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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31 , 2021
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
ALLIANCE RESOURCE PARTNERS, L.P .
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Delaware
73-1564280
(State or Other Jurisdiction of
(IRS Employer Identification No.)
Incorporation or Organization)
1717 South Boulder Avenue, Suite 400 , Tulsa , Oklahoma 74119
(Address of Principal Executive Offices and Zip Code)
( 918 ) 295-7600
(Registrant's Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Trading Symbol
Name of Each Exchange On Which Registered
Common Units representing limited partner interests
ARLP
The NASDAQ Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer ☒
Accelerated Filer ☐
Non-Accelerated Filer ☐
Smaller Reporting Company ☐
(Do not check if smaller reporting company)
Emerging Growth Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 726(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
The aggregate value of the common units held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $ 745,685,497 as of June 30, 2021, the last business day of the registrant's most recently completed second fiscal quarter, based on the reported closing price of the common units as reported on The NASDAQ Stock Market LLC on such date.
As of February 25, 2022, 127,195,219 common units were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
Table of Contents
TABLE OF CONTENTS
Page
PART I
Item 1.
Business
1
Item 1A.
Risk Factors
28
Item 1B.
Unresolved Staff Comments
56
Item 2.
Properties
57
Item 3.
Legal Proceedings
73
Item 4.
Mine Safety Disclosures
74
PART II
Item 5.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
75
Item 6.
[Reserved]
76
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
76
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
95
Item 8.
Financial Statements and Supplementary Data
97
Report of Independent Registered Public Accounting Firm-Grant Thornton LLP (PCAOB ID Number 248)
98
Report of Independent Registered Public Accounting Firm-Ernst & Young LLP (PCAOB ID Number 42)
100
Consolidated Balance Sheets
101
Consolidated Statements of Operations
102
Consolidated Statements of Comprehensive Income (Loss)
103
Consolidated Statements of Cash Flows
104
Consolidated Statement of Partners' Capital
105
Notes to Consolidated Financial Statements
106
1. Organization and Presentation
106
2. Summary of Significant Accounting Policies
107
3. Acquisitions
114
4. Long-Lived Asset Impairments
117
5. Goodwill Impairment
117
6. Inventories
118
7. Property, Plant and Equipment
118
8. Long-Term Debt
119
9. Leases
121
10. Fair Value Measurements
122
11. Partners' Capital
123
12. Variable Interest Entities
123
13. Investments
124
14. Revenue From Contracts With Customers
125
15. Earnings Per Limited Partner Unit
126
16. Employee Benefit Plans
126
17. Common Unit-Based Compensation Plans
129
18. Supplemental Cash Flow Information
132
19. Asset Retirement Obligations
132
20. Accrued Workers' Compensation and Pneumoconiosis Benefits
133
21. Related-Party Transactions
136
22. Commitments and Contingencies
137
23. Concentration of Credit Risk and Major Customers
138
24. Segment Information
138
25. Subsequent Events
141
Supplemental Oil & Gas Reserve Information (Unaudited)
142
Schedule I – Condensed Financial Information of Registrant
148
Item 9.
Changes in and Disagreements with Accountant on Accounting and Financial Disclosure
150
Item 9A.
Controls and Procedures
150
Item 9B.
Other Information
153
PART III
Item 10.
Directors, Executive Officers and Corporate Governance of the General Partner
154
Item 11.
Executive Compensation
159
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
176
Item 13.
Certain Relationships and Related Transactions, and Director Independence
177
Item 14.
Principal Accountant Fees and Services
179
PART IV
Item 15.
Exhibits and Financial Statement Schedules
180
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GLOSSARY OF COAL TERMS
The following are abbreviations and definitions of certain terms used in this document, some of which are defined by authoritative sources and others reflect those we commonly use in the coal industry:
Assigned reserves
Reserves that have been designated for mining by a specific operation
Bituminous coal
Coal used primarily to generate electricity and to make coke for the steel industry with a heat value ranging between 10,500 and 15,500 Btus per pound
Btu
British thermal unit
Compliance coal
Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per MMBtus, requiring no blending or other sulfur dioxide reduction technologies in order to comply with the requirements of the Federal Clean Air Act
Continuous miner
A machine used in underground mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation
High-sulfur coal
Based on market expectations, we classify coal with a sulfur content of greater than 3%
Indicated mineral resource
That part of a mineral resource for which quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. Because an indicated mineral resource has a lower level of confidence than the level of confidence of a measured mineral resource, an indicated mineral resource may only be converted to a probable mineral reserve.
Inferred mineral resource
That part of a mineral resource for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Because an inferred mineral resource has the lowest level of geological confidence of all mineral resources, which prevents the application of the modifying factors in a manner useful for evaluation of economic viability, an inferred mineral resource may not be considered when assessing the economic viability of a mining project, and may not be converted to a mineral reserve.
Long-term contracts
Contracts having a term of one year or greater
Longwall mining
One of two major underground coal mining methods, utilizing specialized equipment to remove nearly all of a coal seam over a very large area
Low-sulfur coal
Based on market expectations, we classify coal with a sulfur content of less than 1.5%
Measured mineral resource
That part of a mineral resource for which quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors, as defined in this section, in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Because a measured mineral resource has a higher level of confidence than the level of confidence of either an indicated mineral resource or an inferred mineral resource, a measured mineral resource may be converted to a proven mineral reserve or to a probable mineral reserve.
Medium-sulfur coal
Based on market expectations, we classify coal with a sulfur content of 1.5% to 3%
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Metallurgical coal
Coal primarily used in the production of steel
Mineral reserve
An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.
Mineral resource
A concentration or occurrence of material of economic interest in or on the Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.
MMBtus
Million British thermal units
Preparation plant
A facility used for crushing, sizing, and washing coal to remove impurities and to prepare it for use by a particular customer
Probable mineral reserve
The economically mineable part of an indicated and, in some cases, a measured mineral resource.
Proven mineral reserve
The economically mineable part of a measured mineral resource and can only result from conversion of a measured mineral resource.
Reclamation
The restoration of land and environmental standards to a mining site after the coal is extracted, including returning the land to its approximate original appearance, restoring topsoil, and planting native grass and ground covers
Room-and-pillar mining
One of two major underground coal mining methods, utilizing continuous miners creating a network of "rooms" within a coal seam, leaving behind "pillars" of coal used to support the roof of a mine
Thermal coal
Coal used primarily in the generation of electricity
Unassigned reserves
Reserves that have not yet been designated for mining by a specific operation
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GLOSSARY OF OIL & GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, some of which are defined by authoritative sources and others reflect those we commonly use in the oil & gas industry:
Basin
A depression in the crust of the Earth, caused by plate tectonic activity and subsidence, in which sediments accumulate. If rich hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, then a petroleum system can develop within the basin. Most basins contain some amount of shale, thus providing opportunities for shale oil & gas exploration and production.
Basis differential
The difference between the spot price of a commodity and the sales price at the delivery point where the commodity is sold
Bbl
Stock tank barrel, or 42 United States gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons
BOE
Barrels of oil equivalent, with six Mcf of natural gas being equivalent to one Bbl of crude oil, condensate, or natural gas liquids
Developed acreage
Acreage allocated or assignable to productive wells
Gross Acres
The total acres in a specified tract in which an owner has a real property interest. For example, an owner who has a 25 percent interest in 100 acres has an ownership interest in 100 gross acres.
MBbls
Thousand barrels of crude oil or other liquid hydrocarbons
MBOE
One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids
Mcf
Thousand cubic feet of natural gas
Mineral Interest
Mineral interests are real-property interests that are typically perpetual and grant ownership to the oil & gas under a tract of land or the rights to explore for, develop, and produce oil & gas on that land or to lease those exploration and development rights to a third party
MMcf
Million cubic feet of natural gas
Net acres
The percentage of total acres an owner owns out of a particular number of acres within a specified tract. For example, an owner who has a 50 percent interest in 100 acres owns 50 net acres.
Net royalty acres
Mineral ownership standardized to a 12.5%, or 1/8 th , royalty interest
NGLs
Natural gas liquids are components of natural gas that are liquid at the surface in field facilities or gas-processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline), and high (liquefied petroleum gas) vapor pressure. Natural gas liquids include propane, butane, pentane, hexane, and heptane, but not methane and ethane since these hydrocarbons need refrigeration to be liquefied. The term is commonly abbreviated as NGL.
Oil & gas
Crude oil, natural gas, and natural gas liquids
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Operator
The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease
Productive well
A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes
Proved developed reserves
Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods
Proved reserves or properties
Proved reserves are those quantities of oil & gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped reserves
Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion
PUDs
Proved undeveloped reserves
Reserves
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.
Royalty interest
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations
Undeveloped acreage
Acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil & gas regardless of whether such acreage contains proved reserves
Unproved reserves or properties
Properties with no proved reserves. We also consider unproved reserves or properties to be defined as the estimated quantities of oil & gas determined based on geological and engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves from being classified as proved.
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FORWARD-LOOKING STATEMENTS
Certain statements and information in this Annual Report on Form 10-K, and certain oral statements made from time to time by our representatives, constitute "forward-looking statements." These statements are based on our beliefs as well as assumptions made by, and information currently available to, us. When used in this document, the words "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "foresee," "may," "outlook," "plan," "project," "potential," "should," "will," "would," and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and reflect our current views with respect to future events and are subject to numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results could differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:
● the severity, magnitude, and duration of the COVID-19 pandemic and the emergence of new virus variants, including impacts of the pandemic and of businesses' and governments' responses to the pandemic, including actions to mitigate its impact and the development of treatments and vaccines, on our operations and personnel, and on demand for coal, oil, and natural gas, the financial condition of our customers and suppliers, available liquidity and capital sources and broader economic disruptions;
● changes in macroeconomic and market conditions and market volatility arising from the COVID-19 pandemic or otherwise, including inflation, changes in coal, oil, natural gas, and natural gas liquids prices, and the impact of such changes and volatility on our financial position;
● decline in the coal industry's share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity and fuels, such as oil & gas, nuclear energy, and renewable fuels;
● changes in global economic and geo-political conditions or in industries in which our customers operate;
● changes in coal prices and/or oil & gas prices, demand and availability which could affect our operating results and cash flows;
● actions of the major oil-producing countries with respect to oil production volumes and prices could have direct and indirect impacts over the near and long term on oil & gas exploration and production operations at the properties in which we hold mineral interests;
● changes in competition in domestic and international coal markets and our ability to respond to such changes;
● potential shut-ins of production by operators of the properties in which we hold mineral interests due to low oil, natural gas, and natural gas liquid prices or the lack of downstream demand or storage capacity;
● risks associated with the expansion of our operations and properties;
● our ability to identify and complete acquisitions;
● dependence on significant customer contracts, including renewing existing contracts upon expiration;
● adjustments made in price, volume, or terms to existing coal supply agreements;
● the effects of and changes in trade, monetary and fiscal policies and laws, including the interest rate policies of the Federal Reserve Board;
● the effects of and changes in taxes or tariffs and other trade measures adopted by the United States and foreign governments;
● legislation, regulations, and court decisions and interpretations thereof, both domestic and foreign, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, hydraulic fracturing, and health care;
● deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;
● investors' and other stakeholders' increasing attention to environmental, social, and governance ("ESG") matters;
● liquidity constraints, including those resulting from any future unavailability of financing;
● customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;
● customer delays, failure to take coal under contracts or defaults in making payments;
● our productivity levels and margins earned on our coal sales;
● disruptions to oil & gas exploration and production operations at the properties in which we hold mineral interests;
● changes in raw material costs, including due to inflationary pressures;
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● changes in our ability to recruit, hire and maintain labor, including, as a result of, the potential impact of government-imposed vaccine mandates;
● our ability to maintain satisfactory relations with our employees;
● increases in labor costs including costs of health insurance and taxes resulting from the Affordable Care Act, adverse changes in work rules, or cash payments or projections associated with workers' compensation claims;
● increases in transportation costs and risk of transportation delays or interruptions;
● operational interruptions due to geologic, permitting, labor, weather, or other factors;
● risks associated with major mine-related accidents, mine fires, mine floods, or other interruptions;
● results of litigation, including claims not yet asserted;
● foreign currency fluctuations that could adversely affect the competitiveness of our coal abroad;
● difficulty maintaining our surety bonds for mine reclamation as well as workers' compensation and black lung benefits;
● difficulty in making accurate assumptions and projections regarding post-mine reclamation as well as pension, black lung benefits, and other post-retirement benefit liabilities;
● uncertainties in estimating and replacing our coal mineral reserves and resources;
● uncertainties in estimating and replacing our oil & gas reserves;
● uncertainties in the amount of oil & gas production due to the level of drilling and completion activity by the operators of our oil & gas properties;
● the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits;
● difficulty obtaining commercial property insurance, and risks associated with our participation in the commercial insurance property program;
● evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches, or other actions;
● difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and
● other factors, including those discussed in "Item 1A. Risk Factors" and "Item 3. Legal Proceedings."
If one or more of these or other risks or uncertainties materialize, or should our underlying assumptions prove incorrect, our actual results could differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind our risk factors and legal proceedings. Known material factors that could cause our actual results to differ from those in the forward-looking statements are described in "Item 1A. Risk Factors" and "Item 3. Legal Proceedings." We disclaim any obligation to update or revise any forward-looking statements or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments unless required by law.
You should consider the information above when reading any forward-looking statements contained in this Annual Report on Form 10-K; other reports filed by us with the U.S. Securities and Exchange Commission ("SEC"); our press releases; our website http://www.arlp.com ; and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.
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Significant Relationships Referenced in this Annual Report
● References to "we," "us," "our", "Partnership" or "ARLP Partnership" mean the business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries.
● References to "ARLP" mean Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis.
● References to "MGP" mean Alliance Resource Management GP, LLC, ARLP's general partner.
● References to "Mr. Craft" mean Joseph W. Craft III, the Chairman, President and Chief Executive Officer of MGP.
● References to "Intermediate Partnership" mean Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P.
● References to "Alliance Coal" mean Alliance Coal, LLC, the holding company for our coal mining operations.
● References to "Alliance Minerals" mean Alliance Minerals, LLC, the holding company for our oil and gas minerals interests.
● References to "Alliance Resource Properties" mean Alliance Resource Properties, LLC, the land holding company for certain of our coal mineral interests, including the subsidiaries of Alliance Resource Properties, LLC.
PART I
ITEM 1. BUSINESS
General
Introduction
We are a diversified natural resource company that generates operating income from the production and marketing of coal and royalty income from coal and oil & gas mineral interests located in strategic producing regions across the United States. The primary focus of our business is to maximize the value of our existing mineral assets, both in the production of coal from our mining assets and the leasing and development of our coal and oil & gas mineral ownership. We believe that our diverse and rich resource base will allow us to continue to create long-term value for unitholders.
We are currently the second-largest coal producer in the eastern United States with seven operating underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia as well as a coal-loading terminal in Indiana on the Ohio River. We manage and report our coal operations under two regions, Illinois Basin and Appalachia. We market our coal production to major domestic and international utilities and industrial users.
We currently own both mineral and royalty interests in approximately 1.5 million gross acres in premier oil & gas producing regions in the United States, primarily the Permian, Anadarko, and Williston Basins. While we own both mineral and royalty interests, we refer to them collectively as mineral interests throughout our discussions of our business as the majority of our holdings are mineral interests. We market our mineral interests for lease to operators in those regions and generate royalty income from the leasing and development of those mineral interests. Reserve additions and the associated cash flows are expected to increase from the development of our existing mineral interests and through acquisitions of additional mineral interests.
We currently have approximately 547.1 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties, which are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. We market our coal mineral reserves and resources to the coal mining operations that are able to access them and generate royalty income from the leasing and development of those coal mineral reserves and resources.
In addition, we develop and market industrial, mining and technology products and services.
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ARLP, a Delaware limited partnership, completed its initial public offering on August 19, 1999, and is listed on the NASDAQ Global Select Market under the ticker symbol "ARLP." We are managed by our sole general partner, MGP, a Delaware limited liability company, which holds a non-economic general partner interest in ARLP.
AllDale I & II Acquisition
On January 3, 2019 (the "Acquisition Date"), we acquired the general partner interests and all of the limited partner interests not owned by Cavalier Minerals JV, LLC ("Cavalier Minerals") in AllDale Minerals, LP ("AllDale I") and AllDale Minerals II, LP ("AllDale II", and collectively with AllDale I, "AllDale I & II") for $176.2 million (the "AllDale Acquisition"). ARLP indirectly owns a 96.0% non-managing member interest and a non-economic managing member interest in Cavalier Minerals. The AllDale Acquisition provided us with diversified exposure to industry-leading operators.
Wing Acquisition
On August 2, 2019, our subsidiary AR Midland, LP ("AR Midland") acquired from Wing Resources LLC and Wing Resources II LLC (collectively, "Wing") approximately 9,000 oil & gas net royalty acres in the Midland Basin for $144.9 million (the "Wing Acquisition"). The Wing Acquisition enhanced our ownership position in the Permian Basin and expanded our exposure to industry-leading operators.
Boulders Acquisition
On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders Royalty Corp. ("Boulders") for a purchase price of $31.0 million (the "Boulders Acquisition"). The Boulders Acquisition also enhanced our ownership position in the Permian Basin.
These acquisitions furthered our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions. See "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions" for more information. We now hold approximately 57,000 net royalty acres in premier oil & gas resource plays.
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The following diagram depicts our simplified organization and ownership as of December 31, 2021:
Our internet address is http://www.arlp.com , and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, Forms 3, 4 and 5 for our Section 16 filers and other documents (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.
The SEC maintains a website that contains reports, proxy and information statements, and other information for issuers, including us. The public can obtain any documents that we file with the SEC at http://www.sec.gov .
Coal Mining Operations
Coal is used primarily for the generation of electric power and production of steel but is also used for chemical, food, and cement processing. We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). We have established long-term relationships with customers through exemplary and consistent performance while operating our mines with an industry-leading safety record.
At December 31, 2021, our mining operations had access to approximately 547.1 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana,
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Kentucky, Maryland, Pennsylvania, and West Virginia. All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties and are currently leased or subleased or held for lease or sublease to our mining operations or others. We produce a diverse range of thermal and metallurgical coal with varying sulfur and heat contents, which enables us to satisfy the broad range of specifications required by our customers. In 2021, we sold 32.3 million tons of coal and produced 32.2 million tons. Of the 32.3 million tons sold, approximately two-thirds was leased from Alliance Resource Properties. The coal we sold in 2021 was approximately 14.2% low-sulfur coal, 50.3% medium-sulfur coal, and 35.5% high-sulfur coal. In 2021, approximately 81.6% of our tons sold were purchased by domestic electric utilities and 12.5% were sold into the international markets through brokered transactions. The balance of our tons sold was to third-party resellers and industrial consumers. For tons sold to domestic electric utilities, 99.9% were sold to utility plants with installed pollution control devices. The Btu content of our coal ranges from 11,450 to 13,200.
The following chart summarizes our coal production by region for the last three years.
Year Ended December 31,
Coal Regions
2021
2020
2019
(tons in millions)
Illinois Basin
22.2
17.9
29.5
Appalachia
10.0
9.1
10.5
Total
32.2
27.0
40.0
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The following map shows the location of our coal mining operations:
Illinois Basin Operations:
4. WARRIOR COMPLEX
7. METTIKI COMPLEX
1. GIBSON COMPLEX
Warrior Mine
Mountain View Mine
Gibson South Mine
Mining Type: Underground
Mining Type: Underground
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Method: Continuous
Mining Method: Longwall
Mining Method: Continuous
Miner
& Continuous Miner
Miner
Coal Type: Medium/High-Sulfur
Coal Type: Low/Medium
Coal Type: Low/Medium-Sulfur
Transportation: Barge, Railroad,
Sulfur - Metallurgical
Transportation: Barge, Railroad
& Truck
Transportation: Railroad
& Truck
& Truck
5. MOUNT VERNON
2. HAMILTON COMPLEX
TRANSFER TERMINAL
8. TUNNEL RIDGE COMPLEX
Hamilton Mine
Rail or Truck to Ohio River Barge
Tunnel Ridge Mine
Mining Type: Underground
Transloading Facility
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Method: Longwall
Appalachian Operations:
Mining Method: Longwall
& Continuous Miner
6. MC MINING COMPLEX
& Continuous Miner
Coal Type: Medium/High-Sulfur
Excel Mine No. 5
Coal Type: Medium/High-Sulfur
Transportation: Barge, Railroad
Mining Type: Underground
Transportation: Barge & Railroad
& Truck
Mining Access: Slope & Shaft
Mining Method: Continuous
3. RIVER VIEW COMPLEX
Miner
River View Mine
Coal Type: Low-Sulfur
Mining Type: Underground
Transportation: Barge, Railroad,
Mining Access: Slope & Shaft
& Truck
Mining Method: Continuous
Miner
Coal Type: Medium/High-Sulfur
Transportation: Barge & Truck
We lease most of our coal mineral reserves and resources from Alliance Resource Properties or private parties 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 mineral reserve or resource area. These leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun.
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These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.
Illinois Basin Operations
Our Illinois Basin mining operations are located in western Kentucky, southern Illinois, and southern Indiana. As of December 31, 2021, we have 1,862 employees, and we operate four active mining complexes in the Illinois Basin.
Gibson Complex. Our subsidiary, Gibson County Coal, LLC ("Gibson County Coal"), operates the Gibson South mine, located near the city of Princeton in Gibson County, Indiana. The Gibson South mine is an underground mine and utilizes continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal. The Gibson South mine's preparation plant has throughput capacity of 1,800 tons of raw coal per hour. Production from the Gibson South mine is shipped by truck or transported by rail on the CSX Transportation, Inc. ("CSX") or Norfolk Southern Railway Company ("NS") railroads from our rail loadout facility directly to customers or various transloading facilities, including our Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") transloading facility, for barge delivery. Production from the mine began in April 2014.
Hamilton Complex. Our subsidiary, Hamilton County Coal, LLC ("Hamilton"), operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois. The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal, longwall mining began in October 2014 and we acquired complete ownership and control in 2015. Hamilton's preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Hamilton has the ability to ship production from the Hamilton mine via the CSX, Evansville Western Railway, or NS rail directly to customers or various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries.
River View Complex. Our subsidiary, River View Coal, LLC ("River View"), operates the River View mine, which is located in Union County, Kentucky and is currently the largest room-and-pillar coal mine in the United States. The River View mine began (multi-seam) production in 2009 and utilizes continuous mining units to produce medium/high-sulfur coal. River View's preparation plant has throughput capacity of 2,700 tons of raw coal per hour. Coal produced from the River View mine is transported by overland belt to a barge loading facility on the Ohio River.
Warrior Complex . Our subsidiary, Warrior Coal, LLC ("Warrior"), operates an underground mining complex located near the city of Madisonville in Hopkins County, Kentucky. The Warrior complex was opened in 1985, and we acquired it in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques to produce medium/high-sulfur coal. Warrior's preparation plant has throughput capacity of 1,200 tons of raw coal per hour. Warrior's production is shipped via the CSX or Paducah & Louisville Railway, Inc. ("PAL") railroads or by truck directly to customers or potentially to various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries.
Mt. Vernon Transfer Terminal, LLC. Our subsidiary, Mt. Vernon, leases land and operates a coal-loading terminal on the Ohio River at Mt. Vernon, Indiana. Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 200,000 tons. In 2021, the terminal loaded approximately 1.4 million tons for customers of Gibson County Coal and Hamilton.
Appalachian Operations
Our Appalachian mining operations are located in eastern Kentucky, Maryland, and West Virginia. As of December 31, 2021, we had 895 employees, and we operate three mining complexes in Appalachia.
MC Mining Complex. The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky. We acquired the original mine in 1989. Our subsidiary, MC Mining, LLC ("MC Mining"), through our subsidiary, Excel Mining, LLC ("Excel") operates the Excel Mine No. 5. Excel completed development of Mine No. 5 in May 2020 and transitioned its employees and equipment from Mine No. 4 in July 2020. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The existing preparation plant, which has throughput capacity of 1,000 tons of raw coal per hour, is utilized by Mine No. 5. Substantially all of the coal produced at MC Mining in 2021 met or exceeded the compliance requirements of Phase II of the Federal Clean Air Act ("CAA") (see "—Environmental, Health and Safety Regulations— Air Emissions " below). Coal produced from the mine
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is shipped via the CSX railroad directly to customers or various transloading facilities on the Ohio River for barge deliveries, or by truck directly to customers or to various docks on the Big Sandy River for barge deliveries.
Mettiki Complex. The Mettiki Complex ("Mettiki") comprises the Mountain View mine located in Tucker County, West Virginia operated by our subsidiary Mettiki Coal (WV), LLC ("Mettiki (WV)") and a preparation plant located near the city of Oakland in Garrett County, Maryland operated by our subsidiary Mettiki Coal, LLC ("Mettiki (MD)"). Mettiki (WV) and began longwall mining in November 2006. The Mountain View mine produces medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical coal market or otherwise, or directly to the coal blending facility at the Virginia Electric and Power Company Mt. Storm Power Station. The Mettiki (MD) preparation plant has throughput capacity of 1,350 tons of raw coal per hour. Coal processed at the preparation plant can be trucked to the blending facility at Mt. Storm or shipped via the CSX railroad, which provides the opportunity to ship into the domestic and international thermal and metallurgical coal markets.
Tunnel Ridge Complex. Our subsidiary, Tunnel Ridge, LLC ("Tunnel Ridge"), operates the Tunnel Ridge mine, an underground longwall mine in the Pittsburgh No. 8 coal seam, located near Wheeling, West Virginia. Longwall mining operations began at Tunnel Ridge in May 2012. The Tunnel Ridge preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Coal produced from the Tunnel Ridge mine is a medium/high-sulfur coal and is transported by conveyor belt to a barge loading facility on the Ohio River. Tunnel Ridge has the ability through a third-party facility to transload coal from barges for rail shipment on the Wheeling and Lake Erie Railway with connections to the CSX and the NS railroads.
Coal Marketing and Sales
We sell coal to an established customer base through opportunities as a result of existing business relationships or through formal bidding processes. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. These arrangements are mutually beneficial to our customers and us in that they provide greater predictability of sales volumes and sales prices. Although some utility customers have appeared to favor a shorter-term contracting strategy, in 2021 approximately 77.9% and 75.1% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2021 to 2026. As of February 11, 2022, our nominal commitment under contract was approximately 33.1 million tons for delivery in 2022. The contractual time commitments for customers to nominate future purchase volumes under these contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity.
The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among other factors, price adjustment features, price and contract reopener terms, permitted sources of supply, force majeure provisions, and coal qualities and quantities. A portion of our long-term contracts is subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both. These provisions, however, may not assure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, lead to the early termination of a contract. Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract. The long-term contracts typically stipulate procedures for transportation of coal, quality control, sampling, and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility, and other qualities. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits. Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include but are not limited to unexpected significant geological conditions and weather events that may disrupt transportation. Depending on the language of the contract, some contracts may terminate upon an event of force majeure that extends for a certain period.
The international coal market has been a part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America. Our sales into the international coal market are considered exports and are made
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through brokered transactions. During the years ended December 31, 2021, 2020, and 2019, export tons represented approximately 12.5%, 3.3%, and 17.9% of tons sold, respectively. Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known.
Reliance on Major Customers
In 2021, we derived more than 10% of our total revenue from Louisville Gas and Electric Company. We did not derive 10% or more of our revenues from any other single customer. For more information about this customer, please read "Item 8. Financial Statement and Supplemental Data—Note 23 – Concentration of Credit Risk and Major Customers."
Coal Competition
The coal industry is intensely competitive. The most important factors on which we compete are coal price, coal quality (including sulfur and heat content), reliability and diversity of supply, and transportation costs from the mine to the customer. We are currently the second-largest coal producer in the eastern United States. Our principal competitors include American Consolidated Natural Resources Inc., CONSOL Energy, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy LP, and Peabody Energy Corporation. We also compete directly with smaller producers in the Illinois Basin and Appalachian regions. In addition, we seek to export a portion of our coal into the international coal markets and we compete with companies that produce coal from one or more foreign countries.
The prices we are able to obtain for our export coal have been influenced by a number of factors, such as global economic conditions, weather patterns, and global supply and demand, among others. The prices we are able to obtain for our domestic sales of coal are primarily linked to coal consumption patterns of domestic electricity-generating utilities, which in turn are influenced by economic activity, government regulations, weather, and technological developments, as well as the location, quality, price and availability of competing sources of fuel and alternative energy sources such as natural gas, nuclear energy, petroleum and renewable energy sources for electrical power generation.
For additional information, please see "Item 1A. Risk Factors."
Coal Transportation
Our coal is transported from our mining complexes to our customers by barge, rail, and truck reflecting important flexibility advantages in supplying our customers. Depending on the proximity of the customer to the mining complex and the transportation available for delivering coal to that customer, transportation costs can be a substantial part of the total delivered cost of a customer's coal. As a consequence, the availability and cost of transportation constitute important factors in the marketability of coal. We believe our mines are located in favorable geographic locations that minimize transportation costs for our customers, and in many cases, we can accommodate multiple transportation options. Our customers typically negotiate and pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry. Approximately 53.1% of our 2021 sales volume was initially shipped from the mining complexes by barge, 31.9% was shipped from the mining complexes by rail, and 15.0% was shipped from the mining complexes by truck. The practices of, rates set by and capacity availability of, the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mining complex. With respect to our export volumes from the United States to other countries, we generally sell coal to our customers at an export terminal in the United States and we are responsible for the cost of transporting coal to the export terminals. Our export customers generally negotiate and pay for ocean vessel transportation.
Mineral Interest Activities
Our mineral interest activities include both oil & gas and coal mineral interests. Our oil & gas mineral interest business includes all activities related to the oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interest in AllDale Minerals III, L.P. ("AllDale III"). AR Midland acquired its mineral interests in the Wing and Boulders Acquisitions. Our mineral interests are primarily located on private lands in three basins, which are also our areas of focus for future development by operators. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) Basins. Our developed and undeveloped net acres standardized to a 1/8th royalty equate to approximately 57,000 oil & gas net royalty acres, including 3,976 oil & gas net royalty acres owned through our equity interest in AllDale III.
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Our coal mineral interests include all of our measured, indicated and inferred coal mineral resources and 422.9 million tons of coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. Our coal mineral interests are located in both the Illinois Basin and the Appalachia Basin.
Oil & Gas Royalties
When our oil & gas mineral interests are leased, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to receive a fixed percentage of the revenue or production from the oil & gas produced from the acreage underlying our interests, free of lease operating expenses and capital costs. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities, or by making an extension payment. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. As an owner of mineral interests, we incur the initial cost to acquire our interests but thereafter only incur our proportionate share of production and ad valorem taxes. Unlike owners of working interests in oil & gas properties, we are not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs associated with oil & gas production.
The following chart summarizes the production of our oil & gas mineral interests for the year ended December 31, 2021, 2020, and 2019:
Year Ended December 31,
2021
2020
2019
Production:
Oil (MBbls)
825
948
741
Natural gas (MMcf)
3,490
3,635
3,664
Natural gas liquids (MBbls)
357
337
364
BOE (MBbls)
1,764
1,892
1,716
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The following map shows the location of our oil & gas mineral interests:
In 2014, we began to invest in oil & gas mineral interests in some of the nation's premier oil-rich basins. Beginning in 2019, we transitioned from a passive investor in mineral interests to an active and material participant in oil & gas minerals.
Permian Basin—Delaware and Midland Basins
The Permian Basin ranges from West Texas into southeastern New Mexico and is currently the most active area for horizontal drilling in the United States. The Permian Basin is further subdivided into the Delaware Basin in the west and the Midland Basin in the east. Based on geologic data and the ongoing development by operators, our mineral interests in the Permian Basin contain multiple producing zones of economic horizontal development including but not limited to the Wolfcamp, Spraberry, and Bone Spring formations. Our recent purchase of acreage located entirely in the Permian Basin through the Boulders Acquisition demonstrates our commitment to continued acquisition of mineral interests in the nation's highest growth oil & gas plays.
Anadarko Basin—SCOOP and STACK Plays
The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens, and McClain Counties. Based on geologic data and the ongoing development by operators, our mineral interests in the SCOOP play contain multiple producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney, and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend, Anadarko Basin, Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo, and Blaine Counties. Based on geologic data and the ongoing development by operators,
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our mineral interests in the STACK play contain multiple producing zones of economic horizontal development including but not limited to the Meramec and Woodford formations.
Williston Basin—Bakken
The Williston Basin stretches from western North Dakota into eastern Montana. Based on geologic data and ongoing development by operators, our mineral interests contain multiple producing zones of economic horizontal development including the Bakken and Three Forks formations.
Other
Our other interests are comprised primarily of mineral interests owned in the Appalachia Basin that stretches throughout most of Ohio, West Virginia, Pennsylvania, and extends into other states. The Appalachia Basin's most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the interests held in the Appalachia Basin, we own a small number of mineral interests in the Tuscaloosa Marine Shale play in Mississippi. AllDale III also owns mineral interests in the Haynesville Shale formation located in northwest Louisiana.
Coal Royalties
Our Coal Royalties segment includes approximately 422.9 million tons of proven and probable reserves and all of the 1.17 billion tons of our measured, indicated and inferred coal mineral resources. Our coal mineral reserves and resources are located in the Appalachia and Illinois Basins in the United States. We lease our reserves and resources to our mining complexes under long-term leases. Approximately two-thirds of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms.
Under our standard royalty lease, we grant the lessees the right to mine and sell our reserves and resources in exchange for royalty payments based on a percentage of the sale price or a fixed royalty per ton of coal mined and sold. Lessees calculate royalty payments due to us and are required to report tons of coal mined and sold as well as the sales prices of the extracted coal.
The following chart summarizes the coal sales associated with our coal mineral interests for the years ended December 31, 2021, 2020 and 2019.
Year Ended December 31,
Coal Regions
2021
2020
2019
(tons in millions)
Illinois Basin
18.9
16.6
20.9
Appalachia
1.3
2.3
2.1
Total
20.2
18.9
23.0
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The following map shows the location of our coal mineral interests:
Illinois Basin:
4. WARRIOR
7. SEBREE SOUTH
1. GIBSON
Mining Type: Underground
Mining Type: Underground
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Method: Continuous
Mining Method: Continuous
Mining Method: Continuous
Miner
Miner
Miner
Coal Type: Medium/High-Sulfur
Coal Type: Medium/High-Sulfur
Coal Type: Low/Medium-Sulfur
Transportation: Barge, Railroad,
Transportation: Barge & Truck
Transportation: Barge, Railroad
& Truck
& Truck
5. HENDERSON/UNION
Appalachian Basin:
2. HAMILTON
Mining Type: Underground
8. MOUNTAIN VIEW
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Continuous Miner
Mining Access: Slope & Shaft
Mining Method: Longwall
Coal Type: Medium/High-Sulfur
Mining Method: Longwall
& Continuous Miner
Transportation: Barge & Truck
& Continuous Miner
Coal Type: Medium/High-Sulfur
Coal Type: Low/Medium
Transportation: Barge, Railroad
6. DOTIKI
Sulfur - Metallurgical
& Truck
Mining Type: Underground
Transportation: Railroad
Mining Access: Slope & Shaft
& Truck
3. RIVER VIEW
Mining Method: Continuous
Mining Type: Underground
Miner
9. PENN RIDGE
Mining Access: Slope & Shaft
Coal Type: Medium/High-Sulfur
Mining Type: Underground
Mining Method: Continuous
Transportation: Barge, Railroad
Mining Access: Slope & Shaft
Miner
& Truck
Mining Method: Longwall
Coal Type: Medium/High-Sulfur
& Continuous Miner
Transportation: Barge & Truck
Coal Type: High-Sulfur
Transportation: Barge & Railroad
& Continuous Miner
Illinois Basin
Our land holding company, Alliance Resource Properties, either directly or through its subsidiaries, holds coal mineral reserves and resources in the following counties in the Illinois Basin:
● Hopkins County, Kentucky
● Webster County, Kentucky
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● Union County, Kentucky
● Henderson County, Kentucky
● Hamilton County, Illinois
● Jefferson County, Illinois
● Gibson County, Indiana
Alliance Resource Properties leases some of the reserves and resources in Union and Henderson Counties from WKY CoalPlay, LLC ("WKY CoalPlay") or its subsidiaries, which are related parties. For more information about our WKY CoalPlay transactions, please read "Item 8. Financial Statements and Supplementary Data—Note 21 – Related Party Transactions."
Gibson . Approximately 6.5 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Gibson County Coal.
Hamilton. Approximately 128.5 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Hamilton.
River View . Approximately 206.8 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, River View.
Warrior . Approximately 77.1 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Warrior.
Dotiki . Approximately 76.0 million tons of these resources are currently leased/subleased or held for lease/sublease to our subsidiary, Webster County Coal, LLC ("Webster County Coal").
Sebree South . Approximately 43.5 million tons of these resources are currently leased/subleased to our subsidiary, Sebree Mining, LLC ("Sebree").
Other . Alliance Resource Properties holds miscellaneous non-strategic coal properties in the Illinois Basin that are not under lease or currently anticipated to be leased to any of our operating companies. Leasing of these properties is dependent upon further development by our operating subsidiaries or third-party mining complexes, which is regulatory and market dependent.
Appalachia Basin
Mountain View. Alliance Resource Properties holds coal mineral reserves and resources in Grant County and Tucker County, West Virginia, estimated to include approximately 10.7 million tons of medium sulfur coal, all of which is currently leased/subleased or held for lease/sublease to our subsidiary, Mettiki (WV).
Penn Ridge Resources. Alliance Resource Properties holds coal mineral resources in Washington County, Pennsylvania, (the "Penn Ridge Resources") estimated to include approximately 78.0 million tons of measured, indicated and inferred high-sulfur coal in the Pittsburgh No. 8 seam. These resources are near our Tunnel Ridge mining complex but are not currently leased. Leasing of these resources is dependent upon further development by Tunnel Ridge or third-party mining complexes, which is regulatory and market dependent.
Other. Alliance Resource Properties holds miscellaneous non-strategic coal properties in the Appalachia Basin that are not under lease. Leasing of these properties is dependent upon mining complexes nearby deciding to develop a project, which is regulatory and market dependent.
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Minerals Interest Competition
Many companies are engaged in the search for and the acquisition of coal and oil & natural gas interests, and there is a limited supply of desirable coal and oil & natural gas reserves. Our ability to acquire additional oil & gas mineral interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors not only own and acquire oil & gas mineral interests but also explore for and produce oil & gas and, in some cases, conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, because we have fewer financial and human resources than many companies in the oil & gas industry, we may be at a disadvantage in bidding for oil & gas properties. Further, oil & gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternative fuels and other forms of energy, may affect the demand for oil & gas.
We also face competition from land companies, coal producers and international steel companies in purchasing coal mineral reserves and resources as well as royalty producing properties. Numerous producers in the coal industry make coal marketing very competitive. Our mining complexes in which we lease our reserves compete with coal producers in various regions of the United States for domestic sales on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer, and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as government regulations, technological developments, and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar, and hydroelectric power.
For additional information, please see "Item 1A. Risk Factors".
Minerals Interest - Seasonal Nature of Business
Generally, demand for oil increases during the summer months and decreases during the winter months while demand for natural gas increases during the winter and summer months and decreases during the spring and fall months. Certain buyers of natural gas use natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil & gas operations in a portion of our leasing areas. These seasonal anomalies can pose challenges for our operators in meeting well-drilling objectives and can increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.
Other Operations
Coal Brokerage
As markets allow, Alliance Coal buys coal from our mining operations and outside producers principally throughout the eastern United States, which we then resell. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal.
Matrix Group
Our subsidiaries, Matrix Design Group, LLC ("Matrix Design") and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD, and Alliance Design Group, LLC ("Alliance Design") (collectively the Matrix Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties. Matrix Group's products and services include data network, communication and tracking systems, mining proximity detection systems, industrial collision avoidance systems, and data and analytics software. We acquired Matrix Design in September 2006.
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Additional Services
We develop and market additional services to establish ourselves as the supplier of choice for our customers. Historically, and in 2021, outside revenues from these services were immaterial.
Environmental, Health, and Safety Regulations
Our coal operations, and those of the operators on the properties in which we hold oil & gas mineral interests, are subject to extensive regulation by federal, state, and local authorities on matters such as:
● employee health and safety;
● permits and other licensing requirements for mining or exploration and production activities;
● 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 that could limit or prohibit mining or exploration and production activities;
● restrict the types, quantities, and concentration of materials that can be released into the environment in the performance of mining or exploration and production activities;
● initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of waste ponds, mining areas, drilling pits, and plugging of abandoned wells;
● 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
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. The regulatory burden on fossil-fuel industries increases the cost of doing business and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators’ costs and adversely affect our performance.
In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected the 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, our customers' ability to use coal, or the value of or amount of royalties received from our mineral interests. For more information, please see the risk factors described in "Item 1A. Risk Factors" below.
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 Mine Safety and Health Administration ("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 promptly remediate any identified condition. 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.
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 estimated costs and timing assumptions 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.
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Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations. 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. These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these 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 challenges, including by the public. 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. Although like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.
Mine Health and Safety Laws
The operation of our mines is subject to the Federal Mine Safety and Health Act of 1977 ("FMSHA"), and regulations adopted pursuant thereto. FMSHA imposes 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 United States for the 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.
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 the imposition of a civil penalty for each cited violation. Negligence and gravity assessments, along with 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. 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 ("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.
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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 to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors." The final rule implemented 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. MSHA has published a request for information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, which is currently set to close on July 9, 2022. It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.
MSHA has also published, and may continue to publish, various proposed rules or requests for information, which may result in additional rulemakings. For example:
● In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that closed in November 2016 for this matter, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's 2016 request for information. The comment period for the request for information for the Diesel Exhaust Partnership closed in September 2020.
● In August 2019, MSHA published a request for information regarding exposure to respirable crystalline silica, most commonly found in the mining environment through quartz. The request solicited information regarding best practices to protect miners’ health from exposure to quartz, including examination of a new reduced permissible exposure limit, potential new or developing protective technologies, and/or technical and educational assistance. The comment period for the request for information closed in October 2019.
● In November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments. The comment period for the proposed rule closed in December 2020.
● In September 2021, MSHA published a proposed rule requiring that mine operators employing six or more miners develop and implement a written safety program for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface Mobile Equipment). The comment period for the proposed rule closed in November 2021. However, MHSA reopened the rulemaking record for additional public comments. A virtual hearing was held in January 2022 and the comment period closed in February 2022.
It is uncertain whether MSHA will present a final rule addressing any of the above issues or any of the other various proposed rules or requests for information or whether any such rule would have material impacts on our operations or our costs of operation.
Subsequent to the 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.
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 federal and state safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.
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Black Lung Benefits Act
The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 ("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, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses where no responsible coal mine operator has been identified for claims. The coal we sell into international markets is generally not subject to this tax. 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. Effective January 1, 2019, the trust fund was funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price. Effective January 1, 2020, the trust fund was funded by an excise tax on coal sold of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. Effective January 1, 2022, the trust fund is funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price. It is uncertain as to whether the excise tax rates will be adjusted in the future or whether any such modifications would be retroactive.
Workers ' Compensation and Black Lung
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. We generally self-insure this potential expense using our actuary estimates of the cost of present and future claims. In addition, coal mining companies are subject to federal legislation and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker's pneumoconiosis, or black lung. We also provide for these claims through self-insurance programs. Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis benefits obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents, and discount rates. 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. "
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 refile 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 have caused a significant increase in our costs expended in association with the federal black lung program.
Surface Mining Control and Reclamation Act
The Federal Surface Mining Control and Reclamation Act of 1977 ("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.
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.
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In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The fee expired on September 30, 2021, and was reauthorized through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021. The fee, as reauthorized, for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30, 2034. We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Please read "Item 8. Financial Statements and Supplementary Data—Note 18 – Asset Retirement Obligations." 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.
In April 2015, the U.S. Environmental Protection Agency ("EPA") finalized rules on coal combustion residuals ("CCRs"); however, the final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites. The Federal Office of Surface Mining ("OSM") has announced its 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 potentially could 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 and in some cases it is unclear what level of collateral will be required. 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 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 federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow. For additional information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources— Cash Requirements ."
Air Emissions
The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining, as well as oil & gas, operations. The CAA imposes 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 federal and state 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 ("SIPs"), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition, and results of operations.
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In addition to the greenhouse gas ("GHG") issues discussed below, the air emissions programs that may affect our operations or the operations of those on the properties in which we hold mineral interests, 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. In 2021, we sold 81.6% of our total tons to electric utilities in the United States, substantially all of which was sold to utility plants with installed pollution control devices. These requirements would not be supplanted by a replacement rule for the Clean Air Interstate Rule ("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 ("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. CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers. The full impacts of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.
● 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 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. In subsequent litigation, the U.S. Supreme Court struck down the MATS rule based on the EPA's failure to take costs into consideration. The D.C. Circuit Court allowed the current rule to stay in place until the EPA issued a new finding. In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule. In April 2017, the D.C Circuit Court of Appeals granted the EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding. In December 2018, the EPA issued a proposed Supplemental Cost Finding, as well as the CAA required "risk and technology review." In May 2020, EPA issued a final rule that reverses the Agency’s prior determination from 2000 and 2016 that it was "appropriate and necessary" to regulate hazardous air pollutants from coal-fueled Electric Generating Units ("EGUs") under the MATS rule. However, in February 2022, EPA published a proposed rule proposing to revoke the May 2020 finding. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit, the MATS rule has forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule. 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.
● The EPA is required by the CAA to periodically reevaluate the available health effects information to determine whether the National Ambient Air Quality Standards ("NAAQS") should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter ("PM"), 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
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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. In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide. In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone; however, various entities filed litigation against one or both of these rulemakings, and the Biden Administration has announced that it will reconsider and potentially revise the NAAQS and consider instituting a more stringent standard. 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 could indirectly reduce the demand for coal. Separately, the implementation of new standards by states has the potential to delay or otherwise impact oil & gas production activities, which could reduce the profitability of our mineral interests.
● 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 prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through Federal Implementation Plans ("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. In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs, which was followed by a supplemental memorandum in July 2021 for SIPs for the second implementation period.
● The EPA's new source review ("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. In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions. The EPA has announced that it will review the NSR program. Depending on the ultimate resolution of the EPA's litigation and review, demand for coal could be affected.
● The EPA’s New Source Performance Standards ("NSPS") under the CAA require the reduction of certain pollutants and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions." These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels. Although the Trump Administration revised prior regulations in September 2020 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. Additionally, in November 2021, EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for GHG and volatile organic compound ("VOC") emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of final rule by the end of the year. Oil & gas production on the properties in which we hold mineral interests could be adversely affected to the extent any final rule imposes increased operating costs on the oil & gas industry.
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GHG Emissions
Combustion of fossil fuels, such as the coal we produce and the oil & gas produced from our mineral interests, results in the emission of GHGs, such as carbon dioxide and methane. 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 United States treaty commitments, new domestic legislation, or regulation by the EPA. Although no comprehensive climate change regulation has been adopted at the federal level in the United States, President Biden announced that climate change will be a focus of his administration. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets. These commitments could further reduce demand and prices for fossil fuels. Although the United States had withdrawn from the Paris Agreement, President Biden recommitted the United States in February 2021 and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered again in Glasgow in November 2021 at the 26th Conference to the Parties ("COP26") during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. Also at COP26, more than forty countries pledged to phase out coal, although the United States did not sign the pledge. The impact of these actions remain unclear at this time. Moreover, 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. Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels. 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 that the EPA has authority to regulate GHG emissions. Although the U.S. Supreme Court's holding did not expressly involve the EPA's authority to regulate GHG emissions from stationary sources, such as coal-fueled power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare. Several rulemakings have been issued under the NSPS that constrain the GHG emissions of fossil-fuel-fired power plants. In January 2021, the EPA published a final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations. However, this finding also excludes several sectors and may, therefore, be subject to revision, and future implementation of the NSPS is uncertain at this time.
In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the U.S. Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision. Then, in October 2017 the EPA proposed to repeal the CPP. The EPA subsequently proposed the Affordable Clean Energy ("ACE") rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction". The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals; and, the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. In June 2019, the EPA published the final repeal of the CPP and promulgation of the ACE rule. The EPA's attempts to replace the CPP with the ACE rule are currently subject to litigation, and on January 19, 2021, the Circuit Court struck down the ACE rule, though the case is not yet final with oral arguments scheduled before the U.S. Supreme Court on February 28, 2022. We cannot predict the outcome of the litigation.
Notwithstanding the ACE rule, 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 not currently adopted 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.
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Substantial limitations on GHG emissions could adversely affect demand for the coal we produce or the oil & gas produced from our mineral interests.
There have been numerous protests and challenges to the permitting of new fossil-fuel infrastructure, including power plants and pipelines, 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. Several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio. Other states may adopt similar requirements, and federal legislation is a possibility in this area. In December 2021, President Biden issued an executive order setting a goal for a carbon pollution-free electricity sector across the country by 2035. To the extent these requirements affect our current and prospective customers or those of our mineral interest producers, they may reduce the demand for fossil-fuel energy and may affect the long-term demand for our coal and the oil & gas producers from the properties in which we hold mineral interests. Finally, while the U.S. Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern. For more information, see our risk factor titled "We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change."
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 ("NEPA"). These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In July 2020, the Council on Environmental Quality ("CEQ") finalized revisions to NEPA regulations that clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA. However, in October 2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions. A final rule is expected in 2022.
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 Northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"), calling for the 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. Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers, while Virginia has withdrawn from RGGI via executive order by its governor.
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, though only California and certain Canadian provinces are currently active participants in the Western Climate Initiative. These regional efforts will likely continue based on current trends and concerns related to the reduction of GHG emissions.
It is possible that future international, federal, and state initiatives to control GHG emissions could result in increased costs associated with fossil-fuel 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 fossil-fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, or those of the operators of our mineral interests, which could have a material adverse effect on our business, financial condition, and results of operations. Finally, activists may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts. For more information, see our Risk Factor titled "Our operations are subject to a series of risks resulting from climate change."
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Water Discharge
The Federal Clean Water Act ("CWA") and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact such 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. For more information about asset retirement obligations, please read "Item 8. Financial Statements and Supplementary Data—Note 18 - Asset Retirement Obligations." 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.
For us or the operators of the properties in which we hold oil & gas mineral interests to conduct certain activities, an operator may need to obtain a permit for the discharge of fill material from the U.S. Army Corps of Engineers ("Corps of Engineers") and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA. 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.
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 which veto was subsequently upheld by the D.C. Circuit Court of Appeals in 2013. 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 ("TMDL") regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody 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.
Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings have been subject to substantial litigation. On August 30, 2021, the US District Court for Arizona granted a request for voluntary remand of the EPA's rule. The Biden Administration has announced plans to establish its own definition of "waters of the United States" ("WOTUS"). Most recently, the EPA and the Corps of Engineers published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the CWA and the definition of WOTUS. To the extent any decision expands the scope of the EPA and the Corps of Engineers’ jurisdiction under the CWA, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.
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Hazardous Substances and Wastes
The Federal Comprehensive Environmental Response, Compensation and Liability Act ("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 owner or operator 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.
The Federal Resource Conservation and Recovery Act ("RCRA") and analogous state laws impose requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-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. Similarly, most wastes associated with the exploration, development, and production of oil & gas are exempt from regulation as hazardous wastes under RCRA, though these wastes typically constitute "solid wastes" that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require such wastes to become subject to more stringent storage, handling, treatment, or disposal requirements, which could impose significant additional costs on the operators of the properties in which we own oil & gas mineral interests. 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, such costs are not believed to have a material impact on our operations.
RCRA impacts the coal industry in particular because it regulates the disposal of certain coal combustion by-products ("CCB"). On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as "non-hazardous" waste and avoids the stricter, more costly, regulations under RCRA's "hazardous" waste rules. While the 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. The CCB rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances. Certain provisions of the revised CCB rule were vacated by the D.C. Circuit in 2018. The EPA is expected to finalize additional rules addressing those specific provisions in 2022 and 2023. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities who sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA is requiring the remaining facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022. The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. The combined effect of the CCB rules and ELG regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.
On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards ("ELG"), 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 the CCB and ELG 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. In November 2019, the EPA proposed revisions to the 2015 ELG rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs. In October 2020, EPA published a final rule. In August 2021, EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits. EPA expects to issue a proposed rule for public comment in fall 2022. It is unclear what impact these regulations will have on the market for our products.
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Endangered Species Act
The federal Endangered Species Act ("ESA") and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the "USFWS") works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil & gas exploration and production activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration; namely, the USFWS plans to rescind the 2018 rule that revised the process for designating critical habitat for threatened and endangered species under the ESA and second, alongside the National Marine Fisheries Service, the USFWS proposes to rescind the 2020 regulatory definition of "habitat." Final action on these proposed rules will occur in 2022. If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered or to redesignate a species from threatened to endangered, we or the operators of the properties in which we hold oil & gas mineral interests could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.
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 regulations. 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.
Human Capital
To conduct our operations, as of December 31, 2021, we employed 2,990 full-time employees, including 2,604 employees involved in active coal mining operations, 219 employees in other operations, and 167 corporate employees. Our workforce is entirely union-free. Our typical employee has approximately eight years of experience with the Partnership and more than 50% of all employees remain employed for more than five years.
To attract and retain the most qualified personnel across all functions of our business we offer competitive compensation packages. In making decisions regarding employee compensation, we review current compensation levels for each position within other companies in the coal industry and other peers and use our discretion to determine an appropriate total compensation package, which generally includes some combination of base salary, possible incentive compensation, medical, dental and life insurance benefits and participation in our profit sharing and savings plan. Depending on the position and employer, incentive compensation bonuses can be based on production and safety goals at a specific coal operation or broader performance goals across the Partnership, among other factors. We intend for each employee's total compensation to be competitive in the marketplace.
Workplace safety is fundamental to our culture. By providing a work environment that rewards safety and encourages employee participation in the safety process, we strive to be the leader in safety performance in the coal mining industry. We are focused on improving employee safety through regular training and continuous monitoring of our progress, including through the mining industry standard of "non-fatal days lost," or "NFDL," which reflects both the frequency and severity of injuries incurred. Our NFDL rating of 3.26 for the year ended December 31, 2021, was below the preliminary industry average over the same time period. In addition, we collected over 13,000 respirable dust samples of the mining environment where our miners regularly work and travel. The average concentration of those samples was 59% below the regulatory standard. We are also regularly inspected by MSHA. For more information about citations or orders for violations of standards under the FMSHA, as amended by the MINER Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.
We are focused on the health of our employees. In addition to providing medical, dental, and vision insurance with no out-of-pocket premiums for our employees, we also provide on-site medical clinics to provide medical services to our employees and their families. Furthermore, at each of our coal operations and corporate offices, we provide a human resource representative to assist employees with various human resource matters. The Partnership also administers our medical plan, which allows us to control costs and work directly on behalf of our employees with health care providers enabling us in part, to continue providing health benefits with no out-of-pocket premiums for our employees.
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We also have developed steps to enhance protections from, and minimize risks associated with, the spread of COVID-19, as needed. Such steps include or have included, without limitation, staggering shift patterns to promote social distancing, enhanced cleaning procedures, promotion of recommended hygiene practices, limited workplace access, "touch-free" check-in/check-out stations, wellness screening at mine locations, and requiring face coverings where appropriate.
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ITEM 1A. RISK FACTORS
Summary Risk Factors
Our business is subject to a number of risks, including risks that could prevent us from achieving our business objectives or could adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks are discussed more fully below and include but are not limited to risks related to:
Risks Inherent in an Investment in Us
● Cash distributions are not guaranteed
● Ownership of limited partner interests could be diluted
● Sales of our common units could cause decline in the market price of our common units
● Increase in interest rates could cause decline in the market price of our common units
● The credit risk of our general partner could adversely impact us
● Our unitholders do not elect the general partner
● The control of our general partner may be transferred to a third party
● Unitholders may be required to sell their units to our general partner
● Cost reimbursements due to our general partner could be substantial
● Your liability as a limited partner may not be limited under certain circumstances
● Our general partner's fiduciary duties are limited
● Our general partner has discretion in determining the level of cash reserves
● Our general partner has potential conflicts of interest
● Some executive officers and directors face potential conflicts of interest
● ESG scores could adversely impact our securities
Risks Related to Our Business
● Declining global economic conditions could adversely impact us
● Material adverse effects on our financial condition as a result of the COVID-19 pandemic or future pandemic outbreaks could adversely impact us
● Financing may not be available to us on favorable terms or at all
● Our indebtedness could adversely impact us
● We depend upon the leadership of key personnel
● Legal proceedings could adversely impact us
● Our customers may not honor their contracts or may not enter into new contracts for our products
● Some of our contracts may be renegotiated or terminated
● We depend upon a few customers for significant portions of our revenues
● The credit risk of our customers could adversely impact us
● Cyber or terrorist attacks could adversely impact us
● Establishment of labor unions at our operations could adversely affect our profitability
Risks Related to Our Industries
● Changes in coal prices and/or oil & gas prices could impact our results of operations
● Competition within the coal industry could adversely affect our ability to sell coal
● Changes in taxes or tariffs and trade measures could adversely impact us
● Changes in consumption patterns by utilities could affect our ability to sell coal and/or impact the price of our natural gas
● Tort claims based on climate change
● Litigation resulting from disputes with customers could result in costs and liabilities
● Unanticipated mine operating conditions could affect our profitability
● Inability to obtain and renew permits necessary for operations could limit our ability to continue or expand our operations
● Fluctuations in transportation costs and availability could reduce demand for our products
● Unexpected increases in raw material costs could impact the profitability of our operations
● The ability to recruit, hire and retain skilled labor could impact the profitability of our operations
● Disruptions in supply chains could impact the profitability of our operations
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● Inflationary pressures could impact the profitability of our operations
● Unavailability of economic coal mineral reserves and resources could limit our ability to continue or expand our operations
● Estimates of our coal mineral reserves and resources could be inaccurate and could result in decreased profitability
● Coal mining in certain areas could be difficult and involve regulatory constraints which could impact our operations
● Extensive environmental laws and regulations could reduce demand for coal as a fuel source
● Legislative and regulatory compliance is costly
● Legislative and regulatory compliance could impact our business
● Legislative and regulatory initiatives relating to hydraulic fracturing could impact our mineral interests
● Legislative and regulatory initiatives relating to seismic activity could impact our business
● Legislative and regulatory initiatives relating to climate change could impact demand for our products
● Mine facilities located in a leased portion of the surface properties which introduces a risk of disruption to our operations
● Inability to acquire or failure to maintain surety bonds could limit our ability to continue or expand our operations
● Dependency on unaffiliated operators to explore and drill on our oil & gas properties limits our ability to control the timing and quantity of production
● A lack of control over the timing of future drilling with respect to our mineral interests limits our ability to control the timing and quantity of production
● Delays in royalty payments and optional royalty payments could impact our business
● Suspension of right to receive royalty payments could impact our business
● Estimates of our oil & gas reserves could be inaccurate and could result in decreased profitability
● Uncertainties involved in drilling for and producing oil & gas could impact our business
● Availability of transportation and facilities for the products could impact our business
● Lack of hedging arrangements exposes us to the impact of commodity prices
● Expansions and acquisitions have inherent risks that could adversely impact us
● Integration of expansions or acquisitions have inherent risks that could adversely impact us
● Inability to obtain commercial insurance at acceptable rates could have a negative impact on our business
Tax Risks to Our Common Unitholders
● Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service ("IRS") treating us as a corporation or legislative, judicial, or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the Partnership.
● Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder's share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take.
● Tax gain or loss on the disposition of our units could be more than expected and create tax liabilities for our unitholders
● Limitation on unitholders ability to deduct interest expense incurred by us could create tax liabilities for our unitholders
● Tax Exempt entities and non-U.S. unitholders face unique tax issues from owning our common units that may result in adverse tax consequences to them
● IRS challenging our allocation of depreciation and amortization deductions could cause adverse tax consequences
● IRS challenging methods of prorating items of income, gain, loss, and deduction could cause adverse tax consequences
● Tax treatment as a partner for unitholders subject to securities loan could cause adverse tax consequences
● Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.
● Unitholders could be subject to state and local taxes and income tax return filing due to their status as a unitholder
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Risks Inherent in an Investment in Us
Cash distributions to unitholders are not guaranteed.
The board of directors of our managing general partner ("Board of Directors") suspended cash distributions to unitholders beginning with the quarter ended March 31, 2020 due to uncertainty in the global economy caused by the COVID-19 pandemic, and resumed cash distributions following the quarter ended March 31, 2021. The payment and amount of any future distribution will be subject to the sole discretion of our Board of Directors and will depend upon many factors, including our financial condition and prospects, our capital requirements and access to financing, covenants associated with our debt obligations, and other factors that our Board of Directors may deem relevant, and there can be no assurance that we will pay a distribution in the future.
The amount of cash we can distribute to holders of our common units or other partnership securities each quarter principally depends on the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:
● the amount of coal and oil & gas produced from our properties;
● the prices at which our coal and oil & gas are sold, which are affected by the supply of and demand for domestic and foreign coal and oil & gas;
● the level of our operating costs;
● weather conditions and patterns;
● the proximity to and capacity of transportation facilities;
● domestic and foreign governmental regulations and taxes;
● regulatory, administrative, and judicial decisions;
● competition and access to capital within our currently targeted industries;
● the price and availability of alternative fuels;
● the effect of worldwide energy consumption; and
● prevailing economic conditions.
In addition, the actual amount of cash available for distribution will depend on other factors, including:
● the level of our capital expenditures;
● the cost of acquisitions and investments;
● our debt service requirements and restrictions on distributions contained in our current or future debt agreements;
● fluctuations in our working capital needs;
● unavailability of financing resulting in unanticipated liquidity constraints; and
● the amount, if any, of cash reserves established by our general partner, in its discretion, for the proper conduct of our business.
Because of these and other factors, we may not have sufficient available cash to pay cash distributions to our unitholders. Furthermore, the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowing, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may be unable to make cash distributions during periods when we record net income. Please read "—Risks Related to our Business" for a discussion of further risks affecting our ability to generate available cash and "Item 8. Financial Statements and Supplementary Data—Note 12 – Variable Interest Entities" for further discussion of restrictions on the cash available for distribution.
We may issue an unlimited number of limited partner interests, on terms and conditions established by our general partner, without the consent of our unitholders, which will dilute your ownership interest in us and could increase the risk that we will not have sufficient available cash to make distributions.
The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
● our unitholders ' proportionate ownership interest in us will decrease;
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● the amount of cash available for distribution on each unit could decrease;
● the relative voting strength of each previously outstanding unit could be diminished;
● the ratio of taxable income to distributions could increase; and
● the market price of our common units could decline.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.
The sale or disposition of a substantial number of our common units by our existing unitholders in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.
An increase in interest rates could cause the market price of our common units to decline.
Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities could cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities could cause the trading price of our common units to decline.
The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.
The credit and risk profile of our general partner or its owners may be factors in credit evaluations of us as a master limited partnership. This is because our general partner can exercise significant influence or control over our business activities, including our cash distribution policy, acquisition strategy, and business risk profile.
Our unitholders do not elect our general partner or vote on our general partner's officers or directors.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner and will have no right to elect our general partner on annual or other continuing bases. If our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66.7% of our outstanding units.
Our unitholders' voting rights are also restricted by a provision in our partnership agreement that provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner to sell or transfer all or part of their ownership interest in our general partner to a third party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by the Board of Directors and officers.
Unitholders may be required to sell their units to our general partner at an undesirable time or price.
If at any time less than 20.0% of our outstanding common units are held by persons other than our general partner and its affiliates, our general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. Our general partner may assign this purchase right to any of its affiliates or us.
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Cost reimbursements due to our general partner could be substantial and could reduce our ability to pay distributions to unitholders.
Before making any distributions to our unitholders, we will reimburse our general partner and its affiliates for all expenses they have incurred on our behalf. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees. For additional information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Related-Party Transactions— Administrative Services ," and "Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions."
Your liability as a limited partner may not be limited, and our unitholders could have to repay distributions or make additional contributions to us under certain circumstances.
As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the "control" of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been established in many jurisdictions.
Under certain circumstances, our unitholders could have to repay amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Our partnership agreement limits our general partner ' s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that may otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates and which reduce the obligations to which our general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partner to the limited partners. Our partnership agreement:
● permits our general partner to make many decisions in its "sole discretion." This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates, or any limited partner;
● provides that our general partner is entitled to make other decisions in its "reasonable discretion";
● generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; and
● provides that our general partner and our officers and directors will not be liable for monetary damages to us, our limited partners, or assignees for errors of judgment or any acts or omissions if our general partner and those other persons acted in good faith.
All limited partners are bound by the provisions in the partnership agreement, including the provisions discussed above.
Our general partner's discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.
Our partnership agreement requires our general partner to deduct from available cash reserves that in its reasonable discretion are necessary for the proper conduct of our business, to comply with applicable law or agreements to which we
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are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.
Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor their interests to the detriment of our unitholders.
Conflicts of interest could arise in the future as a result of relationships between our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its interests and those of its affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:
● Remedies available to our unitholders for actions that, without the limitations, could constitute breaches of fiduciary duty are limited. Unitholders are deemed to have consented to some actions and conflicts of interest that could otherwise be deemed a breach of fiduciary or other duties under applicable state law.
● Our general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders.
● Our general partner's affiliates are not prohibited from engaging in other businesses or activities, including those in direct competition with us, except as provided in the omnibus agreement (please see "Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement").
● Our general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, and reserves, each of which can affect the amount of cash that is distributed to unitholders.
● Our general partner determines whether to issue additional units or other equity securities in us.
● Our general partner determines which costs are reimbursable by us.
● Our general partner controls the enforcement of obligations owed to us by it.
● Our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
● Our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or from entering into additional contractual arrangements with any of these entities on our behalf.
● In some instances, our general partner may direct us to borrow funds to permit the payment of distributions.
Some of our executive officers and directors face potential conflicts of interest in managing our business.
Certain of our executive officers and directors are also officers and/or directors of Alliance GP, LLC ("AGP"). These relationships could create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders' best interests. These officers and directors face potential conflicts regarding the allocation of their time, which could adversely affect our business, results of operations, and financial condition.
Increasing attention to ESG matters may negatively impact our business, financial results, and unit price.
Companies across all industries, including companies in the fossil-fuel industry, are facing increased scrutiny from stakeholders related to their ESG practices. Companies that do not adapt or comply with evolving investor or stakeholder expectations and standards, or are perceived to have not responded appropriately to ESG issues, regardless of any legal requirement to do so, may suffer reputational damage and the business, financial condition, and/ unit price of such companies could be materially and adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention to and demands for action related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, reduce demand for our coal and hydrocarbon products, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our unit price and access to capital markets.
In addition, certain organizations that provide corporate governance and other corporate risk information to investors and unitholders have developed scores and ratings to evaluate companies and investment funds based upon ESG or "sustainability" metrics. Currently, there are no universal standards for such scores or ratings, but consideration of
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sustainability evaluations is becoming more broadly accepted by investors. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments, whereas other funds may use certain ESG criteria to "screen" certain sectors, such as coal or fossil fuels more generally, out of their investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance or sell their interests in the company, particularly if its ESG performance does not improve. Moreover, certain members of the broader investment community may consider a company's sustainability score as a reputational or other factors in making an investment decision. Companies in the energy industry, and in particular those focused on coal, natural gas, or oil extraction, often do not score as well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities, both debt and equity, being excluded from the portfolios of certain investment funds and investors, restricting our access to capital to fund our continuing operations and growth opportunities. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Risks Related to our Business
Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets could have material adverse impacts on our business and financial condition that we currently cannot predict.
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 and financial condition. For example:
● the demand for electricity in the United States and globally could decline if economic conditions deteriorate, which could negatively impact the revenues, margins, and profitability of our business;
● 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 could be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including the development of our coal mineral reserves and resources.
We face various risks related to pandemics and similar outbreaks, which have had and may continue to have material adverse effects on our business, financial position, results of operations, and/or cash flows.
We face a wide variety of risks related to pandemics, including the global outbreak of COVID-19. Since first reported in late 2019, the COVID-19 pandemic has dramatically impacted the global health and economic environment, including millions of confirmed cases, business slowdowns or shutdowns, government challenges, and market volatility of an unprecedented nature. Although we have, to date, managed to continue most of our operations, we cannot predict the future course of events nor can we assure that this global pandemic, including its economic impact, will not continue to have a material adverse impact on our business, financial position, results of operations and/or cash flows. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the coal and oil & gas industries. The COVID-19 outbreak and the responsive actions to limit the spread of the virus have significantly reduced global economic activity, resulting in a decline in the demand for coal, oil, natural gas, and other commodities. Our operations could be further impacted by the COVID-19 pandemic if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, or absenteeism; steps the company has taken to protect health and well-being; government actions; facility closures; work slowdowns or stoppages; inadequate supplies or resources (such as reliable personal protective equipment, testing, and vaccines); or other circumstances related to COVID-19. Looking forward, we could be unable to perform fully on our contracts, we could experience interruptions in our business and we could incur liabilities and suffer losses as a result. We will continue to incur additional costs because of the COVID-19 outbreak, including protecting the health and well-being of our employees and as a result of impacts on operations and performance, which costs we may not be fully able to recover. We could be subject to additional regulatory requirements, enforcement actions, and litigation, again with costs and liabilities that are not fully recoverable or insured. The continued spread of COVID-19 could also affect our ability to hire, develop and retain our talented and diverse workforce, and to maintain our corporate culture. The impact of a government-enforced vaccine mandate may result in adverse impacts such as workforce attrition for us or reduced morale or efficiency. The continued global pandemic, including the economic impact, is likely also to cause further disruption in our supply chain. If our suppliers have increased challenges with their workforce (including as a result of illness, absenteeism, or government orders), facility closures, access to necessary
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components and supplies, access to capital, and access to fundamental support services (such as shipping and transportation), they could be unable to provide the agreed-upon goods and services in a timely, compliant and cost-effective manner. We could incur additional costs and delays in our business, including as a result of higher prices for materials and equipment and schedule delays. As a result of the COVID-19 crisis, there may be changes in our customers' priorities and practices, as our customers in both the United States and globally confront reduced demand. Our customers have and may continue to experience adverse effects as a result of the COVID-19 crisis which could impact their creditworthiness or their ability to make payment for our products. We continue to work with our stakeholders (including customers, employees, suppliers, and local communities) to address this global pandemic responsibly. We continue to monitor the situation, assess further possible implications to our employees, business, supply chain, and customers, and take certain actions to mitigate various adverse consequences. We expect that the longer the COVID-19 pandemic, including its economic disruption, continues, the greater the adverse impact on our business operations, financial performance, and results of operations could be. The ultimate impact of COVID-19 on our operational and financial performance in future periods remains uncertain and will depend on future pandemic-related developments, including the duration of the pandemic, potential subsequent waves of COVID-19 infection or potential new variants, the effectiveness and adoption of COVID-19 vaccines and therapeutics, supplier impacts and related government actions to prevent and manage disease spread, including the implementation of any federal, state, local or foreign vaccine mandates, all of which are uncertain and cannot be predicted.
Growing our business could require significant amounts of financing that may not be available to us on acceptable terms, or at all.
We plan to fund capital expenditures for our growth initiatives with existing cash balances, future cash flows from operations, borrowings under revolving credit and securitization facilities, and cash provided from the issuance of debt or equity. At times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans could be negatively impacted by constraints in the capital markets as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we could be unable to refinance our current debt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet our funding needs. Furthermore, additional growth projects and expansion opportunities could develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.
Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then-current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations, and cash flows. If we are unable to finance our growth initiatives as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.
Our indebtedness could limit our ability to borrow additional funds, make distributions to unitholders, or capitalize on business opportunities.
We had long-term indebtedness of $443.1 million as of December 31, 2021. Our leverage may:
● adversely affect our ability to finance future operations and capital needs;
● limit our ability to pursue acquisitions and other business opportunities;
● make our results of operations more susceptible to adverse economic or operating conditions; and
● make it more difficult to self-insure for our workers' compensation obligations.
In addition, we have unused borrowing capacity under our revolving credit facility. Future borrowings, under our credit facilities or otherwise, could increase our leverage.
Our payments of principal and interest on any indebtedness will reduce the cash available for distribution on our units. We will be prohibited from making cash distributions:
● during an event of default under any of our indebtedness; or
● if after such distribution, we fail to meet a coverage test based on the ratio of our consolidated cash flow to our consolidated fixed charges.
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Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, engage in some transactions, and capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. Please see "Item 8. Financial Statements and Supplementary Data – Note 8 – Long-Term Debt" for further discussion.
We depend on the leadership and involvement of Joseph W. Craft III and other key personnel for the success of our business.
We depend on the leadership and involvement of Mr. Craft. Mr. Craft has been integral to our success, due in part to his ability to identify and develop internal growth projects and accretive acquisitions, make strategic decisions, and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, financial condition, and results of operations.
We and our subsidiaries are subject to various legal proceedings, which could have a material adverse effect on our business.
We are party to a number of legal proceedings incident to our normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could have an adverse effect on our cash flows, results of operations, or financial position. Please see "Item 3. Legal Proceedings" and "Item 8. Financial Statements and Supplementary Data—Note 22 – Commitments and Contingencies" for further discussion.
The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.
In 2021, we sold approximately 77.9% of our coal sales tonnage under contracts having a term greater than one year, which we refer to as long-term sales contracts. These contracts have historically provided a relatively secure market for the production committed under the terms of the contracts. From time to time industry conditions could make it more difficult for us to enter into long-term sales contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.
Some of our long-term sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.
Some of our long-term sales contracts contain provisions that allow the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term sales contracts may provide only limited protection during adverse market conditions. In some circumstances, the failure of the parties to agree on a price under a reopener provision can also lead to the early termination of a contract.
Several of our long-term sales contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer's reasonable control. Such events could include labor disputes, mechanical malfunctions, and changes in government regulations, including changes in environmental regulations rendering the use of our coal inconsistent with the customer's environmental compliance strategies. Additionally, most of our long-term sales contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. In the event of early termination of any of our long-term sales contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition, and results of operations could be adversely affected.
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We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of the coal we produce.
In 2021, we derived more than 10% of our total revenues from Louisville Gas and Electric Company. If we were to lose this or any of our significant customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or change the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition, and results of operations.
Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer's contractual obligations are honored. See "Item 3. Legal Proceedings."
Terrorist attacks or cyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.
Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure, and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of reserves and resources, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, could be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Further, as cyber incidents continue to evolve, we could be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
Although none of our employees are members of unions, our workforce may not remain union-free in the future.
None of our employees are represented under collective bargaining agreements. However, our workforce 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 could still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.
Risks Related to Our Industries
Prices for oil & gas, as well as coal, are volatile and can fluctuate widely based upon a number of factors beyond our control. An extended decline in the prices of such commodities could negatively impact our results of operations.
Our results of operations are primarily dependent upon the prices of oil & gas and coal, as well as our ability to improve productivity and control costs. The prices for oil & gas and coal depend upon factors beyond our control, including:
● overall domestic and global economic conditions;
● the adverse impact of the COVID-19 pandemic due to the reduction in demand, as well as impacts of the pandemic on our ability to produce coal and oil & gas;
● the supply of and demand for domestic and foreign coal;
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● the supply of and demand for oil & gas;
● weather conditions and patterns that affect demand for coal and oil & gas, or our ability to produce coal or the ability of operators to produce oil & gas from our mineral interests;
● supply chain and cost of raw materials for coal and oil & gas operations;
● the proximity to and capacity of transportation facilities;
● competition from other coal suppliers;
● domestic and foreign governmental regulations and taxes;
● the price and availability of alternative fuels;
● the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;
● international developments impacting the supply of coal;
● international developments impacting the supply of oil & gas; and
● the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits, as well as regulations affecting the oil & gas extraction industry.
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 could materially and adversely affect us by decreasing our revenues to the extent we are not protected by the terms of existing coal supply agreements.
Competition within the coal industry could adversely affect our ability to sell coal, and excess production capacity in the industry has put downward pressure on coal prices. In addition, foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.
We compete with other coal producers in various regions of the United States for domestic coal sales. In addition, we face competition from foreign and domestic producers that sell their coal in the international coal markets. The most important factors on which we 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 could 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 could impact our ability to retain or attract customers and could adversely impact our revenues and cash available for distribution.
We sell coal to the export thermal and metallurgical coal market, both of which are significantly affected by international demand and competition. Consolidation in the coal industry or current or future bankruptcy proceedings of coal competitors could adversely affect us. If overcapacity continues, the prices of and demand for our coal could significantly decline further, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows, and could reduce our revenues and cash available for distribution.
In addition, we face competition from foreign producers that sell their coal in the export market. Potential changes to international trade agreements, trade concessions, or other political and economic arrangements could benefit coal producers operating in countries other than the United States. We could be adversely impacted on the basis of price or other factors by foreign trade policies or other arrangements that benefit competitors. In addition, coal is sold internationally in United States dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates could provide our foreign competitors with a competitive advantage. If our competitors' currencies decline against the United States dollar or foreign purchasers' local currencies, those competitors could be able to offer lower prices for coal to those purchasers. Furthermore, if the currencies of overseas purchasers were to significantly decline in value in comparison to the United States dollar, those purchasers may seek decreased prices for the coal we sell. 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.
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Changes in taxes or tariffs and other trade measures by the United States and foreign governments could adversely affect our results of operations, financial position, and cash flows.
We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.
New tariffs and other trade measures could adversely affect our results of operations, financial position, and cash flows. In response to tariffs imposed by the United States, the European Union, Canada, Mexico, and China have imposed tariffs on United States goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the United States or other potentially adverse economic outcomes. Additionally, we sell coal into the export thermal and metallurgical markets. Accordingly, our international sales could also be impacted by the tariffs and other restrictions on trade between the United States and other countries. While tariffs and other retaliatory trade measures imposed by other countries on United States goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.
Changes in consumption patterns by utilities regarding the use of coal have affected our ability to sell the coal we produce and may do so in the future.
Our business is closely linked to the demand for electricity, and any changes in coal consumption by United States or international electric power generators would likely impact our business over the long term. The domestic electric power sector accounts for the vast majority of the total domestic coal consumption. The amount of coal consumed by the domestic electric 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. Indirect competition from natural gas-fired plants that are relatively more efficient, less expensive to construct, and less difficult to permit than coal-fired plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.
Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash available for distribution.
Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, could have a material adverse effect on the demand for coal and our business over the long term.
We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change .
Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a
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result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.
Litigation resulting from disputes with our customers could result in substantial costs, liabilities, and loss of revenues.
From time to time, we have disputes with our customers over the provisions of 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 could 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, and results of operations. See "Item 3. Legal Proceedings."
Our profitability could decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.
Our coal mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:
● mining and processing equipment failures and unexpected maintenance problems;
● unavailability of required equipment;
● prices for fuel, steel, explosives, and other supplies;
● fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;
● variations in the thickness of the layer, or seam, of coal;
● amounts of overburden, partings, rock, and other natural materials;
● weather conditions, such as heavy rains, flooding, ice, and other natural events affecting operations, transportation, or customers;
● accidental mine water discharges and other geological conditions;
● fires;
● seismic activities, ground failures, rock bursts or structural cave-ins or slides;
● employee injuries or fatalities;
● labor-related interruptions;
● increased reclamation costs;
● inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
● fluctuations in transportation costs and the availability or reliability of transportation; and
● unexpected operational interruptions due to other factors.
These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.
Effective December 1, 2021, we renewed our annual property and casualty insurance program. Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance, LLC ("Wildcat Insurance"). Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. The maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 75 or 90 day waiting period for underground business interruption depending on the mining complex, and an additional $10.0 million overall aggregate deductible. We have elected to retain a 10% participating interest in our commercial property insurance program. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations, and ability to purchase property insurance in the future. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, the insurance industry has been subject to efforts by environmental activists to restrict coverages available for fossil-fuel companies.
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We could be unable to obtain and renew permits necessary for our coal mining operations, which could reduce our production, cash flow, and profitability.
Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations may not be issued, maintained, or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability. Please read "Item 1. Business—Environmental, Health and Safety Regulations— Mining Permits and Approvals ."
The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its "veto" power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA's action was ultimately upheld by a federal court. As a result of these developments, we could be unable to obtain or experience delays in securing, utilizing, or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position. Please read "Item 1. Business—Environmental, Health and Safety Regulations— Water Discharge ."
In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process or even an inability to obtain permits, permit modifications, or permit renewals necessary for 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.
Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is 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. Our transportation providers could face difficulties in the future that could 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 United States 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.
States in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or maintain production and could adversely affect revenues.
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Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID-19 pandemic), labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to participate in the export market for coal sales, which could adversely affect our sales and our results of operations.
Unexpected increases in raw material costs could significantly impair our operating profitability.
Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies, and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas, and coking coal consumed in the production of iron and steel fluctuate significantly and could change unexpectedly. Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, and maintenance expense. There could be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products, or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs and could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs. This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers in and attracting new workers to the coal industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, 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 profitability.
Disruptions in supply chains could significantly impair our operating profitability.
We are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability and adversely affect our results of operations.
Inflationary pressures could significantly impair our operating profitability.
Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal or oil & gas and could adversely affect our results of operations.
The unavailability of an adequate supply of coal mineral reserves and resources that can be mined at competitive costs could cause our profitability to decline.
Our profitability depends substantially on our ability to mine coal mineral reserves and resources that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves and resources as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal mineral reserves and resources that are economically recoverable. Replacement reserves and resources may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves or resources that we acquire, which could adversely affect our profitability and financial condition. Exhaustion of reserves and resources at particular mines also could have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves and resources in the future
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could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, or the inability to acquire coal properties on commercially reasonable terms.
The estimates of our coal mineral reserves and resources could prove inaccurate and could result in decreased profitability.
The estimates of our coal mineral reserves and resources could vary substantially from the actual amounts of coal we are able to economically recover. The reserve and resource data set forth in "Item 2. Properties—Coal Mineral Resources and Reserves" represent engineering estimates. All of the coal mineral reserves presented in this Annual Report on Form 10-K constitute proven and probable mineral reserves. There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond our control. Estimates of coal mineral reserves and resources necessarily depend upon a number of variables and assumptions, any one of which could 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.
Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect our actual coal reserves and resources. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results. Additionally, the estimates of coal reserves and resources may be adversely affected in future fiscal periods by the SEC's recent rule amendments revising property disclosure requirements for publicly traded coal mining companies, with which we are complying for the first time in this report.
Coal mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the United States, which could affect the mining operations and cost structures of these areas.
The geological characteristics of some of our coal mineral reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. In addition, permitting, licensing, and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. Subsidence issues are particularly important to our operations engaged in longwall mining. Failure to timely and economically secure subsidence rights or any associated mitigation agreements could materially affect our results by causing delays or changes in our mining plan. These factors could materially adversely affect the mining operations and cost structures of, and our customers' ability to use coal produced by, our mines.
Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.
Federal, state, and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury, and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations could require further emission reductions and associated emission control expenditures. These laws and regulations could affect demand and prices for coal. There is also continuing pressure on federal and state regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the
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EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the United States. Please read "Item 1. Business—Environmental, Health and Safety Regulations— Air Emissions ," "— GHG Emissions " and "— Hazardous Substances and Wastes ."
Our coal mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
We are subject to numerous 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. 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 could be costly and time-consuming and could delay the commencement or continuation of exploration or production operations. The possibility exists 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 materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers' use of coal. Please read "Item 1. Business—Environmental, Health and Safety Regulations."
Federal and state 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 have an adverse effect on our results of operation and financial position. For more information, please read "Item 1. Business—Environmental, Health and Safety Regulations— Mine Health and Safety Laws ."
Oil & gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which could impact our operators' willingness to develop our interests.
Our operators' operations on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil & gas wells below actual production capacity to conserve supplies of oil & gas. In addition, the production, handling, storage, and transportation of oil & gas, as well as the remediation, emission, and disposal of oil & gas wastes, by-products thereof, and other substances and materials produced or used in connection with oil & gas operations are subject to regulation under federal, state, and local laws and regulations primarily relating to the protection of worker health and safety, natural resources, and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all of our operators' operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management. Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including:
● provisions related to the unitization or pooling of the oil & gas properties;
● the establishment of maximum rates of production from wells;
● the spacing of wells;
● the plugging and abandonment of wells; and
● the removal of related production equipment.
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Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which could require increased capital costs for third-party oil & gas transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral interests.
Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity. Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. These current laws and regulations and other potential regulations could increase the operating costs of our operators and delay production and could ultimately impact our operators' ability and willingness to develop our properties.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and fewer potential drilling locations, which could adversely affect revenues from our mineral interests.
Oil & gas production on the properties in which we hold mineral interests utilizes hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate the production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the Underground Injection Control ("UIC") program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil & gas commissions.
Several states where we own interests, including Texas and Oklahoma, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. In addition to state laws, local land-use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We cannot predict what additional state or local requirements may be imposed in the future on oil & gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators could incur substantial costs to comply with these requirements, which could be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.
There has been increasing public controversy regarding hydraulic fracturing about increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs and adversely affect revenues from our mineral interests. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Legislation or regulatory initiatives intended to address seismic activity could restrict our operators ' drilling and production activities, as well as their ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between the hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil & gas activity and induced seismicity. For example, in 2015, the United States Geological Study identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil & gas extraction.
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In addition, a number of lawsuits have been filed in other states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, both Texas and Oklahoma have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. In September 2021, the Texas Railroad Commission ("TRRC") issued a notice to operators in the Midland area to reduce saltwater disposal well activities and provide certain data to the TRRC. Subsequently, the TRRC ordered the indefinite suspension of all deep oil and gas produced water injection wells in the area, effective December 31, 2021.
The adoption or implementation of any new laws or regulations that restrict our operators' ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations, or otherwise, or requiring our operators to shut down or limit the operation of disposal wells, could have a material adverse effect on our business, financial condition and results of operations.
Our operations are subject to a series of risks resulting from climate change.
Combustion of fossil fuels, such as the coal we produce and the oil & gas produced from our mineral interests, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events. Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain sources in the United States, or constrain the emissions of powerplants (though such emissions restraints have been subject to challenge; for more information, see our regulatory disclosure titled "GHG emissions"). Additionally, relating to our oil and gas mineral interests, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal September 2020 revisions to methane standards, effectively reinstating the more stringent 2016 standards. Furthermore, in November 2021, EPA issued a proposed rule that, if finalized, would establish new sources and first-time existing source standards of performance for methane and volatile organic compound emissions for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems. EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of final rule by the end of the year. We cannot predict the scope of any final methane regulatory requirements or the cost for our operators to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.
Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets. These commitments could further reduce demand and prices for fossil fuels. Although the United States had withdrawn from the Paris Agreement, following President Biden’s executive order in January 2021, the United States rejoined the Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our operators' operations.
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Governmental, scientific, and public concern over climate change has also resulted in increased political risks, including certain climate-related pledges made by certain candidates now in political office. In January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Other actions that may be pursued include restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we, our customers, or operators of our mineral interests could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing. For more information, see our risk factor titled "We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change."
Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero ("GFANZ") announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. In late 2020, the Federal Reserve announced it had joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining or oil & gas production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal and oil & gas, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us or oil & gas operators restricting or canceling mining or oil & gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate economically. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources, could cause prices and sales of our coal and/or oil & gas to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations, as well as those of our operators and their supply chain. Such physical risks may result in damage to our facilities or our operators' facilities or otherwise adversely impact operations which could decrease the production attributable to our mineral interests. We may not have insurance to cover these risks and the consequences for our or their operations could have a negative impact on the costs and revenues from operations.
Some of our operating subsidiaries lease a portion of the surface properties upon which their mining facilities are located.
Our operating subsidiaries do not, in all instances, own all of the surface properties upon which their mining facilities have been constructed. Certain of the operating companies have constructed and now operate all or some portion of their facilities on properties owned by unrelated third parties with whom our subsidiary has entered into a long-term lease. We
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have no reason to believe that there exists any risk of loss of these leasehold rights given the terms and provisions of the subject leases and the nature and identity of the third-party lessors; however, in the unlikely event of any loss of these leasehold rights, operations could be disrupted or otherwise adversely impacted as a result of increased costs associated with retaining the necessary land use.
Federal and state laws require bonds to secure our obligations related to statutory reclamation requirements and workers ' compensation and black lung benefits. Our inability to acquire or failure to maintain surety bonds that are required by federal and state law would have a material adverse effect on us.
Federal and state laws require us to place and maintain bonds to secure our obligations to repair and return the 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 federal and state 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, including as a result of external pressures related to fossil-fuel companies;
● the ability of current and future surety bond issuers to increase required collateral, or limitations on the availability of collateral for surety bond issuers due to the terms of our credit agreements; and
● the exercise by third-party surety bondholders of their rights to refuse to renew the surety.
We have outstanding surety bonds with governmental agencies for reclamation, federal and state workers' compensation, and other obligations. At December 31, 2021, our total of such bonds was $254.5 million. We could have difficulty maintaining our surety bonds for mine reclamation as well as workers' compensation and black lung benefits. In addition, those governmental agencies may increase the amount of bonding required. 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.
We depend on unaffiliated operators for all of the exploration, development, and production of the oil & gas properties in which we own mineral interests.
Because we depend on our third-party operators for all of the exploration, development, and production of our oil & gas properties, we have little to no control over the operations related to our oil & gas properties. The operators of our properties are often not obligated to undertake any development activities. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law). The success and timing of drilling and development activities on our oil & gas properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:
● the capital costs required for drilling activities by the operators of our oil & gas properties, which could be significantly more than anticipated;
● the ability of the operators of our properties to access capital;
● prevailing commodity prices;
● the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
● the operators' expertise, operating efficiency, and financial resources;
● approval of other participants in drilling wells;
● the operators' expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
● the selection of technology;
● the selection of counterparties for the marketing and sale of production; and
● the rate of production of the reserves.
The operators may elect not to undertake development activities or may undertake these activities in an unanticipated fashion, which could result in significant fluctuations in our oil & gas revenues.
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We have little to no control over the timing of future drilling with respect to our oil & gas mineral interests.
All of our oil & gas mineral interests may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue the development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the scheduled development plans of our operators. The reserve data included in the reserve report assumes that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and could result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.
We could experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease and enforce payment obligations under the lease. If we terminate any of our leases, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under Title 11 of the United States Code (the "Bankruptcy Code"), in which case our right to enforce or terminate the lease for any defaults, including non-payment, could be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have substantial time to decide whether they ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery could be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.
If the operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, and/or results of operations could be adversely affected.
Upon a change in ownership of mineral interests, and at regular intervals pursuant to routine audit procedures at each of our operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of our operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests is placed in suspense, our results of operations could be reduced significantly.
Our estimated oil & gas reserves are based on many assumptions that could turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil & gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil & gas and assumptions concerning future oil & gas prices, production levels, ultimate recoveries, and operating costs. As a result, estimated quantities of proved reserves and projections of future production rates could be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2021, were audited by Netherland, Sewell & Associates, Inc. ("NSAI"), which conducted a detailed review of all of our properties at that time using the information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual
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drilling, testing, and production. In addition, certain assumptions regarding future oil & gas prices, production levels, and operating costs could prove incorrect. A meaningful portion of our reserve estimates is made without the benefit of lengthy production history, which is less reliable than estimates based on lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil & gas that are ultimately recovered being different from our reserve estimates.
Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board ("FASB"), we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil & gas index prices, calculated as the unweighted arithmetic average for the first day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs could differ materially from those used in the present value estimate, and future net present value estimates using then-current prices and costs could be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil & gas industry in general. Please see "Item 2. Properties—Oil & Gas Reserves" for more information on our reserves.
Drilling for and producing oil & gas are high-risk activities with many uncertainties that could materially adversely affect our business, financial condition, and results of operations.
The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive. Drilling for oil & gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or gas to return a profit at then realized prices after deducting drilling, operating, and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or gas is present or that it can be produced economically. The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators' drilling and producing operations could be curtailed, delayed, canceled, or otherwise negatively impacted as a result of other factors, including:
● unusual or unexpected geological formations or earthquakes;
● loss of drilling fluid circulation;
● title problems;
● facility or equipment malfunctions;
● unexpected operational events;
● shortages or delivery delays of equipment and services;
● compliance with environmental and other governmental requirements; and
● adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources, and equipment, pollution, environmental contamination or loss of wells, and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or canceled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations, and free cash flow could be materially adversely affected.
The marketability of oil & gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, our operators' operations could be interrupted and our results of operations and cash available for distribution could be materially adversely affected.
The marketability of our operators' oil & gas production will depend in part upon the availability, proximity, and capacity of transportation facilities, including gathering systems, trucks, and pipelines, owned by third parties. Neither we nor, in general, the operators of our properties control these third-party transportation facilities and our operators' access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our operators' ability to deliver to market or produce oil & gas and thereby cause a significant interruption in our operators' operations. If they
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are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production-related difficulties, they may be required to shut-in or curtail production. In addition, the amount of oil & gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or our operators' control, such as pipeline interruptions due to maintenance, excessive pressure, inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances could last from a few days to several months. In many cases, we and our operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil & gas produced from our acreage, could adversely affect our financial condition, results of operations, and cash available for distribution.
We do not currently enter into hedging arrangements with respect to commodity production from our properties, and we will be exposed to the impact of decreases in the price of such commodities.
We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil & gas or the coal produced from our properties, and we may not enter into such arrangements in the future. As a result, although we could realize the benefit of any short-term increase in the price, we will not be protected against decreases in the price or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operation and cash available for distribution.
In the future, we may enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of oil & gas or coal. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there could be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we could be limited in receiving the full benefit of increases in commodity prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.
Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.
Since our formation and the acquisition of our predecessor in August 1999, we have expanded our coal operations by adding and developing mines in existing, adjacent, and neighboring properties. Similarly, the profitability of our business depends significantly upon acquisitions to grow our coal and oil & gas reserves, production, and free cash flow. Our future growth could be limited if we are unable to continue to make acquisitions in either our coal operations or our royalties segments, or if we are unable to successfully integrate the companies, businesses, or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.
Competition for acquisitions of coal and oil & gas mineral interests could increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing under acceptable terms. In addition, these acquisitions could be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.
The process of integrating acquired assets could involve unforeseen difficulties and could require a disproportionate amount of our managerial and financial resources. If we are unable to successfully integrate the companies, businesses, or properties we acquire, our profitability could decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:
● uncertainties in assessing the value, strengths, and potential profitability of expansion and acquisition opportunities ;
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● uncertainties in identifying the extent of all weaknesses, risks, contingent and other liabilities of, expansion and acquisition opportunities;
● the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;
● problems that could arise from the integration of the new operations; and
● unanticipated changes in business, industry, or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.
Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and could require us to incur indebtedness, seek equity capital, or both. Future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.
The integration of any expansions or acquisitions that we complete will be subject to substantial risks.
Even if we make expansions or acquisitions that we believe will increase our coal or mineral revenue, any expansion or acquisition involves potential risks, including, among other things:
● the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, the operating expenses, and costs our operators would incur to develop the minerals;
● a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
● a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
● the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
● mistaken assumptions about the overall cost of equity or debt;
● our ability to obtain satisfactory title to the assets we acquire;
● an inability to hire, train or retain qualified personnel to manage and operate our growing mineral assets; and
● the occurrence of other significant changes, such as impairment of properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.
We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly-traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.
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Tax Risks to Our Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and our not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.
The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our units could be negatively impacted.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstance and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws and interpretation thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If the IRS were to contest the U.S. federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to
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administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders could be reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties and interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to pay taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability which results from your share of our taxable income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis therein, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
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Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for "business interest" is limited to the sum of our business interest income and 30% of our "adjusted taxable income." For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization or depletion is not capitalized into cost of goods sold with respect to inventory. If our "business interest" is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as "IRAs") raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business ("effectively connected income"). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner's "amount realized" generally includes any decrease of a partner's share of the partnership's liabilities, the Treasury regulations provide that the "amount realized" on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner's share of a publicly traded partnership's liabilities. The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023. Thereafter, the obligation to withhold on a transfer of interests in a publicly traded partnership that is effected through a broker is imposed on the transferor's broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.
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We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the "Allocation Date"), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are the subject of a securities loan (e.g., a loan to a " short seller " to cover a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Certain U.S. federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.
In past years, members of the U.S. Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. Elimination of those provisions would not impact our financial statements or results of operations. However, elimination of such provisions could result in unfavorable tax consequences for our unitholders and, as a result, could negatively impact our unit price.
You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements.
We currently own assets and conduct business in multiple states which currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state, and local tax returns and pay any taxes due in these jurisdictions. You should consult with your tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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ITEM 2. PROPERTIES
Coal Mineral Resources and Reserves
Overview of Coal Properties
Our coal properties are located in the Illinois Basin and the Appalachia Basin. Our Illinois Basin properties are located in western Kentucky, southern Illinois, and southern Indiana. Our Appalachian properties are located in eastern Kentucky, Maryland, western Pennsylvania, and northern West Virginia. Mining operations on our coal properties consist of underground mines that produce bituminous coal that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). In addition to our coal mining operations, we also hold coal mineral interests that we lease/sublease to our operations or hold for lease/sublease to our operations or others. For a detailed overview of our coal mining operations and our coal royalty activities, please see "Item 1. Business—Coal Mining Operations" and "Item 1. Business—Mineral Interest Activities", respectively.
Evaluation and Review of Coal Mineral Resources and Reserves
Numerous uncertainties are inherent in estimating coal mineral resources and reserves, and the estimates are subject to change as additional information becomes available or circumstances change. Significant factors and assumptions related to the uncertainty in estimating coal mineral reserves and resources include:
● 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.
Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect our actual coal reserves and resources. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results. Additionally, the estimates of coal reserves and resources may be adversely affected in future fiscal periods by the SEC's recent rule amendments revising property disclosure requirements for publicly traded coal mining companies, with which we are complying for the first time in this report.
Under SEC rules, a mineral resource is a concentration or occurrence of material of economic interest in or on the Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. A mineral reserve is an estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.
Our coal mineral resource and reserve estimates included in this Annual Report on Form 10-K were prepared by an independent, qualified engineering firm, RESPEC Company, LLC ("RESPEC"). We provided RESPEC with property control, mine plans, production, revenue, costs, capital, and other information considered by RESPEC in making their estimates. As part of our internal controls, our geologists and engineers review the integrity, accuracy, and timeliness of the data provided to RESPEC that they considered in calculating their coal mineral resource and reserve estimates. We also review the geologic data, mining assumptions, and methodology used by RESPEC to estimate our coal mineral
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resources and reserves. Our geologists and engineers also met with RESPEC periodically during the year to discuss the assumptions and methods used in the coal mineral resource and reserve estimation process.
RESPEC, an independent third-party engineering firm, does not own an interest in any of our properties and is not employed on a contingent basis. RESPEC's Technical Report Summaries for each of our material mining operations are included as exhibits to this Annual Report on Form 10-K.
Summary of Coal Mineral Resources and Reserves
Coal Mineral Resources
Most of our coal properties designated as mineral resources are of thickness, quality, and mineability similar to that of our mineral reserves, and all are proximal to existing infrastructure such as power, water, transportation, facilities, etc. However, we have not completed pre-feasibility or feasibility studies with respect to our coal properties designated as mineral resources, as is required to convert the mineral resources into mineral reserves. There is no certainty that all or any part of our mineral resources will be converted into mineral reserves.
The following table sets forth our coal mineral resources, exclusive of coal mineral reserves, at December 31, 2021:
Heat
Resources (tons in
Content (Btus
Pounds SO2 per MMBtu
Resource Classification
Ownership
millions)
per pound)
<1.2
1.2-2.5
>2.5
Measured
Indicated
Combined
Inferred
Owned
Leased
Total
(1)
Illinois Basin
Dotiki (KY)
12,100
—
2.3
73.7
51.2
24.8
76.0
—
27.6
48.4
76.0
Henderson/Union (KY)
11,450
—
3.2
520.3
175.4
286.0
461.4
62.1
74.6
448.9
523.5
Sebree South (KY)
11,750
—
—
43.5
22.1
16.8
38.9
4.6
0.3
43.2
43.5
Hamilton County (IL)
11,650
5.1
33.8
398.8
187.1
239.3
426.4
11.3
32.6
405.1
437.7
Region Total
5.1
39.3
1,036.3
435.8
566.9
1,002.7
78.0
135.1
945.6
1,080.7
Appalachian Basin
Mountain View (WV)
13,200
—
0.5
6.3
2.1
4.5
6.6
0.2
1.7
5.1
6.8
Penn Ridge (PA)
12,500
—
—
78.0
21.9
53.2
75.1
2.9
78.0
—
78.0
Region Total
—
0.5
84.3
24.0
57.7
81.7
3.1
79.7
5.1
84.8
Total
5.1
39.8
1,120.6
459.8
624.6
1,084.4
81.1
214.8
950.7
1,165.5
% of Total
0.4%
3.4%
96.1%
39.5%
53.6%
93.0%
7.0%
18.4%
81.6%
100.0%
(1) Combined resources are defined as measured plus indicated resources.
At December 31, 2021, we had approximately 1.165 billion tons of coal mineral resources. Tonnages are reported on a clean recoverable basis with pricing based on available third party forecasts and historical pricing adjusted for quality at the end of 2021 ranging from $36.00 to $67.00 per short ton, which are the prices used by RESPEC to estimate the amount of coal mineral resources. All resources are classified as underground mineable in the exploration stage.
Coal Mineral Reserves
Our reserves are assigned to our active operations and are (1) currently in production, (2) economically viable, and (3) meet the other requirements to be considered reserves as defined by the SEC.
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The following table sets forth coal mineral reserve information, exclusive of the coal mineral resources above, at December 31, 2021, about our coal operations:
Heat
Content (Btus
Pounds SO2 per MMBtu
Classification
Ownership
Reserves (tons in millions)
per pound)
<1.2
1.2-2.5
>2.5
Proven
Probable
Owned
Leased
Total
Illinois Basin Operations
Warrior (KY)
12,300
—
—
77.1
61.4
15.7
18.7
58.4
77.1
River View (KY)
11,450
—
—
214.6
117.8
96.8
62.0
152.6
214.6
Hamilton County (IL)
11,650
—
—
128.5
57.6
70.9
22.5
106.0
128.5
Gibson (South) (IN)
11,500
0.7
12.4
39.5
44.2
8.4
18.3
34.3
52.6
Region Total
0.7
12.4
459.7
281.0
191.8
121.5
351.3
472.8
Appalachian Basin Operations
MC Mining (KY)
12,800
11.9
1.0
—
9.1
3.8
—
12.9
12.9
Mountain View (WV)
13,200
—
4.2
3.5
6.4
1.3
—
7.7
7.7
Tunnel Ridge (WV)
12,600
—
—
53.7
28.6
25.1
—
53.7
53.7
Region Total
11.9
5.2
57.2
44.1
30.2
—
74.3
74.3
Total
12.6
17.6
516.9
325.1
222.0
121.5
425.6
547.1
% of Total
2.3%
3.2%
94.5%
59.4%
40.6%
22.2%
77.8%
100.0%
On December 31, 2021, we had approximately 547.1 million tons of coal mineral reserves. Tonnages are reported on a clean recoverable basis with pricing based on available third party forecasts and historical pricing adjusted for quality at the end of 2021 ranging from $36.00 to $67.00 per short ton, which are the prices used by RESPEC to estimate the amount of coal mineral reserves. All reserves are classified as underground mineable in the production stage.
Mining Operations
The following table sets forth production and other data about our mining operations:
Tons Produced
Operations
Location
2021
2020
2019
Transportation
Equipment
(in millions)
Illinois Basin Operations
Dotiki (1)
Kentucky
—
—
1.3
CSX, PAL, truck, barge
CM
Warrior
Kentucky
4.1
3.6
3.7
CSX, NS, PAL, truck, barge
CM
River View
Kentucky
9.9
9.4
11.3
Truck, barge
CM
Hamilton County
Illinois
4.9
2.6
5.9
CSX, EVW, NS, barge
LW, CM
Gibson (North) (1)
Indiana
—
—
1.8
CSX, NS, truck, barge
CM
Gibson (South)
Indiana
3.3
2.3
5.5
CSX, NS, truck, barge
CM
Region Total
22.2
17.9
29.5
Appalachian Basin Operations
MC Mining/Excel
Kentucky
1.3
0.5
1.0
CSX, truck, barge
CM
Mountain View
West Virginia
1.5
1.8
2.1
CSX, truck
LW, CM
Tunnel Ridge
West Virginia
7.2
6.8
7.4
CSX, NS, barge
LW, CM
Region Total
10.0
9.1
10.5
TOTAL
32.2
27.0
40.0
(1) Closed
CSX
-
CSX Railroad
EVW
-
Evansville Western Railroad
NS
-
Norfolk Southern Railroad
PAL
-
Paducah & Louisville Railroad
CM
-
Continuous Miner
LW
-
Longwall
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Individual Property Disclosures
We consider the following properties to be material based on multiple factors including, but not limited to, the property’s contribution to our overall business and financial condition. Please see Coal Mineral Resources and Coal Mineral Reserves sections above for information about the coal mineral resources and reserves held by these material properties. In addition to the following information, Technical Report Summaries for these material properties with additional information are included as exhibits to this Annual Report on Form 10-K.
Henderson/Union
The Henderson/Union Resources are located in Henderson and Union counties, Kentucky at 37°44'30"N, -87°46'07"W and currently have control in over 1,600 tracts encompassing over 127,000 acres. The property is controlled through both fee ownership and leases of the coal. Existing and proposed facilities are on controlled land. The coal mineral resources are controlled by Alliance Resource Properties. The base leases are with private owners and WKY CoalPlay or its subsidiaries, which are related parties. See "Item 8. Financial Statements and Supplementary Data — Note 21 – Related Party Transactions" for more information about our WKY CoalPlay transactions. These base leases generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:
Major Roads: Interstates 69 and US-60,
Railroads: None,
Airport: Evansville Regional Airport (EVV),
Town: Morganfield,
Docks: River View, Hamilton 1, UC Processing, on the Ohio River,
Water: Local municipalities and mine sources,
Electricity: Kentucky Utilities (KU),
Personnel: Regional.
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Description
The potential underground mine(s) would utilize room-and-pillar methods operating a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill possible permitting and development requirements. Multiple access points are available for development. Access is available from the active River View mine, which began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Access at the Hamilton and UC Coal, LLC sites are considered "brownfield" developments. Though some facilities and permitting are in place, significant upgrades to existing infrastructure and new construction would be needed to bring them into good working order that meets industry standards. The property associated with Henderson/Union has no book value as of December 31, 2021 but does have outstanding advanced royalties with WKY CoalPlay or its subsidiaries. See "Item 8. Financial Statements and Supplementary Data — Note 21 – Related Party Transactions" for more information about advanced royalties that Henderson/Union has with WKY CoalPlay.
History
The Henderson/Union property contains resources in four seams, the West Kentucky No. 11 (WKY11), the West Kentucky No. 9 (WKY9), the West Kentucky No. 7 (WKY7), and the West Kentucky No. 6 (WKY6). Island Creek Coal Company ("Island Creek") operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody Coal Corporation ("Peabody") and Patriot Coal Corporation ("Patriot") operated mines in the area and controlled a portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 and Uniontown #9 mines. Island Creek also operated the Hamilton #1 and #2 mines in Kentucky. Peabody and later Patriot operated the Camp complex and Highland mines to the southeast and east. Both the WKY9 and WKY11 seams were mined at these locations. No mining has occurred on the property in the WKY7 or WKY6 seams.
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Approximately 1,050 exploration holes have been drilled within and adjacent to the Henderson/Union area to assess thickness and mineability of the WKY11, WKY9, WKY7, and WKY6 seams. From these holes, over 410 samples were collected and analyzed to determine coal quality characteristics. Also, over 150 oil/gas well geophysical logs drilled by various companies have been interpreted to supplement the exploration drilling. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high sulfur, thermal utility market.
Encumbrances
Our revolving credit facility is secured by, among other things, liens against certain Henderson/Union surface properties and coal leases. Documentation of such liens is of record in the Offices of the Henderson and Union County Clerks. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our revolving credit facility.
The Kentucky Department of Natural Resources ("KYDNR"), Division of Mine Permits ("DMP") is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining.
Geology and Reserves
Henderson/Union contains coal resources in four seams ranging in depths from about 100 to 750 feet. The table below summarizes mineral resources as of December 31, 2021 using a cut off thickness of 4.00 feet:
Quality, Washed, Dry Basis
% Recovery
Resources
Tons (millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Prep Plant
Henderson/Union
Measured Mineral Resources
175.4
4.71
8.15
3.01
13,241
4.54
87.10
54.76
Indicated Mineral Resources
286.0
4.62
8.23
2.86
13,242
4.33
88.03
53.77
Combined Mineral Resources
461.4
4.66
8.20
2.92
13,241
4.41
87.67
54.14
Inferred Mineral Resources
62.1
4.48
8.16
2.60
13,321
3.91
89.66
52.14
River View
River View is located in Union County, Kentucky at 37°45'37"N, -87°56'42"W and currently has approximately 54,250 underground acres permitted. The mine is controlled through both fee ownership and leases of the coal. The coal mineral reserves are leased or held for lease to River View by Alliance Resource Properties. River View either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. The coal mineral reserves currently assigned to and controlled by River View are pursuant to a 2009 Coal Lease and Sublease Agreement from Alliance Resource Properties. The base leases are with private owners and generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:
Major Roads: Interstates 69 and US-60,
Railroads: None,
Airport: Evansville Regional Airport (EVV),
Town: Morganfield,
Docks: River View on the Ohio River,
Water: Uniontown Water Department and mine sources,
Electricity: Kentucky Utilities (KU),
Personnel: Regional.
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Description
The underground mine is currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for River View as of December 31, 2021 was $199.3 million.
History
Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and controlled a smaller portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 and Uniontown #9 mines to the west of River View. Island Creek also operated the Hamilton #1 and #2 mines to the southwest. Peabody and later Patriot operated the Camp complex and Highland mines to the southeast and east. Both the WKY9 and WKY11 seams were mined at these locations.
Approximately 630 exploration holes penetrate the WKY11 seam and about 450 holes penetrate the WKY9 seam within and adjacent to the River View resource/reserve area to assess thickness, quality, and mineability of the seams. River View has drilled over 80 holes on the property to supplement the historic data. Also, over 300 oil/gas well geophysical logs drilled by various companies have been interpreted to supplement the exploration drilling.
Encumbrances
Our revolving credit facility is secured by, among other things, liens against certain River View surface properties and coal leases. Documentation of such liens is of record in the Office of the Union County Clerk. Please read "Item 8.
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Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our revolving credit facility.
Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Union County Clerk. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our accounts receivable securitization facility.
The KYDNR, DMP is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities, and other incidental activities have been obtained and remain in good standing.
Geology and Reserves
River View extracts coal underground from the West Kentucky No. 11 and No. 9 seams at depths ranging from 200 to 500 feet. The table below summarizes mineral reserves as of December 31, 2021 using a cut off thickness of 4.00 feet:
Quality, Washed, Dry Basis
% Recovery
Reserves
Tons (millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Prep Plant
River View
Proven Mineral Reserves
117.8
4.69
7.57
3.13
13,284
4.71
86.46
53.80
Probable Mineral Reserves
96.8
4.60
7.71
3.11
13,235
4.71
86.24
52.19
Total Mineral Reserves
214.6
4.65
7.63
3.12
13,262
4.71
86.36
53.07
The River View mine had 223.3 million tons of coal mineral reserves at the end of 2020. The year over year reconciliation is as follows:
River View Yearly Reserve Reconciliation
(millions)
Tons as of December 31, 2020
223.3
Production
(9.9)
Mineral Acquisition / Deletion
0.9
Normal Course Adjustments
0.3
Tons as of December 31, 2021
214.6
Normal course adjustments are associated with numerous slight changes in the geologic model.
Hamilton
Hamilton, a longwall mine located in Hamilton County, Illinois at 38°10'12”N, -88°36'47"W, currently has approximately 10,500 underground acres and 1,300 surface acres permitted. The mine property is controlled through both fee ownership and leases of the coal. The coal mineral reserves and resources are leased or held for lease to Hamilton by Alliance WOR Properties, LLC ("Alliance WOR Properties"), a subsidiary of Alliance Resource Properties. Hamilton either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. Hamilton (or Alliance WOR Properties) currently controls approximately 53,348 acres of coal mineral reserves and resources and subsidence rights, and 1,400 acres of surface properties. The underlying base coal leases are with private owners and are comprised of a large number of leases originally taken by AMAX Coal Company and Old Ben Coal Company ("Old Ben") in the mid to late 1970’s and early 1980’s (the "Old Ben Leases"), leases acquired by Consolidation Coal Company in the late 1980’s (the "Consol Leases"), and subsequent leases taken directly by White Oak Resources, LLC or affiliated companies and/or Alliance WOR Properties. Local infrastructure is as follows:
Major Roads: Interstates 64,
Railroads: CSX and EVW,
Airport: Evansville Regional Airport (EVV),
Towns: McLeansboro and Mt. Vernon,
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Docks: Mount Vernon on the Ohio River,
Water: Hamilton County Water District and mine sources,
Electricity: Wayne-White Electric Co-op (WWEC),
Personnel: Regional.
Description
The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Hamilton as of December 31, 2021 was $347.1 million.
History
There were no previous operations on the Hamilton reserves property prior to our predecessor, White Oak Resources LLC, who began construction of the mine in 2011.
Over 180 exploration holes have been drilled in the Hamilton reserve area by other companies to assess thickness, quality, and mineability of the Herrin and Harrisburg seams. White Oak Resources LLC drilled over 90 holes in the reserve area starting in 2008. Also, over 70 oil/gas well geophysical logs drilled by various companies have been interpreted to supplement the exploration drilling.
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Encumbrances
Our revolving credit facility is secured by, among other things, liens against certain Hamilton surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Hamilton County Clerk. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our revolving credit facility.
The Consol Leases are encumbered by an overriding royalty payable to Sustainable Conservation, Inc. ("Sustainable") in the amount of the greater of $0.25 per ton or 0.75% of the average sales realization price received per ton, which sums can be credited against approximately $481,000.00 previously paid to Sustainable for the assignment of the Consol Leases.
The Illinois Department of Natural Resources, Land Reclamation Division is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities and other incidental activities have been obtained and remain in good standing.
Geology and Reserves
Hamilton extracts coal underground from the Herrin (Illinois No.6) seam at depths ranging from 900 to 1100 feet. The table below summarizes mineral reserves as of December 31, 2021 using a cut off thickness of 4.00 feet:
Quality, Washed, Dry Basis
% Recovery
Reserves
Tons (millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Prep Plant
Hamilton County
Proven Mineral Reserves
57.6
6.37
8.04
2.81
13,407
4.20
86.71
53.85
Probable Mineral Reserves
70.9
6.63
7.99
2.83
13,423
4.21
86.82
57.34
Total Mineral Reserves
128.5
6.52
8.01
2.82
13,416
4.21
86.77
55.78
The Hamilton mine had 125.0 million tons of coal mineral reserves at the end of 2020. The year over year reconciliation is as follows:
Hamilton County Yearly Reserve Reconciliation
(millions)
Tons as of December 31, 2020
125.0
Production
(4.9)
Mineral Acquisition / Deletion
1.0
Mine Plan Adjustment
6.7
Normal Course Adjustments
0.7
Tons as of December 31, 2021
128.5
Normal course adjustments are associated with numerous slight changes in the geologic model.
Gibson South
Gibson South is located in Gibson County, Indiana at 38°18'22"N, 87°42'30"W and currently has approximately 23,350 underground acres permitted. The mine property is controlled through both fee ownership and leases of the coal. Gibson South holds rights to approximately 21,600 gross acres of coal. Leases generally have an initial term with automatic extensions for as long as mining operations are conducted within a described area. Local infrastructure is as follows:
Major Roads: Interstates 69 and 64,
Railroads: CSX and NS,
Airport: Evansville Regional Airport (EVV),
Town: Princeton,
Docks: Mount Vernon on the Ohio River,
Water: Gibson Water, Inc. and well water,
Electricity: Western Indiana Energy REMC,
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Personnel: Regional.
Description
The underground mine is currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Gibson South as of December 31, 2021 was $118.8 million.
History
In November 1997, pursuant to (a) Assignment of Underground Coal Leases, (b) Partial Assignment of Underground Coal Leases and (c) Special Corporate Warranty Deed, Old Ben conveyed to MAPCO Land & Development Corporation various coal leases and fee coal interests within a large property boundary located in Gibson County, Indiana. MAPCO Land & Development Corporation changed its name to MAPCO Coal Land & Development Corporation, and MAPCO Coal Land & Development Corporation merged into Alliance Properties, LLC (“Alliance Properties”) effective August 4, 1999.
Old Ben ran large exploration programs across multiple years to examine thickness, mineability, and quality, drilling a total of 137 holes. Another 73 holes were drilled in the western area of the property by owners of an adjacent mine.
After the original Old Ben acquisition, Alliance Properties and Gibson County Coal continued to acquire additional coal leases and fee coal interests in the area. In addition, beginning in or around 2006, the leases originally acquired from Old Ben began to expire by their terms, and Alliance Properties/Gibson County Coal began a program of either amending the expiring leases or entering into new, direct leases with the coal owners. Alliance Properties merged into Gibson County Coal on February 19, 2018.
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Encumbrances
Our revolving credit facility is secured by, among other things, liens against certain Gibson County Coal surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Recorder of Gibson County, Indiana. Please read "Item 8. Financial Statements and Supplementary Data – Note 8 – Long-term Debt" for more information on our revolving credit facility.
Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Recorder of Gibson County, Indiana. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our accounts receivable securitization facility.
The Indiana Department of Natural Resources, Division of Reclamation is responsible for oversight of active coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation, and related facilities and other incidental activities have been obtained and remain in good standing.
Geology and Reserves
Gibson South extracts coal underground from the Springfield (Indiana No.5) seam at depths ranging from 450 to 650 feet. The table below summarizes mineral reserves as of 12/31/21 using a cut off thickness of 4.00 feet:
Quality, Washed, Dry Basis
% Recovery
Reserves
Tons (millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Prep Plant
Gibson South
Proven Mineral Reserves
44.2
6.10
6.97
1.92
13,506
2.84
95.05
74.87
Probable Mineral Reserves
8.4
5.46
7.91
2.33
13,349
3.49
93.39
72.12
Total Mineral Reserves
52.6
6.00
7.12
1.98
13,482
2.94
94.79
74.44
The Gibson South mine had 54.7 million tons of coal mineral reserves at the end of 2020. The year over year reconciliation is as follows:
Gibson South Yearly Reserve Reconciliation
(millions)
Tons as of December 31, 2020
54.7
Production
(3.3)
Mineral Acquisition / Deletion
0.9
Normal Course Adjustments
0.3
Tons as of December 31, 2021
52.6
Normal course adjustments are associated with numerous slight changes in the geologic model.
Tunnel Ridge
Tunnel Ridge, located at 40°09’17" N, -80°39’26"W, is an underground longwall mine in the Pittsburgh No. 8 seam of coal, and currently has approximately 20,890 underground acres permitted. The mine property is controlled through both fee ownership and leases of the coal. The vast majority of the coal mined and to be mined by Tunnel Ridge is leased from the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation. Please read "Item 8. Financial Statements and Supplemental Data - Note 21 – Related Party Transactions" for additional information on this lease. Tunnel Ridge either owns or controls the surface properties upon which its facilities are located, including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. Local infrastructure is as follows:
Major Roads: Interstate 70,
Railroads: None,
Airport: Pittsburgh International Airport (PIT),
Town: Wheeling,
Docks: Tunnel Ridge on the Ohio River,
Water: Ohio County Water District and mine sources,
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Electricity: American Electric Power (AEP), West Penn Power (WPP)
Personnel: Regional.
Description
The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2010. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Tunnel Ridge as of December 31, 2021 was $238.8 million.
History
Valley Camp Coal Company ("Valley Camp") operated mines on the property prior to Tunnel Ridge's operations.
Valley Camp drilled 24 exploration holes in and adjacent to the reserve area to check thickness, quality, and mineability of the Pittsburgh No. 8 seam. Tunnel Ridge accounts for over 80 of the remaining holes. Also, Tunnel Ridge has collected over 600 channel samples to supplement the exploration drilling.
Encumbrances
Our revolving credit facility is secured by, among other things, liens against certain Tunnel Ridge surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our revolving credit facility.
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Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on our accounts receivable securitization facility.
Tunnel Ridge is located on the West Virginia / Pennsylvania State boundary, operating in each state. As such, regulatory requirements must be met pertaining to mining facilities located in each state.
For operations in West Virginia, the West Virginia Department of Environmental Protection ("WVDEP") is the regulatory authority over mining activities. Within the WVDEP, the Division of Mining and Reclamation is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.
For operations in Pennsylvania, the Pennsylvania Department of Environmental Protection (PADEP) is the regulatory authority over mining activities. Within the PADEP, the Bureau of District Mining Operations is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.
Geology and Reserves
Tunnel Ridge extracts coal underground from the Pittsburgh No.8 seam at depths ranging from 300 to 800 feet. The table below summarizes mineral reserves as of December 31, 2021 using a cut off thickness of 4.00 feet:
Quality, Washed, Dry Basis
% Recovery
Reserves
Tons (millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Prep Plant
Tunnel Ridge
Proven Mineral Reserves
28.6
6.89
8.12
3.32
13,685
4.86
69.21
51.90
Probable Mineral Reserves
25.1
7.02
8.23
3.47
13,650
5.09
67.87
52.69
Total Mineral Reserves
53.7
6.95
8.17
3.39
13,669
4.97
68.58
52.27
The Tunnel Ridge mine had 64.0 million tons of coal mineral reserves at the end of 2020. The year over year reconciliation is as follows:
Tunnel Ridge Yearly Reserve Reconciliation
(millions)
Tons as of December 31, 2020
64.0
Production
(7.2)
Mine Plan Adjustment
(3.1)
Tons as of December 31, 2021
53.7
Oil & Gas Reserves
Our mineral interests are primarily located in three basins, which are also our areas of focus for future development. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. At December 31, 2021, we had approximately 42,000 developed and undeveloped net acres held at a weighted average royalty of 17.0%. Our net acres standardized to 1/8th royalty equates to approximately 57,000 net royalty acres, including approximately 3,976 net royalty acres owned through our equity interest in AllDale III.
The following table presents our estimated net proved oil & gas reserves, including our share of reserves owned through our equity interest in AllDale III, as of December 31, 2021 based on the reserve report prepared by our internal engineering team. The reserve report has been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves included in the reserve report are located in the continental United States.
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As of December 31, 2021
Crude Oil
Natural Gas
Natural Gas Liquids
Total
(MBbl)
(MMcf)
(MBbl)
(MBOE) (2)
Estimated proved developed reserves
5,493
28,426
3,039
13,269
Estimated proved undeveloped reserves
1,353
4,126
578
2,618
Total estimated proved reserves (1)
6,846
32,552
3,617
15,887
(1) Proved reserves of approximately 1,285 MBOE were attributable to noncontrolling interests as of December 31, 2021.
(2) Natural gas reserve volumes are converted to BOE based on a 6:1 ratio: 6 Mcf of natural gas converts to one BOE.
Estimates of reserves as of December 31, 2021 were prepared using product prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2021. The average realized product prices weighted by production over the remaining lives of the properties are $63.57/Bbl for oil, $2.98/Mcf of natural gas and $21.13 per barrel of NGL. These prices are adjusted for energy content, associated average differential and transportation deducts by producing area to arrive at the net realized prices by product. For 2021, NGL prices averaged approximately 37% of the posted oil prices during the course of the year with an additional $3.49/Bbl deducted for transportation costs.
The following table summarizes our changes in proved undeveloped reserves (in MBOE):
Beginning balance, January 1, 2021
4,533
Sales of PUDs
(12)
Transfers of PUDs to estimated proved developed
(1,469)
Extensions and discoveries
971
Revisions of previous estimates
(1,405)
Ending balance, December 31, 2021
2,618
As a mineral interest owner we have no transparency into or control over our operators' investments and operational progress to convert PUDs to proved developed producing reserves. We do not incur any capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by our operators. As a result, during the year ended December 31, 2021, we did not have any expenditures to convert PUDs to proved developed producing reserves. PUDs that have not been developed within two years of permitting are reviewed and removed from proved reserves as necessary. As of December 31, 2021 approximately 16.48% of our total proved reserves were classified as PUDs.
Evaluation and Review of Reserves
Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.
Under SEC rules, proved reserves are those quantities of oil & gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a "high degree of confidence that the quantities will be recovered." All of our proved reserves as of December 31, 2021 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil & gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil & gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:
(1) performance-based methods,
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(2) volumetric-based methods and
(3) analogy.
These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production data. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.
To estimate economically recoverable proved reserves and related future net cash flows, our engineering team considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, and radioactivity logs.
Our 2021 year-end proved reserves were prepared by our internal engineering team. Our engineering team works to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Approximately 95% of our total 2021 year end proved reserve estimates were audited by NSAI. Our engineering team met with NSAI periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. Our engineering team provided historical information to NSAI for our properties, such as oil & gas production, well test data, and realized commodity prices. Our engineering team also provided ownership interest information with respect to our properties. Our internal petroleum engineer, primarily responsible for overseeing the petroleum reserves preparation, has over 20 years of engineering and operations experience in the oil & gas sector and a Bachelor of Science in Petroleum Engineering.
The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
● review and verification of historical data, which is based on actual production as reported by our operators;
● verification of property ownership by our land department;
● review of all our reported proved reserves semi-annually including the review of all significant reserve changes and proved undeveloped reserves additions by our internal petroleum engineer;
● internally prepared reserve estimates compared to reserves audit by NSAI;
● review of changes in reserves semi-annually by our internal petroleum engineer and by senior management; and
● no employee ' s compensation is tied to the amount of reserves booked.
NSAI, an independent third-party petroleum engineering firm, does not own an interest in any of our properties and is not employed on a contingent basis. When compared on a well-by-well basis, some of our estimates are greater and some are less than the NSAI estimates. NSAI is satisfied with our methods and procedures used to prepare the December 31, 2021 reserve estimates and future revenue, and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, prepared by us. NSAI's audit report with the respect to our proved reserve estimates as of December 31, 2021 is included as an exhibit to this Annual Report on Form 10-K.
NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
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Acreage Concentration
Our mineral interests, which include both proved reserves discussed above and unproved reserves, are primarily located in three basins, which are also our areas of focus for future operator development. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. Below is a chart reflecting our gross, net mineral and net royalty acreage associated with our mineral interests in each of our primary basins as of December 31, 2021.
Developed Acreage
Undeveloped Acreage
Gross
Net Mineral
Net Royalty
Gross
Net Mineral
Net Royalty
Basin
Permian Basin
249,660
5,345
6,930
525,983
14,574
19,431
Anadarko Basin
142,311
5,106
7,282
294,826
10,905
15,538
Williston Basin
113,579
1,834
2,399
113,437
1,803
2,369
Other
27,885
863
1,086
37,821
1,525
1,887
Total
533,435
13,148
17,697
972,067
28,807
39,225
Oil & Gas Production Prices and Production Costs
For the year ended December 31, 2021, 46.8% of our production and 70.0% of our oil & gas revenues were related to oil production and sales, respectively. The following table sets forth information regarding production of oil & gas and certain price and cost information for each of the periods indicated:
Year Ended December 31,
2021
2020
2019
Production:
Oil (MBbls)
825
948
741
Natural gas (MMcf)
3,490
3,635
3,664
Natural gas liquids (MBbls)
357
337
364
BOE (MBbls)
1,764
1,892
1,716
Average Realized Prices:
Oil (per Bbl)
$
66.84
$
39.04
$
54.30
Natural gas (per Mcf)
$
3.85
$
1.52
$
2.01
Natural gas liquids (per Bbl)
$
28.51
$
9.08
$
20.17
BOE (MBbls)
$
44.65
$
24.10
$
32.02
Unit cost per BOE:
Production and ad valorem taxes
$
4.46
$
2.64
$
4.82
Productive Wells
As of December 31, 2021, 6,572 gross productive horizontal wells and 4,167 gross productive vertical wells were located on the acreage in which we have a mineral interest. Of our productive horizontal wells, 965 are considered natural gas wells, while the remaining 5,607 primarily produce oil. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. We do not own any material working interests in any wells. Accordingly, we do not own any net wells.
Drilling Results
As a holder of mineral interests, we generally are not provided with information as to whether any wells drilled on the acreage associated with our mineral interests are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage associated with our mineral interests during the relevant period.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we are party to litigation matters incidental to the conduct of our business. It is the opinion of management that the ultimate resolution of our pending litigation matters will not have a material adverse effect on our
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financial condition, results of operation or liquidity. However, we cannot assure you that disputes or litigation will not arise or that we will be able to resolve any such future disputes or litigation in a satisfactory manner. The information under "General Litigation" and "Other" in "Item 8. Financial Statements and Supplementary Data—Note 22 – Commitments and Contingencies" is incorporated herein by this reference.
Litigation was initiated in November 2019 in the U.S. District Court for the Western District of Kentucky (Branson v. Webster County Coal, LLC et al.) against certain of our subsidiaries in which the plaintiffs allege violations of the Fair Labor Standards Act and Kentucky Wage and Hour Act due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. The plaintiffs seek class or collective action certification. A similar lawsuit was initiated in March 2020 in the U.S. District Court for the Eastern District of Kentucky (Brewer v. Alliance Coal, LLC, et al.). Collectively, the plaintiffs of these two lawsuits allege damages ranging from approximately $22.2 million to $143.7 million. Subsequently, four additional lawsuits making similar allegations were initiated against certain of our subsidiaries: filed March 4, 2021 in the Circuit Court for Hopkins County, Kentucky (Johnson v. Hopkins County Coal, LLC, et al.); filed April 6, 2021 in the U.S. District Court for the Northern District of West Virginia (Rettig v. Mettiki Coal WV, LLC, et al.); filed April 9, 2021 in the U.S. District Court for the Southern District of Illinois (Cates v. Hamilton County Coal, LLC, et al.); and filed April 13, 2021 in the U.S. District Court for the Southern District of Indiana (Prater v. Gibson County Coal, LLC, et al.). The plaintiffs in these cases seek to recover alleged compensatory, liquidated and/or exemplary damages for the alleged underpayment, and costs and fees that potentially may be recoverable under applicable law. We believe the claims made in these lawsuits are without merit and intend to defend the litigation vigorously. The litigation is in early stages. We do not believe this litigation will have a material adverse effect on our business, financial position or results of operations.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.
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PART II
ITEM 5.
MARKET FOR REGISTRANT ' S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The common units representing limited partners' interests are listed on the NASDAQ Global Select Market under the symbol "ARLP." The common units began trading on August 20, 1999. There were approximately 32,374 record holders of common units at December 31, 2021.
Available cash with respect to each quarter may, at the discretion of our general partner, be distributed to the limited partners as of a record date selected by the general partner. "Available cash," as defined in our partnership agreement, generally means, with respect to any quarter, all cash on hand at the end of each quarter, plus working capital borrowings after the end of the quarter, less cash reserves in the amount necessary or appropriate in the reasonable discretion of our general partner to (a) provide for the proper conduct of our business, (b) comply with applicable law or any debt instrument or other agreement of ours or any of our affiliates, and (c) provide funds for distributions to unitholders for any one or more of the next four quarters.
Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such information as set forth in "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" contained herein.
Unit Repurchase Program
On May 31, 2018, ARLP announced that the Board of Directors approved the establishment of a unit repurchase program authorizing ARLP to repurchase up to $100 million of its outstanding limited partner common units. The unit repurchase program is intended to enhance ARLP's ability to achieve its goal of creating long-term value for its unitholders and provides another means, along with quarterly cash distributions, of returning cash to unitholders. The program has no time limit and ARLP may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate ARLP to repurchase any dollar amount or number of units, and repurchases may be commenced or suspended from time to time without prior notice.
During the three months ended December 31, 2021, we did not repurchase and retire any units. Since inception of the unit repurchase program, we have repurchased and retired 5,460,639 units at an average unit price of $17.12 for an aggregate purchase price of $93.5 million. The remaining authorized amount for unit repurchases under this program is $6.5 million.
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ITEM 6. [ Reserved]
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
General
The following discussion of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included in "Item 8. Financial Statements and Supplementary Data" where you can find more detailed information in "Note 1 – Organization and Presentation" and "Note 2 – Summary of Significant Accounting Policies" regarding the basis of presentation supporting the following financial information.
Executive Overview
We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests located in strategic producing regions across the United States. We are currently the second-largest coal producer in the eastern United States with seven operating underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia, as well as a coal-loading terminal in Indiana. In addition to our mining operations, Alliance Resource Properties owns or leases coal mineral reserves and resources in the Illinois and Appalachia Basins that are (a) leased to our internal mining complexes or (b) near other internal and external coal mining operations. The oil & gas mineral interests we own are in premier oil & gas producing regions of the United States, primarily in the Permian, Anadarko and Williston Basins.
Our mining operations are located near many of the major eastern utility generating plants and on major coal hauling railroads in the eastern United States. Our River View and Tunnel Ridge mines and Mt. Vernon transloading facility are located on the Ohio River. As of December 31, 2021, we had approximately 547.1 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of these coal mineral reserves are owned or leased by Alliance Resource Properties, our land holding company. We believe we control adequate reserves to implement our currently contemplated mining plans. Please see "Item 1. Business—Coal Mining Operations" in our Annual Report on Form 10-K for the year ended December 31, 2021 for further discussion of our mines.
In 2021, we sold 32.3 million tons of coal and produced 32.2 million tons. Of the 32.3 million tons sold, approximately two-thirds was leased from Alliance Resource Properties. The coal we sold in 2021 was approximately 14.2% low-sulfur coal, 50.3% medium-sulfur coal and 35.5% high-sulfur coal. Based on market expectations, we classify low-sulfur coal as coal with a sulfur content of less than 1.5%, medium-sulfur coal as coal with a sulfur content of 1.5% to 3%, and high-sulfur coal as coal with a sulfur content of greater than 3%. The Btu content of our coal ranges from 11,450 to 13,200. In 2021, approximately 87.7% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices.
During 2021, approximately 81.6% of our tons sold were purchased by U.S. electric utilities and 12.5% were sold into the international markets through brokered transactions. The balance of tons sold were to third-party resellers and industrial consumers. Although some utility customers continue to favor a shorter-term contracting strategy, in 2021 we have continued to see several domestic utilities in the market seeking significant coal supply commitments for multi-year terms. Long-term sales contracts contribute to our stability and profitability by providing greater predictability of sales volumes and sales prices. In 2021, approximately 77.9% of our sales tonnage was sold under long-term sales contracts.
On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders for a purchase price of $31.0 million in the Boulders Acquisition. This acquisition enhances our ownership position in the Permian Basin and furthers our business strategy to grow our Oil & Gas Royalties segment. Following the Boulders Acquisition, we hold approximately 57,000 net royalty acres in premier oil & gas basins including our investment in AllDale III. For more information, please read "Item 8. Financial Statement and Supplemental Data—Note 3 – Acquisitions" of this Annual Report on Form 10-K.
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Our results of operations could be impacted by variability in coal sales prices in addition to prices for items that are used in coal production such as steel, electricity and other supplies, unforeseen geologic conditions or mining and processing equipment failures and unexpected maintenance problems, and by the availability or reliability of transportation for coal shipments. Moreover, the mining regulatory environment in which we operate has grown increasingly stringent as a result of federal and state legislative and regulatory initiatives. Additionally, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal mineral reserves and resources, or find replacement buyers for coal under contracts with comparable terms to existing contracts. As outlined in "Item 1. Business—Environmental, Health, and Safety Regulations", a variety of measures taken by regulatory agencies in the United States and abroad in response to the perceived threat from climate change attributed to GHG emissions could substantially increase compliance costs for us and our customers and reduce demand for fossil fuels including coal which could materially and adversely impact our results of operations.
We are dependent on third-party operators for the exploration, development and production of our oil & gas mineral interests; therefore, the success and timing of drilling and development of our oil & gas mineral interests depend on a number of factors outside our control. Some of those factors include the operators' capital costs for drilling, development and production activities, the operators' ability to access capital, the operators' selection of counterparties for the marketing and sale of production and oil & gas prices in general, among others. The operations on the properties in which we hold oil & gas mineral interests are also subject to various governmental laws and regulations. Compliance with these laws and regulations could be burdensome or expensive for these operators and could result in the operators incurring significant liabilities, either of which could delay production and may ultimately impact the operators' ability and willingness to develop the properties in which we hold oil & gas mineral interests.
For additional information regarding some of the risks and uncertainties that affect our business and the industries in which we operate, see "Item 1A. Risk Factors".
Our principal expenses related to the production of coal are labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes in addition to capital required to maintain our current levels of production. We employ a totally union-free workforce. Many of the benefits of our union-free workforce are related to higher productivity and are not necessarily reflected in our direct costs. In addition, transportation costs, which are mostly borne by our customers, may be substantial and are often the determining factor in a coal consumer's contracting decision. The principal expenses related to our oil & gas minerals interests business are production and ad valorem taxes. For our coal royalty interests business, the principal expenses are royalty expenses and production and ad valorem taxes.
Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize unitholder returns by:
● expanding our operations by adding and developing mines and coal mineral reserves and resources in existing, adjacent or neighboring properties;
● extending the lives of our current mining operations through acquisition and development of coal mineral reserves and resources using our existing infrastructure;
● continuing to make productivity improvements to remain a low-cost producer in each region in which we operate;
● strengthening our position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services;
● developing strategic relationships to take advantage of opportunities within the coal and oil & gas industries and in other industries inside and outside of the MLP sector; and
● continuing to make investments in oil & gas mineral interests and coal royalty interests in various geographic locations within producing basins in the continental United States.
As of December 31, 2021, we had four reportable segments: Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an "all other" category referred to as Other, Corporate and Elimination. The two Coal Operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. The Oil & Gas Royalties reportable segment includes our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) basins. Our ownership in these basins includes approximately 57,000 net royalty acres, which provide us with diversified exposure to industry leading operators consistent with our general strategy to grow our oil & gas mineral interest business. We market our oil & gas mineral interests for lease to operators in those regions and generate royalty
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income from the leasing and development of those mineral interests. Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties, which are either a) leased to our mining complexes or (b) near our coal mining operations but not yet leased.
Beginning in the first quarter of 2021, we began to strategically view and manage our coal royalty activities separately from our coal operations since acquiring and managing a variety of royalty producing assets involve similar attributes. As a result, we restructured our reportable segments to better reflect this strategic view in how we manage our business and allocate resources. Periods prior to 2021 that are presented herein have been recast to include Alliance Resource Properties within our new Coal Royalties reportable segment with offsetting recast adjustments primarily to our coal operations reportable segments and to a lesser extent, our Other, Corporate and Elimination category. Eliminations reported in Other, Corporate and Elimination were also recast to reflect intercompany royalty revenues and offsetting intercompany royalty expense resulting from our new Coal Royalties reportable segment.
● Illinois Basin Coal Operations reportable segment includes currently operating mining complexes (a) the Gibson County Coal mining complex, which includes the Gibson South mine, (b) the Warrior mining complex, (c) the River View mining complex and (d) the Hamilton mining complex. The Illinois Basin Coal Operations reportable segment also includes our Mt. Vernon coal-loading terminal in Indiana which currently operates on the Ohio River.
The Illinois Basin Coal Operations reportable segment also includes Mid-America Carbonates, LLC ("MAC") and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, which ceased production in December 2016, (d) the Hopkins County Coal, LLC mining complex, which ceased production in April 2016, and (e) the Sebree mining complex, which ceased production in November 2015. The non-operating mining complexes are in various stages of reclamation.
● Appalachia Coal Operations reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining mining complex. The Mettiki mining complex includes Mettiki Coal (WV)'s Mountain View mine and Mettiki Coal (MD)'s preparation plant.
● Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale III and Cavalier Minerals. AR Midland acquired its mineral interests in the Wing Acquisition and Boulders Acquisition. Please read "Item 8. Financial Statements and Supplementary Data — Note 3 – Acquisitions" and " — Note 13 – Investments" of this Annual Report on Form 10-K for more information on the Wing Acquisition and Boulders Acquisition, and AllDale III, respectively.
● Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties that are (a) leased to certain of our mining complexes in both the Illinois Basin Coal Operations and Appalachia Coal Operations reportable segments or (b) located near our operations and external mining operations. Approximately two thirds of the coal sold by our Coal Operations' mines is leased from our Coal Royalties entities.
● Other, Corporate and Elimination includes marketing and administrative activities, the Matrix Group, Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding, LLC ("AROP Funding") and Alliance Resource Finance Corporation ("Alliance Finance"). Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" of this Annual Report on Form 10-K for more information on AROP Funding and Alliance Finance.
How We Evaluate Our Performance
Our management uses a variety of financial and operational measurements to analyze our performance. Primary measurements include the following: (1) raw and saleable tons produced per unit shift; (2) coal sales price per ton; (3) BOE sold; (4) price per BOE; (5) coal royalty tons sold; (6) coal royalty revenue per ton; (7) Segment Adjusted EBITDA Expense per ton; (8) EBITDA; and (9) Segment Adjusted EBITDA.
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Raw and Saleable Tons Produced per Unit Shift. We review raw and saleable tons produced per unit shift as part of our operational analysis to measure the productivity of our operating segments, which is significantly influenced by mining conditions and the efficiency of our preparation plants. Our discussion of mining conditions and preparation plant costs are found below under "— Analysis of Historical Results of Operations " and therefore provides implicit analysis of raw and saleable tons produced per unit shift.
Coal Sales Price per Ton. We define coal sales price per ton as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis.
Oil & gas BOE sold . We monitor and analyze our BOE sales volumes from the various basins that comprise our portfolio of mineral interests. We also regularly compare projected volumes to actual volumes reported and investigate unexpected variances.
Price per BOE. We define price per BOE as total oil & gas royalties divided by BOE produced. We review price per BOE to evaluate performance against budget and for trend analysis.
Coal Royalty Tons sold . We monitor and analyze our coal royalty sales volumes from our various mining subsidiaries for coal leased by Alliance Resource Properties for consistency with our Coal Operations segments and for trend analysis.
Coal Royalty Revenue per Ton. We define coal royalty revenue per ton as total coal royalties divided by royalty tons sold. We review coal royalty revenue per ton to evaluate consistency with our Coal Operations segments and for trend analysis.
Segment Adjusted EBITDA Expense per Ton. We define Segment Adjusted EBITDA Expense per ton (a non-GAAP financial measure) as the sum of operating expenses, coal purchases and other expense divided by total tons sold. We review Segment Adjusted EBITDA Expense per ton for cost trends.
EBITDA. We define EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We believe that the presentation of EBITDA provides useful information to investors regarding our performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.
Segment Adjusted EBITDA. We define Segment Adjusted EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, general and administrative expense, settlement gain, asset and goodwill impairments and acquisition gain. Management therefore is able to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.
Analysis of Historical Results of Operations
2021 Compared with 2020
Total revenues increased 18.2% to $1.57 billion, compared to $1.33 billion for 2020 primarily due to increased coal sale volumes and oil & gas prices, which increased 14.4% and 88.2%, respectively. Higher revenues, lower depreciation and $157.0 million of non-cash impairment charges in 2020, partially offset by higher Segment Adjusted EBITDA Expense, resulted in net income attributable to ARLP of $178.2 million for 2021 compared to a net loss attributable to ARLP of $129.2 million for 2020. In general, results from coal operations and oil & gas royalties for 2021 were significantly improved compared to 2020, which was impacted by reduced global energy demand and weak commodity prices as a result of lockdown measures imposed in response to the COVID-19 pandemic.
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Year Ended December 31,
Year Ended December 31,
2021
2020
2021
2020
(in thousands)
(per ton/BOE sold)
Coal - Tons sold
32,268
28,212
N/A
N/A
Coal - Tons produced
32,207
26,990
N/A
N/A
Coal - Coal sales
$
1,386,923
$
1,232,272
$
42.98
$
43.68
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
975,839
$
881,006
$
30.24
$
31.23
Oil & Gas Royalties - BOE sold
1,663
1,792
N/A
N/A
Oil & Gas Royalties - Royalties (3)
$
74,988
$
42,912
$
45.08
$
23.95
Coal Royalties - Tons sold
20,247
18,863
N/A
N/A
Coal Royalties - Intercompany royalties
$
51,402
$
42,112
$
2.54
$
2.23
(1) For a definition of Segment Adjusted EBITDA Expense and related reconciliation to its comparable GAAP financial measure, please see below under "—Reconciliation of non-GAAP 'Segment Adjusted EBITDA Expense' to GAAP 'Operating Expenses.'"
(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding expenses of our Oil & Gas Royalties segment and is adjusted for intercompany transactions with our Coal Royalties segment.
(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal sales . Coal sales increased $154.7 million or 12.6% to $1.39 billion for 2021 from $1.23 billion for 2020. The increase was attributable to a volume variance of $177.2 million resulting from increased tons sold partially offset by a negative price variance of $22.5 million due to lower average coal sales prices. Tons sold increased 14.4% to 32.3 million tons in 2021 due to improved coal demand and increased export shipments. Primarily due to the expiration of higher priced contract shipments, coal sales price realizations declined 1.6% in 2021 to $42.98 per ton sold, compared to $43.68 per ton sold during 2020. Production volumes increased by 19.3% in 2021, reflecting the temporary idling and scaling back of production at certain mines during 2020 in response to weak market conditions resulting from the pandemic.
Coal - Segment Adjusted EBITDA Expense . Segment Adjusted EBITDA Expense for our coal operations increased 10.8% to $975.8 million, as a result of higher coal sales volumes. On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations decreased 3.2% in 2021 to $30.24 per ton sold, compared to $31.23 per ton in 2020, primarily due to increased volumes lowering fixed costs per ton, a favorable sales mix from our lower cost mines and the impact of ongoing expense control and efficiency initiatives at all of our mining operations in addition to other cost decreases which are discussed below by category:
● Labor and benefit expenses per ton produced, excluding workers' compensation, decreased 11.3% to $9.53 per ton in 2021 from $10.75 per ton in 2020. The decrease of $1.22 per ton was primarily due to increased volumes at our Illinois Basin mines where production was temporarily idled in 2020 in response to weak market conditions resulting from the pandemic.
● Workers' compensation expenses per ton produced decreased to $0.38 per ton in 2021 from $0.59 per ton in 2020. The decrease of $0.21 per ton produced resulted from increased production and refunds received in 2021 on assessments paid to the state of Kentucky in prior years, partially offset by unfavorable workers' compensation accrual adjustments in 2021 primarily due to unfavorable changes in claims development.
● Maintenance expenses per ton produced decreased 11.2% to $2.77 per ton in 2021 from $3.12 per ton in 2020. The decrease of $0.35 per ton produced was primarily due to increased production volumes.
Segment Adjusted EBITDA Expense decreases above were partially offset by the following increase:
● Material and supplies expenses per ton produced increased 4.9% to $10.50 per ton in 2021 from $10.01 per ton in 2020. The increase of $0.49 per ton produced primarily reflects increases of $0.79 per ton for roof support, $0.21 per ton for contract labor used in the mining process and $0.17 per ton in longwall subsidence expense primarily at our Tunnel Ridge operation, partially offset by decreases of $0.30 per ton for outside expenses used in the mining processes and $0.14 per ton for environmental and reclamation expenses other than longwall subsidence.
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Oil & gas royalties . Oil & gas royalty revenues increased to $75.0 million in 2021 compared to $42.9 million for 2020. The increase of $32.1 million was primarily due to significantly higher sales price realizations per BOE.
General and administrative. General and administrative expenses for 2021 increased to $70.2 million compared to $59.8 million in 2020. The increase of $10.4 million was primarily due to higher incentive compensation expenses.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased to $261.4 million for 2021 compared to $313.4 million for 2020 primarily as a result of increased mine life estimates for certain mines and reduced depreciation associated with a) coal inventory changes, b) certain mines closed prior to 2021 and c) lower BOE volumes.
Asset impairments. During 2020, we recorded $25.0 million of non-cash asset impairment charges due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment and greenfield coal mineral reserves and resources as a result of weakened coal market conditions. Please read "Item 8. Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments."
Goodwill impairment. During 2020, we recorded a $132.0 million non-cash goodwill impairment charge associated with our Hamilton mine, primarily as the result of reduced expected production volumes due to weakened coal market conditions and low energy demand resulting in part from the COVID-19 pandemic. Please read "Item 8. Financial Statements and Supplementary Data— Note 5 – Goodwill Impairment."
Transportation revenues and expenses . Transportation revenues and expenses were $69.6 million and $21.1 million for 2021 and 2020, respectively. The increase of $48.5 million was primarily attributable to increased average third-party transportation rates in 2021 and increased coal shipments to international markets for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.
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Segment Information . Our 2021 Segment Adjusted EBITDA increased $102.8 million, or 23.0%, to $549.3 million from 2020 Segment Adjusted EBITDA of $446.5 million. Segment Adjusted EBITDA, tons sold, coal sales, other revenues, Segment Adjusted EBITDA Expense, oil & gas royalties, BOE volume, coal royalties and coal royalties tons sold by segment are as follows:
Year Ended December 31,
2021
2020
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
$
265,292
$
213,876
$
51,416
24.0
%
Appalachia Coal Operations
172,601
171,362
1,239
0.7
%
Oil & Gas Royalties
68,774
39,773
29,001
72.9
%
Coal Royalties
33,202
23,968
9,234
38.5
%
Other, Corporate and Elimination (2)
9,383
(2,490)
11,873
(1)
Total Segment Adjusted EBITDA (3)
$
549,252
$
446,489
$
102,763
23.0
%
Coal - Tons sold
Illinois Basin Coal Operations
22,264
19,113
3,151
16.5
%
Appalachia Coal Operations
10,004
9,099
905
9.9
%
Total tons sold
32,268
28,212
4,056
14.4
%
Coal sales
Illinois Basin Coal Operations
$
873,930
$
755,208
$
118,722
15.7
%
Appalachia Coal Operations
512,993
477,064
35,929
7.5
%
Total coal sales
$
1,386,923
$
1,232,272
$
154,651
12.6
%
Other revenues
Illinois Basin Coal Operations
$
4,666
$
1,932
$
2,734
141.5
%
Appalachia Coal Operations
3,940
14,954
(11,014)
(73.7)
%
Oil & Gas Royalties
2,197
229
1,968
(1)
Coal Royalties
69
105
(36)
(34.3)
%
Other, Corporate and Elimination
27,586
14,596
12,990
89.0
%
Total other revenues
$
38,458
$
31,816
$
6,642
20.9
%
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
$
613,303
$
543,264
$
70,039
12.9
%
Appalachia Coal Operations
344,332
320,656
23,676
7.4
%
Oil & Gas Royalties
9,943
4,106
5,837
142.2
%
Coal Royalties
18,269
18,249
20
0.1
%
Other, Corporate and Elimination (2)
(33,198)
(25,026)
(8,172)
(32.7)
%
Total Segment Adjusted EBITDA Expense
$
952,649
$
861,249
$
91,400
10.6
%
Oil & Gas Royalties
Volume - BOE (4)
1,663
1,792
(129)
(7.2)
%
Oil & gas royalties
$
74,988
$
42,912
$
32,076
74.7
%
Coal Royalties
Volume - Tons sold (5)
$
20,247
18,863
$
1,384
7.3
%
Intercompany coal royalties
51,402
$
42,112
9,290
22.1
%
(1) Percentage change not meaningful.
(2) Other, Corporate and Elimination includes the elimination of intercompany coal royalty revenues and expenses between our Coal Royalties Segment and our Coal Operations Segments in addition to the expenses for the other miscellaneous activities included in this category.
(3) For a definition of Segment Adjusted EBITDA and related reconciliation to comparable GAAP financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)."
(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
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(5) Represents tons sold by our Coal Operations Segments associated with coal mineral reserves leased from our Coal Royalties Segment.
Illinois Basin Coal Operations – Segment Adjusted EBITDA increased 24.0% to $265.3 million in 2021 from $213.9 million in 2020. The increase of $51.4 million was primarily attributable to higher coal sales, which increased 15.7% to $873.9 million in 2021 from $755.2 million in 2020. The increase of $118.7 million in coal sales primarily reflects increased sales volumes, which rose 16.5% compared to 2020 due to improved coal demand and increased export volumes reflecting the continued economic recovery from the COVID-19 pandemic. Increased expenses resulting from higher coal sales volumes, partially offset by ongoing cost control and efficiency initiatives, contributed to higher Segment Adjusted EBITDA Expense of $613.3 million in 2021 compared to $543.3 million in 2020. Segment Adjusted EBITDA Expense per ton decreased 3.1% to $27.55 from $28.42 per ton sold in 2020 primarily as a result of increased volumes where production was temporarily idled and scaled back in 2020 in response to weak market conditions resulting from the pandemic. A favorable sales mix from our lower cost mines in 2021 and the impact of ongoing expense control and efficiency initiatives at all of our mining operations in the region also contributed to the decrease. In addition, also see certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Appalachia Coal Operations – Segment Adjusted EBITDA increased to $172.6 million for 2021 from $171.4 million in 2020. The increase of $1.2 million was primarily attributable to higher coal sales, partially offset by lower contract buy-out revenues during 2021. Coal sales increased 7.5% to $513.0 million in 2021 compared to $477.1 million in 2020 as a result of increased sales volumes, partially offset by lower price realizations. Tons sold increased 9.9% in 2021 compared to 2020 due to increased sales volumes at our Tunnel Ridge and MC Mining operations resulting from improved market conditions. Coal sales price per ton sold in 2021 decreased 2.2% compared to 2020 primarily due to the expiration of higher priced contract shipments. Segment Adjusted EBITDA Expense increased 7.4% in 2021 compared to 2020 due to increased coal sales volumes, partially offset by decreased per ton costs. Segment Adjusted EBITDA Expense per ton decreased 2.3% to $34.42 compared to $35.24 per ton sold in 2020, as a result of increased sales volumes lowering fixed costs per ton, the full-year production benefit from MC Mining’s transition of mining operations to a new reserve area in the second half of 2020, ongoing expense control and efficiency initiatives and improved recoveries across the region. See also certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Oil & Gas Royalties – Segment Adjusted EBITDA increased 72.9% to $68.8 million for 2021 from $39.8 million in 2020. The increase of $29.0 million was primarily due to significantly higher sales price realizations per BOE, which more than offset lower volumes.
Coal Royalties – Segment Adjusted EBITDA increased 38.5% to $33.2 million for 2021 from $24.0 million in 2020. The increase of $9.2 million was a result of increased royalty tons sold and higher average coal royalty revenue per ton received from our mining subsidiaries.
Other, Corporate and Elimination – Segment Adjusted EBITDA increased by $11.9 million in 2021 due primarily to increased mining technology product sales from the Matrix Group.
2020 Compared with 2019
Total revenues decreased 32.3% to $1.33 billion for 2020 compared to $1.96 billion for 2019 primarily due to lower coal sales and transportation revenues resulting from weak market conditions and disruptions caused by the COVID-19 pandemic. These lower revenues and a non-cash goodwill impairment charge of $132.0 million partially offset by lower operating expenses, resulted in a net loss attributable to ARLP of $129.2 million for 2020 compared to net income attributable to ARLP of $399.4 million for 2019, which included a net gain of $170.0 million related to the AllDale Acquisition in 2019. Operating expenses and transportation expenses totaled $859.7 million and $21.1 million, respectively, for 2020 compared to $1.18 billion and $99.5 million, respectively, in 2019.
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Year Ended December 31,
Year Ended December 31,
2020
2019
2020
2019
(in thousands)
(per ton sold)
Coal - Tons sold
28,212
39,289
N/A
N/A
Coal - Tons produced
26,990
39,981
N/A
N/A
Coal - Coal sales
$
1,232,272
$
1,762,442
$
43.68
$
44.86
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
881,006
$
1,233,377
$
31.23
$
31.39
Oil & Gas Royalties - BOE sold
1,792
1,611
N/A
N/A
Oil & Gas Royalties - Royalties (3)
42,912
$
51,735
$
23.95
$
32.12
Coal Royalties - Tons sold
18,863
23,002
N/A
N/A
Coal Royalties - Intercompany royalties
42,112
$
57,737
$
2.23
$
2.51
(1) For a definition of Segment Adjusted EBITDA Expense and related reconciliation to its comparable GAAP financial measure, please see below under "—Reconciliation of non-GAAP 'Segment Adjusted EBITDA Expense' to GAAP 'Operating Expenses.'"
(2) Coal - Segment Adjusted EBITDA Expense is defined as consolidated Segment Adjusted EBITDA Expense excluding expenses of our Oil & Gas Royalties segment and is adjusted for intercompany transactions with our Coal Royalties segment.
(3) Average sales price per BOE is defined as oil & gas royalty revenues excluding lease bonus revenue divided by total BOE sold.
Coal sales . Coal sales decreased $530.2 million or 30.1% to $1.23 billion for 2020 from $1.76 billion for 2019. The decrease was attributable to a volume variance of $496.9 million resulting from decreased tons sold and a price variance of $33.3 million due to lower average coal sales prices. Tons sold declined 28.2% to 28.2 million tons in 2020, due to reduced shipments to domestic utilities and international markets. Coal sales price realizations declined 2.6% in 2020 to $43.68 per ton sold, compared to $44.86 per ton sold during 2019 resulting, in part, from the absence of high priced metallurgic coal volumes in the 2020 Year. Coal production volumes fell to 27.0 million tons, a reduction of 32.5% compared to 2019, due to temporarily idling production at certain mines particularly in the Illinois Basin Coal Operations region, in response to weak market conditions during 2020.
Coal - Segment Adjusted EBITDA Expense . Segment Adjusted EBITDA Expense for our coal operations decreased 28.6% to $881.0 million in 2020, primarily as a result of reduced tons sold. Segment Adjusted EBITDA Expense per ton decreased slightly in 2020 to $31.23 per ton, compared to $31.39 per ton in 2019. The decrease is attributed primarily to expense control initiatives at all operations, partially offset by the per ton cost impact of lower coal volumes resulting from production curtailment in response to market conditions. Significant cost control initiatives included the closure of higher cost per ton production at our Dotiki and Gibson North mines. Cost per ton in 2020 also benefited from improved recoveries at several mines in both regions offset in part by reduced unit shifts from the curtailment. Our costs per ton were impacted by the following cost variances as discussed by category:
● Material and supplies expenses per ton produced decreased 8.6% to $10.01 per ton in 2020 from $10.95 per ton in 2019. The decrease of $0.94 per ton produced resulted primarily from production mix benefits and improved recoveries previously mentioned, related decreases of $0.46 per ton for roof support, $0.32 per ton for contract labor used in the mining process and $0.14 per ton for certain ventilation expenses, partially offset by an increase of $0.15 per ton for power and fuel used in the mining process .
● Maintenance expenses per ton produced decreased 13.1% to $3.12 per ton in 2020 from $3.59 per ton in 2019. The decrease of $0.47 per ton produced was primarily due to reduced maintenance requirements as a result of production mix benefits and improved recoveries previously mentioned.
● We had no sales of outside coal purchases in 2020 compared to $23.4 million in 2019. Thus, costs per ton in 2020 benefited as our cost of outside coal purchases are generally higher on a per ton basis than our produced coal.
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Segment Adjusted EBITDA Expense decreases above were partially offset by the following increases:
● Labor and benefit expenses per ton produced, excluding workers' compensation, increased 8.7% to $10.75 per ton in 2020 from $9.89 per ton in 2019. The increase of $0.86 per ton was primarily due to curtailed production, partially offset by an improved production mix and improved recoveries at certain mines all previously discussed.
● Production taxes and royalty expenses per ton incurred as a percentage of coal sales prices and volumes increased $0.53 per produced ton sold in 2020 compared to 2019 primarily as a result of a $0.60 per ton government-imposed increase in the federal black lung excise tax, effective January 1, 2020 and an unfavorable state production mix increasing severance taxes per ton, in addition to increased excise taxes per ton resulting from a greater mix of domestic vs. export shipments in 2020 compared to 2019.
Oil & gas royalties . Oil & gas royalty revenues decreased to $42.9 million in 2020 compared to $51.7 million for 2019. The decrease was primarily due to lower average product prices, partially offset by higher volumes resulting from the Wing Acquisition in August 2019 and continued drilling and development of our mineral interests.
Other revenues . Other revenues were principally comprised of Mt. Vernon transloading revenues in our Illinois Basin Coal Operations segment, oil & gas lease bonuses in our Oil & Gas Royalties segment and Matrix Design sales in Other, Corporate and Elimination. Other revenues also include contract buy-out revenues and other outside services which could occur in any of our segments. Other revenues decreased to $31.8 million in 2020 from $48.0 million in 2019. The decrease of $16.2 million was primarily due to reduced sales of mining technology products by our Matrix Design subsidiary and lower coal volumes shipped through our Mt. Vernon transloading facility.
General and administrative. General and administrative expenses for 2020 decreased to $59.8 million compared to $73.0 million in 2019. The decrease of $13.2 million was primarily due to incentive compensation reductions and our expense reduction initiatives.
Asset impairments. During 2020, we recorded $25.0 million of non-cash asset impairment charges due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment and greenfield coal mineral reserves and resources as a result of weakened coal market conditions. During 2019, we recorded an asset impairment charge of $15.2 million due to the cessation of production at our Dotiki mine. Please read "Item 8. Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments" of this Annual Report on Form 10-K."
Goodwill impairment. During 2020, we recorded a $132.0 million non-cash goodwill impairment charge associated with our Hamilton mine, primarily as the result of reduced expected production volumes due to weakened coal market conditions and low energy demand resulting in part from the COVID-19 pandemic. Please read "Item 8. Financial Statements and Supplementary Data— Note 5 – Goodwill Impairment " of this Annual Report on Form 10-K.
Equity securities income . Equity securities income decreased $12.9 million compared to 2019 as we did not recognize equity securities income in 2020 due to the redemption of our preferred interest in Kodiak Gas Service, LLC ("Kodiak") in 2019.
Acquisition gain . We recorded a non-cash acquisition gain of $177.0 million in 2019 associated with the AllDale Acquisition to reflect the fair value of the interests in AllDale I & II we already owned at the time of the acquisition.
Transportation revenues and expenses . Transportation revenues and expenses were $21.1 million and $99.5 million for 2020 and 2019, respectively. The decrease of $78.4 million was largely attributable to decreased coal tonnage for which we arrange third-party transportation at certain mines primarily reflecting reduced coal shipments to international markets and a decrease in average third-party transportation rates in 2020. Transportation revenues are recognized in an amount equal to transportation expenses when title to the coal passes to the customer.
Net income attributable to noncontrolling interest . Net income attributable to noncontrolling interest decreased to $0.2 million in 2020 from $7.5 million in 2019 as a result of allocating $7.1 million of the acquisition gain discussed above to noncontrolling interest in 2019.
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Segment Information . Our 2020 Segment Adjusted EBITDA decreased $225.5 million, or 33.6%, to $446.5 million from 2019 Segment Adjusted EBITDA of $672.0 million. Segment Adjusted EBITDA, tons sold, coal sales, other revenues, Segment Adjusted EBITDA Expense, oil & gas royalties, BOE volume, coal royalties and coal royalties tons sold by segment are as follows:
Year Ended December 31,
2020
2019
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
$
213,876
$
349,810
$
(135,934)
(38.9)
%
Appalachia Coal Operations
171,362
215,187
(43,825)
(20.4)
%
Oil & Gas Royalties
39,773
46,997
(7,224)
(15.4)
%
Coal Royalties
23,968
36,315
(12,347)
(34.0)
%
Other, Corporate and Elimination (2)
(2,490)
23,692
(26,182)
(110.5)
%
Total Segment Adjusted EBITDA (3)
$
446,489
$
672,001
$
(225,512)
(33.6)
%
Coal - Tons sold
Illinois Basin Coal Operations
19,113
28,480
(9,367)
(32.9)
%
Appalachia Coal Operations
9,099
10,809
(1,710)
(15.8)
%
Total tons sold
28,212
39,289
(11,077)
(28.2)
%
Coal sales
Illinois Basin Coal Operations
$
755,208
$
1,128,588
$
(373,380)
(33.1)
%
Appalachia Coal Operations
477,064
628,406
(151,342)
(24.1)
%
Other, Corporate and Elimination
—
5,448
(5,448)
(100.0)
%
Total coal sales
$
1,232,272
$
1,762,442
$
(530,170)
(30.1)
%
Other revenues
Illinois Basin Coal Operations
$
1,932
$
13,017
$
(11,085)
(85.2)
%
Appalachia Coal Operations
14,954
11,166
3,788
33.9
%
Oil & Gas Royalties
229
1,301
(1,072)
(82.4)
%
Coal Royalties
105
23
82
(1)
Other, Corporate and Elimination
14,596
22,533
(7,937)
(35.2)
%
Total other revenues
$
31,816
$
48,040
$
(16,224)
(33.8)
%
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
$
543,264
$
791,795
$
(248,531)
(31.4)
%
Appalachia Coal Operations
320,656
424,387
(103,731)
(24.4)
%
Oil & Gas Royalties
4,106
7,811
(3,705)
(47.4)
%
Coal Royalties
18,249
21,445
(3,196)
(14.9)
%
Other, Corporate and Elimination (2)
(25,026)
(40,542)
15,516
38.3
%
Total Segment Adjusted EBITDA Expense
$
861,249
$
1,204,896
$
(343,647)
(28.5)
%
Oil & Gas Royalties
Volume - BOE (4)
1,792
1,611
181
11.2
%
Oil & gas royalties
$
42,912
$
51,735
$
(8,823)
(17.1)
%
Coal Royalties
Volume - Tons sold (5)
18,863
23,002
(4,139)
(18.0)
%
Intercompany coal royalties
$
42,112
$
57,737
$
(15,625)
(27.1)
%
(1) Percentage change not meaningful.
(2) Other, Corporate and Elimination includes the elimination of intercompany coal royalty revenues and expenses between our Coal Royalties Segment and our Coal Operations Segments in addition to the expenses for the other miscellaneous activities included in this category.
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(3) For a definition of Segment Adjusted EBITDA and related reconciliation to comparable GAAP financial measures, please see below under "—Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)."
(4) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
(5) Represents tons sold by our Coal Operations Segments associated with coal mineral reserves leased from our Coal Royalties Segment.
Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased 38.9% to $213.9 million in 2020 from $349.8 million in 2019. The decrease of $135.9 million was primarily attributable to lower coal sales, which decreased 33.1% to $755.2 million in 2020 from $1.13 billion in 2019, partially offset by reduced operating expenses. The decrease of $373.4 million in coal sales primarily reflects reduced tons sold, which decreased 32.9% compared to 2019 due to curtailed production across all of our mining operations in the region as a result of weak coal market conditions, particularly international markets, amid the COVID-19 pandemic. Segment Adjusted EBITDA Expense decreased 31.4% to $543.3 million in 2020 from $791.8 million in 2019 primarily as a result of reduced tons sold. Segment Adjusted EBITDA Expense per ton increased $0.62 per ton sold to $28.42 from $27.80 per ton sold in 2019, primarily due to reduced coal volumes and related increased fixed costs per ton offset in part by the closure of higher cost per ton operations, improved recoveries at certain mines in 2020 and reduced reclamation accruals at certain non-operating mines. In addition, see certain cost per ton and production variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Appalachia Coal Operations – Segment Adjusted EBITDA decreased 20.4% to $171.4 million for 2020 from $215.2 million in 2019. The decrease of $43.8 million was primarily attributable to lower coal sales, which decreased 24.1% to $477.1 million in 2020 from $628.4 million in 2019, partially offset by reduced operating expenses. The decrease of $151.3 million in coal sales reflects lower tons sold and price realizations. Sales volumes decreased 15.8% in 2020 compared to 2019 due to curtailed production in the region as a result of weak coal market conditions, particularly intern
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