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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, 2020
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 $ 343,214,355 as of June 30, 2020, 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 23, 2021, 127,195,219 common units were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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TABLE OF CONTENTS
Page
PART I
Item 1.
Business
1
Item 1A.
Risk Factors
25
Item 1B.
Unresolved Staff Comments
52
Item 2.
Properties
53
Item 3.
Legal Proceedings
58
Item 4.
Mine Safety Disclosures
59
PART II
Item 5.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
60
Item 6.
Not used
61
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
61
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
79
Item 8.
Financial Statements and Supplementary Data
82
Report of Independent Registered Public Accounting Firm
83
Consolidated Balance Sheets
86
Consolidated Statements of Operations
87
Consolidated Statements of Comprehensive Income (Loss)
88
Consolidated Statements of Cash Flows
89
Consolidated Statement of Partners' Capital
90
Notes to Consolidated Financial Statements
91
1. Organization and Presentation
91
2. Summary of Significant Accounting Policies
92
3. Acquisitions
100
4. Long-Lived Asset Impairments
103
5. Goodwill Impairment
104
6. Inventories
104
7. Property, Plant and Equipment
105
8. Long-Term Debt
106
9. Leases
108
10. Fair Value Measurements
109
11. Partners' Capital
109
12. Variable Interest Entities
110
13. Investments
112
14. Revenue From Contracts With Customers
113
15. Earnings Per Limited Partner Unit
113
16. Employee Benefit Plans
114
17. Common Unit-Based Compensation Plans
117
18. Supplemental Cash Flow Information
120
19. Asset Retirement Obligations
120
20. Accrued Workers' Compensation and Pneumoconiosis Benefits
121
21. Related-Party Transactions
123
22. Commitments and Contingencies
125
23. Concentration of Credit Risk and Major Customers
126
24. Segment Information
126
25. Subsequent Events
129
Supplemental Oil & Gas Reserve Information (Unaudited)
130
Schedule I – Condensed Financial Information of Registrant
135
Item 9.
Changes in and Disagreements with Accountant on Accounting and Financial Disclosure
137
Item 9A.
Controls and Procedures
137
Item 9B.
Other Information
140
PART III
Item 10.
Directors, Executive Officers and Corporate Governance of the General Partner
141
Item 11.
Executive Compensation
146
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
162
Item 13.
Certain Relationships and Related Transactions, and Director Independence
163
Item 14.
Principal Accountant Fees and Services
165
PART IV
Item 15.
Exhibits and Financial Statement Schedules
166
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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%
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%
Medium-sulfur coal
Based on market expectations, we classify coal with a sulfur content of 1.5% to 3%
Metallurgical coal
Coal primarily used in the production of steel
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 reserves
Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
Proven reserves
Proven reserves are reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well established.
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
Reserves
Reserves are that part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Our references to reserves in this
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report take into account estimated losses involved in producing a saleable product ( i.e., salable reserves ).
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
MMcf
Million 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
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 in 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 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, including impacts of the pandemic and of businesses' and governments' responses to the pandemic 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, including 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;
● changing global economic 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;
● the effectiveness or lack of effectiveness in distributed vaccines to reduce the impact of COVID-19;
● 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;
● recent action and the possibility of future action on trade made by United States and foreign governments;
● the effect of changes in taxes or tariffs and other trade measures;
● 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;
● changes in the availability of skilled labor;
● our ability to maintain satisfactory relations with our employees;
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● 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-related 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 reserves;
● 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 United States 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" 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 "SGP" mean Alliance Resource GP, LLC. SGP is indirectly wholly owned by Mr. Craft and Kathleen S. Craft, who are collectively referred to in such capacity as the "Owners of SGP." The Owners of SGP held approximately 34.48% of the outstanding AHGP common units prior to the Simplification Transactions discussed below. SGP was dissolved on December 30, 2020 and is in the process of winding up its affairs.
● 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 the coal mining operations of Alliance Resource Operating Partners, L.P.
● References to "Alliance Minerals" mean Alliance Minerals, LLC, the holding company for the oil and gas minerals interests of Alliance Resource Partners, L.P.
● References to "AHGP" mean Alliance Holdings GP, L.P., individually and not on a consolidated basis as the parent company of MGP prior to the Simplification Transactions discussed below and as a wholly owned subsidiary of ARLP subsequent to the Simplification Transactions.
PART I
ITEM 1. BUSINESS
General
Introduction
We are a diversified natural resource company that generates income from coal production 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 oil & gas mineral ownership. We believe that ARLP's diverse and rich resource base will allow ARLP to continue to create long-term value for unitholders.
We are currently the second-largest coal producer in the eastern United States with seven 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 primarily 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.
In addition, we develop and market industrial and mining technology products and services.
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.
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Simplification Transactions
On July 28, 2017, the conflicts committee ("Conflicts Committee") of the board of directors ("Board of Directors") of MGP and AGP's board of directors approved a transaction to simplify our partnership structure. Pursuant to that transaction, which closed on the same date, MGP contributed to ARLP all of its incentive distribution rights ("IDRs") and its 0.99% managing general partner interest in ARLP in exchange for 56,100,000 ARLP common units and a non-economic general partner interest in ARLP. In conjunction with this transaction and on the same economic basis as MGP, SGP also contributed to ARLP its 0.01% general partner interest in both ARLP and the Intermediate Partnership in exchange for 28,141 ARLP common units collectively (the "Exchange Transaction").
On February 22, 2018, our Board of Directors and the board of directors of AHGP's general partner approved a simplification agreement (the "Simplification Agreement") pursuant to which, among other things, through a series of transactions (the "Simplification Transactions"):
i. AHGP would become a wholly owned subsidiary of ARLP,
ii. all of the issued and outstanding AHGP common units would be canceled and converted into the right to receive the ARLP common units held by AHGP and its subsidiaries,
iii. in exchange for a number of ARLP common units calculated pursuant to the Simplification Agreement, MGP's 1.0001% general partner interest in our Intermediate Partnership and MGP's 0.001% managing member interest in our subsidiary, Alliance Coal, would be contributed to us, and
iv. MGP would remain ARLP's sole general partner and would be a wholly owned subsidiary of AGP, and thus no control, management, or governance changes with respect to our business would occur.
The Simplification Agreement and the transactions contemplated thereby were approved by the written consent of approximately 68% of the holders of AHGP common units outstanding as of April 25, 2018, the record date for the consent solicitation. On May 31, 2018, ARLP, AHGP, and the other parties to the Simplification Agreement completed the transactions contemplated by the Simplification Agreement.
Prior to the Simplification Transactions, MGP was a wholly owned indirect subsidiary of AHGP. Alliance GP, LLC ("AGP"), which is indirectly wholly owned by Mr. Craft, was the general partner of AHGP prior to the Simplification Transactions and became the direct owner of MGP as a result of those transactions. See discussions under Partnership Simplification regarding changes in ownership of ARLP and MGP as a result of the Exchange Transaction and Simplification Transactions.
As part of the Simplification Transactions, (i) each AHGP common unit that was issued and outstanding at the effective time of the Simplification Transactions was canceled and converted into the right to receive a portion of the ARLP common units held by AHGP and its subsidiaries, and (ii) SGP became the sole limited partner in AHGP. Each outstanding AHGP common unit, other than certain AHGP common units held by the Owners of SGP, converted into the right to receive approximately 1.4782 ARLP common units held by AHGP and its subsidiaries. The remaining AHGP common units held by the Owners of SGP were canceled and converted into the right to receive 29,188,997 ARLP common units which equaled (i) the product of the number of certain AHGP common units held by the Owners of SGP multiplied by 1.4782, minus (ii) 1,322,388 ARLP common units. In addition, ARLP issued 1,322,388 ARLP common units to the Owners of SGP in exchange for causing SGP to contribute to ARLP its remaining limited partner interest in AHGP, which included AHGP's indirect ownership of a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal, resulting in an overall exchange ratio to the Owners of SGP equal to that of the other AHGP unitholders. Upon the issuance of ARLP common units to the Owners of SGP in exchange for the limited partner interest in AHGP, ARLP became a) the sole limited partner of AHGP and b) through AHGP, the indirect owner of a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal.
AllDale I & II Acquisition
On January 3, 2019 (the "Acquisition Date"), ARLP 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, which was funded with cash on hand and borrowings under our revolving credit facility (the "AllDale Acquisition"). ARLP indirectly owns a 96.0% non-managing member interest and a non-economic managing member interest in Cavalier Minerals. The
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AllDale Acquisition provides ARLP with diversified exposure to industry leading operators and is consistent with our general business strategy to pursue accretive acquisitions.
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 net royalty acres in the Midland Basin, with exposure to more than 400,000 gross acres (the "Wing Acquisition"). The Wing Acquisition enhanced our ownership position in the Permian Basin, expanded our exposure to industry leading operators, and furthered our business strategy to grow our Minerals segment. Following the Wing Acquisition, we hold approximately 55,500 net royalty acres in premier oil & gas resource plays including net royalty acres from our investment in AllDale Minerals III, LP ("AllDale III"). See "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions" for more information.
The following diagram depicts our simplified organization and ownership as of December 31, 2020:
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.
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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 for 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, 2020, we had approximately 1.7 billion tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia. 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 2020, we sold 28.2 million tons of coal and produced 27.0 million tons. The coal we sold in 2020 was approximately 10.6% low-sulfur coal, 51.6% medium-sulfur coal, and 37.9% high-sulfur coal. In 2020, approximately 94.2% of our tons sold were purchased by United States electric utilities and 3.3% 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 United States electric utilities, 100% were sold to utility plants with installed pollution control devices. The Btu content of our coal ranges from 11,400 to 13,200.
The following chart summarizes our coal production by region for the last five years.
Year Ended December 31,
Coal Regions
2020
2019
2018
2017
2016
(tons in millions)
Illinois Basin
17.9
29.5
29.9
27.3
25.4
Appalachia
9.1
10.5
10.4
10.3
9.8
Total
27.0
40.0
40.3
37.6
35.2
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The following map shows the location of our coal mining operations:
Designated reserves noted on the map and reserves associated with our mining complexes may be owned or held by Alliance Resource Properties, our land holding company, with intercompany leases to our mining complexes.
Illinois Basin Operations:
4. WARRIOR COMPLEX
8. SEBREE-ONTON COMPLEX
11. TUNNEL RIDGE COMPLEX
1. GIBSON COMPLEX
Warrior Mine
Onton Mine (Idled)
Tunnel Ridge Mine
Gibson South Mine
Mining Type: Underground
Mining Type: Underground
Mining Type: Underground
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Method: Continuous
Mining Method: Continuous
Mining Method: Longwall
Mining Method: Continuous
Miner
Miner
& Continuous Miner
Miner
Coal Type: Medium/High-Sulfur
Coal Type: Medium/High-Sulfur
Coal Type: Medium/High-Sulfur
Coal Type: Low/Medium-Sulfur
Transportation: Barge, Railroad,
Transportation: Barge & Truck
Transportation: Barge & Railroad
Transportation: Barge, Railroad
& Truck
& Truck
Appalachian Operations:
12. PENN RIDGE RESERVES
5. MOUNT VERNON
9. MC MINING COMPLEX
Mining Type: Underground
2. HAMILTON COMPLEX
TRANSFER TERMINAL
Excel Mine No. 5
Mining Access: Slope & Shaft
Hamilton Mine
Rail or Truck to Ohio River Barge
Mining Type: Underground
Mining Method: Longwall
Mining Type: Underground
Transloading Facility
Mining Access: Slope & Shaft
& Continuous Miner
Mining Access: Slope & Shaft
Mining Method: Continuous
Coal Type: High-Sulfur
Mining Method: Longwall
6. HENDERSON/UNION
Miner
Transportation: Barge & Railroad
& Continuous Miner
RESERVES
Coal Type: Low-Sulfur
& Continuous Miner
Coal Type: Medium/High-Sulfur
Mining Type: Underground
Transportation: Barge, Railroad,
Transportation: Barge, Railroad
Mining Access: Slope & Shaft
& Truck
& Truck
Mining Method: Continuous Miner
Coal Type: Medium/High-Sulfur
10. METTIKI COMPLEX
3. RIVER VIEW COMPLEX
Transportation: Barge & Truck
Mountain View Mine
River View Mine
Mining Type: Underground
Mining Type: Underground
7. DOTIKI RESERVES
Mining Access: Slope
Mining Access: Slope & Shaft
Mining Type: Underground
Mining Method: Longwall
Mining Method: Continuous
Mining Access: Slope & Shaft
& Continuous Miner
Miner
Mining Method: Continuous
Coal Type: Low/Medium
Coal Type: Medium/High-Sulfur
Miner
Sulfur - Metallurgical
Transportation: Barge & Truck
Coal Type: Medium/High-Sulfur
Transportation: Railroad
Transportation: Barge, Railroad
& Truck
& Truck
We lease most of our coal reserves from 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 reserve area. These
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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. 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, 2020, we had 1,670 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") and Norfolk Southern Railway Company ("NS") railroads from the Gibson North rail loadout facility directly to customers or to 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.
Gibson County Coal also operated the Gibson North mine, an underground mine also located near the city of Princeton in Gibson County, Indiana. The Gibson North mine began production in November 2000 and utilized continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal. The Gibson North mine was idled in December 2015 in response to market conditions but resumed production in May 2018. In November 2019, the Gibson North mine was again idled in response to market conditions and in May 2020, the Gibson North mine was reclaimed and sealed.
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. Initial development production from the continuous miner units began in 2013, 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, and NS rail directly to customers or to 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 and Paducah & Louisville Railway, Inc. ("PAL") railroads and 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. During 2020, the terminal loaded approximately 425,000 tons for customers of Gibson County Coal and Hamilton.
Alliance Resource Properties . Alliance Resource Properties, LLC and collectively with its subsidiaries ("Alliance Resource Properties") own or control coal reserves that they lease to certain of our subsidiaries that operate our mining complexes, including Gibson South, Hamilton, River View and Warrior. In December 2014 and February 2015, WKY CoalPlay, LLC or its subsidiaries ("WKY CoalPlay"), which are related parties, entered into coal lease agreements with
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us regarding coal reserves located in Henderson and Union Counties, Kentucky ("Henderson/Union Reserves") and Webster County, Kentucky. For more information about the WKY CoalPlay transactions, please read "Item 8. Financial Statements and Supplementary Data — Note 21 – Related-Party Transactions."
Dotiki Complex. Our subsidiary, Webster County Coal, LLC ("Webster County Coal"), operated Dotiki, an underground mining complex located near the city of Providence in Webster County, Kentucky. The complex opened in 1966, and we purchased the mine in 1971 and operated it until it ceased production in August 2019. For information regarding Dotiki's remaining coal reserves, please read "Item 2. Properties – Coal Reserves."
Hopkins Complex. The Hopkins complex, which we acquired in January 1998, is located near the city of Madisonville in Hopkins County, Kentucky. Our subsidiary, Hopkins County Coal, LLC ("Hopkins County Coal") operated the Elk Creek underground mine until it ceased production in April 2016. We have begun performing reclamation activities at the complex. For information regarding Hopkins' remaining coal reserves, please read "Item 2. Properties Coal Reserves."
Pattiki Complex. Our subsidiary, White County Coal, LLC ("White County Coal"), operated Pattiki, an underground mining complex located near the city of Carmi in White County, Illinois. We began construction of the complex in 1980 and operated it until it ceased production in December 2016. We have begun performing reclamation activities at the complex. For information regarding Pattiki's remaining coal reserves, please read "Item 2. Properties – Coal Reserves."
Sebree - Onton Complex . On April 2, 2012, we acquired substantially all of Green River Collieries, LLC's assets related to its coal mining business and operations located in Webster and Hopkins Counties, Kentucky, including the Onton No. 9 mining complex ("Onton mine"). The Onton mine was operated by our subsidiary, Sebree Mining, LLC ("Sebree"). The Onton mine was idled in November 2015 in response to market conditions. For information regarding Onton's remaining coal reserves, please read "Item 2. Properties – Coal Reserves."
Appalachian Operations
Our Appalachian mining operations are located in eastern Kentucky, Maryland, and West Virginia. As of December 31, 2020, we had 860 employees, and we operate three mining complexes in Appalachia with one mine currently under development.
MC Mining Complex. The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky. We acquired the mine in 1989. Our subsidiary, MC Mining, LLC ("MC Mining"), owns the mining complex and controls the reserves, and our subsidiary, Excel Mining, LLC ("Excel") conducts all mining operations. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has throughput capacity of 1,000 tons of raw coal per hour. Substantially all of the coal produced at MC Mining in 2020 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 is shipped via the CSX railroad directly to customers or to 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.
Our subsidiary, Excel, completed development activity for MC Mining's Excel Mine No. 5 in May 2020 and transitioned its employees and equipment to the new mine in July 2020. MC Mining controls the estimated 15 million tons of coal reserves assigned to the Excel Mine No. 5 and Excel will conduct all mining operations. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal with an expected annual production capacity of 1.3 million tons. MC Mining utilizes its existing underground mining equipment and preparation plant to produce and process coal from the Excel Mine No. 5 and ships coal produced from the mine to various transloading facilities on the Ohio River and the Big Sandy River for barge deliveries or directly to customers via the CSX railroad and by truck. The development plan for the new Excel Mine No. 5 provided a seamless transition from the current MC Mining operation.
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) began continuous miner development of the Mountain View mine in July 2005 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
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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. Tunnel Ridge began construction of the mine and related facilities in 2008. Development mining began in 2010, and 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.
Penn Ridge. Our subsidiary, Penn Ridge Coal, LLC ("Penn Ridge"), holds coal reserves in Washington County, Pennsylvania, estimated to include approximately 61.5 million tons of proven and probable high-sulfur coal in the Pittsburgh No. 8 seam. Development of the project is regulatory and market dependent and its timing is open-ended pending obtaining all required regulatory approvals, sufficient coal sales commitments to support the project, and final approval by the Board of Directors.
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 2020 approximately 93.0% and 92.8% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2020 to 2025. As of February 1, 2021, our nominal commitment under contract was approximately 24.1 million tons in 2021. 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 substantial part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America, although the share of our export sales fell significantly in 2020 due to reduced demand in the international coal market. Our sales into the international coal market are considered exports and
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are made through brokered transactions. During the years ended December 31, 2020, 2019, and 2018, export tons represented approximately 3.3%, 17.9%, and 27.8% of tons sold, respectively. We use the end-usage point as the basis for attributing tons to individual countries. 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 2020, our key customers were American Electric Power, Louisville Gas and Electric Company, and Tennessee Valley Authority. We generally define key customers as those from which we derive 10% or more of our total revenues during 2020. For more information about these customers, 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 a number of smaller producers in the Illinois Basin and Appalachian regions.
In addition, we compete with companies that produce coal from one or more foreign countries. We seek to export a portion of our coal into the international coal markets and historically the prices we 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. Potential changes to international trade agreements, trade concessions, or other political and economic arrangements may benefit coal producers operating in countries other than the United States. We may 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 may provide our foreign competitors with a competitive advantage. If our competitors' currencies decline against the United States dollar or against foreign purchasers' local currencies, those competitors may 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 to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
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. Costs and other factors, such as safety and environmental considerations, have affected and may continue to affect the overall demand for coal as a fuel. 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 displaced and may continue to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators. Federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for our 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.
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. 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
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located in favorable geographic locations that minimize transportation costs for our customers, and in many cases, we are able to 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 58.9% of our 2020 sales volume was initially shipped from the mining complexes by barge, 28.1% was shipped from the mining complexes by rail and 13.0% 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 business includes all activities related to the 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. 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 55,500 net royalty acres, including 3,988 net royalty acres owned through our equity interests in AllDale III.
When our 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 or plugging and abandonment costs associated with oil & gas production.
The following chart summarizes the production of our mineral interests for the year ended December 31, 2020, and 2019:
Year Ended
December 31,
2020
2019
Production:
Oil (MBbls)
948
741
Natural gas (MMcf)
3,635
3,664
Natural gas liquids (MBbls)
337
364
BOE (MBbls)
1,892
1,716
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The following map shows the location of our oil & gas mineral interests:
In 2014, ARLP began to actively invest in oil & gas mineral interests in some of the nation's premier oil-rich basins. Beginning in 2019, ARLP 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 Wing 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.
Minerals Competition
There is intense competition for acquisition opportunities in the oil & gas industry, and we compete with other companies that have greater resources. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to acquire additional 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 mineral interests but also explore for and produce oil & gas and, in some cases, carry on 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.
Minerals - 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 operating 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 mining technology products
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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 miner and equipment tracking systems and proximity detection systems. We acquired Matrix Design in September 2006.
Additional Services
We develop and market additional services in order to establish ourselves as the supplier of choice for our customers. Historically, and in 2020, 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,
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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.
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;
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● training and availability of mine rescue teams;
● underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;
● flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
● post-accident two-way communications and electronic tracking systems.
MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.
In 2014, MSHA began implementation of a finalized new regulation titled "Lowering Miner's Exposure 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, 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 request for information. The comment period for the request for information closed in September 2020. It is uncertain whether MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.
Separately, 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. It is uncertain whether MSHA will present a final rule addressing this issue.
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.
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 and to some survivors of a miner who dies from this disease. The BLBA levied a tax on coal sold of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. 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. The Revenue Act of 1987
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extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018. On January 1, 2019, the excise tax rates reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price. In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase was set to expire on December 31, 2020. However, in December 2020, the excise tax rate increase was extended another year, through December 31, 2021.
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.
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 for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively. This fee is currently scheduled to be in effect until September 30, 2021, and requires Congressional action to reauthorize. 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.
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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 United States 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 their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken. These actions by OSM, 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. By example, the Office of Workers' Compensation Programs issued new criteria in 2019, but has yet to provide information to self-insured operators regarding the bonding levels and collateral thresholds that 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— Off-Balance Sheet Arrangements ."
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.
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
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control devices such as flue gas desulfurization systems, or "scrubbers," or by reducing electricity-generating levels. In 2020, we sold 93.0% of our total tons to electric utilities in the United States, of which 100% 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 United States 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 ("HAP") from coal-fueled Electric Generating Units ("EGUs") under the MATS rule. Notwithstanding the invalidation of this threshold regulatory determination, the final rule leaves in place all of the HAP emission control requirements imposed by the MATS rule based on the conclusion that the EGU source category cannot meet the statute's stringent requirements for delisting a source category from HAP regulation. Many electric generators have already announced retirements due to the MATS rule. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit , the MATS rule has forced generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR Update and MATS and the effects they may have on our business and our results of operations, financial condition, or cash flows.
● 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 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 have filed litigation against one or both of these rulemakings, and the NAAQS may be subject to revision under the Biden Administration. 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
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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 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.
● 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. Depending on the ultimate resolution of these cases, 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 from 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, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. 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.
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 has 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 has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement. However, the impact of these orders, and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement, 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-
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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 United States Supreme Court's 2007 decision that the EPA has authority to regulate GHG emissions. Although the United States 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. Most recently, 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 United States Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States 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 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 and 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. 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. 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 United States 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
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July 2020, the Council on Environmental Quality 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, these regulations may be subject to further regulation under the Biden Administration.
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.
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. It is likely that these regional efforts will 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."
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.
In order 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 United States 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
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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. It is also possible that Biden Administration could propose a broader definition of WOTUS. Should any rule expanding the definition of what constitutes a water of the United States take effect as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.
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.
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.
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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. It is unclear what impact these regulations will have on the market for our products.
Endangered Species Act
The federal Endangered Species Act ("ESA") and counterpart state legislation protect species threatened with possible extinction. The United States 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. 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, 2020, we employed 2,902 full-time employees, including 2,530 employees involved in active mining operations, 203 employees in other operations, and 169 corporate employees. Our workforce is entirely union-free. Our typical employee has approximately nine years of experience with the Partnership and more than 34% of all employees remain employed for more than five years. However, we reduced our headcount by 19% during 2020 primarily due to the effects of the COVID-19 pandemic.
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 a base salary, incentive bonus, medical, dental and life insurance and participation in our profit sharing and savings plan. Depending on the position, incentive bonuses can be based on production and safety goals at specific coal operations or company-wide performance goals, 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 1.06 for the nine months ended September 30, 2020, was approximately 68.6% lower than the preliminary industry average over the same time period. 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
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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.
In light of the COVID-19 pandemic in 2020, we have also taken steps to enhance protections from, and minimize risks associated with, the spread of COVID-19, including, but not limited to, 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 of the market price of our common units
● Increase in interest rates could cause decline of 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
● Unavailability of economic coal reserves could limit our ability to continue or expand our operations
● Estimates of our coal reserves could be inaccurate and could result in decreased profitability
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● 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 minerals segment
● Legislative and regulatory initiatives relating to hydraulic fracturing could impact our mineral interests
● Legislative and regulatory initiatives relating to address seismic activity could impact our minerals segment
● 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
● Unexpected increases in raw material costs could impact the profitability of 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 minerals segment
● Suspension of right to receive royalty payments could impact our minerals segment
● 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 minerals segment
● Availability of transportation and facilities for the products could impact our minerals segment
● 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 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-United States 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
Risks Inherent in an Investment in Us
Cash distributions to unitholders are not guaranteed.
Our Board of Directors suspended cash distributions to unitholders beginning with the quarter ended March 31, 2020. The payment and amount of any future distribution will be subject to the sole discretion of our Board of Directors and will
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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;
● 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.
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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.
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
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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 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.
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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 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. A number of 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, limit our choices for lenders, insurance providers and business partners, impair our brand 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 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
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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 factor 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.
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 reserves.
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, and negatively impacted our results of operations for 2020. 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 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 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 credit-worthiness or their ability to make payment for our products. We continue to work with our stakeholders
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(including customers, employees, suppliers, and local communities) to address this global pandemic responsibly. We continue to monitor the situation, to assess further possible implications to our employees, business, supply chain, and customers, and to 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. Given the tremendous uncertainties and variables, we cannot at this time predict the impact of the global COVID-19 pandemic, or any future pandemic, but any pandemic or similar outbreak could have a material adverse impact on our business, financial position, results of operations, and/or cash flows.
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 $603.8 million as of December 31, 2020. 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.
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.
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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 2020, we sold approximately 93.0% 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, 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.
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 2020, we derived more than 10% of our total revenues from each of three customers, American Electric Power, Louisville Gas and Electric Company, and Tennessee Valley Authority. If we were to lose these 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.
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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, 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;
● 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;
● 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;
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● 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.
Changes in taxes or tariffs and other trade measures could adversely affect our results of operations, financial position, and cash flows.
Certain taxes and fees related to our operations, including the Abandoned Mine Land Reclamation Fund and the Black Lung Excise Tax, are set to expire in 2021. While the renewal of these taxes and fees would not have a significant impact on our business or results of operations, Congress 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
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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.
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 utility industry accounts for approximately 91% of 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, a prolonged economic recession, or prolonged recovery from the COVID-19 pandemic, 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 United States 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 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
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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 October 1, 2020, 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.
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
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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.
The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.
Our profitability depends substantially on our ability to mine coal reserves 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 as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves 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 that we acquire, which could adversely affect our profitability and financial condition. Exhaustion of reserves 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 in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for
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attractive properties, the lack of suitable acquisition candidates, or the inability to acquire coal properties on commercially reasonable terms.
The estimates of our coal reserves could prove inaccurate and could result in decreased profitability.
The estimates of our coal reserves could vary substantially from the actual amounts of coal we are able to economically recover. The reserve data set forth in "Item 2. Properties—Coal Reserves" represent our engineering estimates. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which 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.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on the risk of recovery, and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, could vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations could be material. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.
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 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 characteristic 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 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 ."
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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.
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.
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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 minerals segment.
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.
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
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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, and in some instances, regulators may order disposal wells be shut-in.
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 if 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, President Biden has signed an executive order calling for the suspension, revision, or rescission of a September 2020 rule that reduced certain restrictions on GHG emissions from the oil and gas sector.
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, President Biden has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States' nationally determined emissions reduction targets under the agreement. However, the impact of these orders, and the terms of any legislation or regulation to implement the United States' commitment under the Paris Agreement, remain unclear at this time.
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, as a number of cities, local governments, and other plaintiffs have sued various fossil fuels companies in state and federal courts, alleging various legal theories to recover for the impacts of alleged damages from global warming, such as rising sea levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but
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defrauded their investors or customers by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.
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. 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. Recently, the Federal Reserve announced it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect mining or oil & gas production activities.
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 our 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 in an economic manner. 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.
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 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.
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. 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.
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
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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, 2020, our total of such bonds was $171.1 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.
We have little to no control over the timing of future drilling with respect to our 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.
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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, 2020, were audited by Netherland, Sewell & Associates, Inc. ("NSAI"), which conducted a detailed review of all of our properties at that time using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual 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 are 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
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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 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.
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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 and coal reserves in existing, adjacent, and neighboring properties. Similarly, the profitability of our minerals segment depends significantly upon acquisitions to grow our 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 minerals business, 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.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions 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 ;
● 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
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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.
Tax Risks to Our Common Unitholders
Our tax treatment depends on our status as a partnership for 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 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 units depends largely on our being treated as a partnership for United States 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 United States 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 United States federal income tax purposes or otherwise subject us to taxation as an entity.
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If we were treated as a corporation for United States federal income tax purposes, we would pay United States 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 the 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 United States 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 United States federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for 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 United States 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 United States 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 United States 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 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 units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our 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 federal income tax purposes. The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to 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 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
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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 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 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 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.
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, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act," discussed below), 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.
For our 2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase. For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in a greater business interest expense deduction. In addition, unitholders may treat 50% of any excess business interest allocated to them in 2019 as deductible in the 2020 taxable year without regard to the 2020 business interest expense limitations. The remaining 50% of such unitholder's excess business interest is carried forward and subject to the same limitations as other taxable years.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our 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
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are exempt from United States 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 units.
Non-United States unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a United States 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 United States trade or business. As a result, distributions to a Non-United States unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-United States unitholder who sells or otherwise disposes of a unit will also be subject to United States 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 United States 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, recently issued 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 further 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, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor's broker.
We treat each purchaser of our units as having the same tax benefits without regard to the units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of 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 units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.
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 United States 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
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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 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 Congress have indicated a desire to eliminate certain key United States federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed and elimination of those provisions would not impact our financial statements or results of operations. However, elimination of the 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 units.
In addition to United States 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 United States 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 Reserves
We must obtain permits from applicable regulatory authorities before beginning to mine particular reserves. For more information on this permitting process, and matters that could hinder or delay the process, please read "Item 1. Business—Environmental, Health and Safety Regulations— Mining Permits and Approvals ."
Our reported coal reserves are those we believe can be economically and legally extracted or produced at the time of the filing of this Annual Report on Form 10-K. In determining whether our reserves meet this economic and legal standard, we take into account, among other things, our potential ability or inability to obtain mining permits, the possible necessity of revising mining plans, changes in future cash flows caused by changes in estimated future costs, changes in mining permits, variations in quantity and quality of coal, and varying levels of demand and their effects on selling prices.
At December 31, 2020, we had approximately 1.653 billion tons of coal reserves. These reserves are owned or held by the complexes they are most closely associated with or Alliance Resource Properties. Alliance Resource Properties has lease agreements with some of the complexes for certain reserves it owns or holds. All of the estimates of reserves which are presented in this Annual Report on Form 10-K are of proven and probable reserves (as defined below) and closely adhere to the standards described in United States Geological Survey ("USGS") Circular 831 and USGS Bulletin 1450-B. For information on the locations of our mines, please read "Coal Operations" under "Item 1. Business."
The following table sets forth reserve information at December 31, 2020 about our coal operations:
Mine
Heat
Status
Content (Btus
Pounds S02 per MMBtu
Classification
Reserve Assignment
Reserve Control
Operations (1)
(2)
per pound)
<1.2
1.2-2.5
>2.5
Total
Proven
Probable
Assigned
Unassigned
Owned
Leased
(tons in millions)
Illinois Basin Operations
Gibson South (IN)
A
11,500
0.6
13.6
40.4
54.6
46.7
7.9
54.6
—
18.2
36.4
Hamilton County (IL)
A
11,650
—
—
540.0
540.0
234.8
305.2
125.0
415.0
52.0
488.0
Henderson/Union (KY)
R
11,400
—
3.1
459.7
462.8
172.9
289.9
—
462.8
62.2
400.6
River View (KY)
A
11,450
—
—
223.9
223.9
124.9
99.0
223.9
—
63.5
160.4
Warrior (KY)
A
12,300
—
—
80.4
80.4
66.0
14.4
80.4
—
19.4
61.0
Dotiki (KY)
C
12,100
—
2.9
73.2
76.1
52.4
23.7
—
76.1
27.6
48.5
Hopkins (KY)
C
12,000
—
—
13.9
13.9
9.7
4.2
—
13.9
4.4
9.5
Sebree - Onton (KY)
I
11,750
—
—
40.3
40.3
22.6
17.7
40.3
—
0.2
40.1
Region Total
0.6
19.6
1,471.8
1,492.0
730.0
762.0
524.2
967.8
247.5
1,244.5
Appalachia Operations
MC Mining (KY)
A
12,600
12.7
1.8
—
14.5
10.2
4.3
14.5
—
0.2
14.3
Mettiki (MD)
A
13,200
—
1.6
3.8
5.4
5.3
0.1
—
5.4
—
5.4
Mettiki (WV)
A
13,200
—
6.4
9.0
15.4
10.2
5.2
9.6
5.8
1.6
13.8
Penn Ridge (PA)
R
12,500
—
—
61.5
61.5
16.7
44.8
61.5
—
61.5
—
Tunnel Ridge (WV)
A
12,600
—
—
64.0
64.0
31.7
32.3
64.0
—
—
64.0
Region Total
12.7
9.8
138.3
160.8
74.1
86.7
149.6
11.2
63.3
97.5
Total
13.3
29.4
1,610.1
1,652.8
804.1
848.7
673.8
979.0
310.8
1,342.0
% of Total
0.8%
1.8%
97.4%
100.0%
48.7%
51.3%
40.8%
59.2%
18.8%
81.2%
(1) Our mining operations, both active and inactive, contain underground mines
(2) A = Active, C = Closed, I = Idled, R = Reserves only
Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists and engineers. This data is obtained through our extensive, ongoing exploration drilling and in-mine channel sampling programs. Our drill spacing criteria adheres to standards as defined by the USGS. The maximum acceptable distance from seam data points varies with the geologic nature of the coal seam being studied, but generally the standard for (a) proven reserves is that points of observation are no greater than ½ mile apart and are projected to extend as a ¼ mile wide belt around each point of measurement and (b) probable reserves is that points of observation are between ½ and 1 ½ miles apart and are projected to extend as a ½ mile wide belt that lies ¼ mile from the points of measurement.
Reserve estimates will change from time to time to reflect mining activities, additional analysis, new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods, and other
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factors. We have historically obtained an outside audit of our reserve estimates and calculation methods every five years with the most recent audit being performed by Weir International Mining Consultants ("Weir") in July 2015. Weir is expected to perform this audit again during 2021 in advance of the SEC's new property disclosure requirements for mining companies.
Reserves represent that part of a mineral deposit that can be economically and legally extracted or produced, and reflect estimated losses involved in producing a saleable product. All of our reserves are thermal coal, except for reserves at Mettiki that can be delivered to the thermal or metallurgical markets. The 12.7 million tons of reserves listed at MC Mining as <1.2 pounds of SO 2 per MMBtus are marketable as compliance coal under Phase II of CAA. Btu values are reported on an as shipped, fully washed basis. Shipments that are either fully or partially raw will have a lower Btu value.
We own or control certain leases for coal deposits that do not currently meet the criteria to be reflected as reserves but may be reclassified as reserves in the future. These tons are classified as non-reserve coal deposits and are not included in our reported reserves. We have total non-reserve coal deposits of 289.2 million tons of which the Henderson/Union Reserves account for 157.4 million tons. Our remaining non-reserve coal deposits include the following: Dotiki—16.2 million tons, Elk Creek—7.8 million tons, Gibson South—1.7 million tons, Gibson North—21.4 million tons, Hamilton—33.7 million tons, Mettiki—1.0 million tons, Penn Ridge––15.9 million tons, Riverview—2.1 million tons, Sebree - Onton—4.6 million tons, Sebree—7.0 million tons, Tunnel Ridge—16.2 million tons and Warrior—4.2 million tons.
We lease most of our reserves and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area. These leases provide for royalties to be paid to the lessor 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. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.
Mining Operations
The following table sets forth production and other data about our mining operations:
Tons Produced
Operations
Location
2020
2019
2018
Transportation
Equipment
(in millions)
Illinois Basin Operations
Dotiki (1)
Kentucky
—
1.3
2.5
CSX, PAL, truck, barge
CM
Gibson North (1)
Indiana
—
1.8
0.9
CSX, NS, truck, barge
CM
Gibson South
Indiana
2.3
5.5
6.9
CSX, NS, truck, barge
CM
Hamilton
Illinois
2.6
5.9
6.3
CSX, EVW, barge
LW, CM
River View
Kentucky
9.4
11.3
9.8
Truck, barge
CM
Warrior
Kentucky
3.6
3.7
3.5
CSX, PAL, truck, barge
CM
Region Total
17.9
29.5
29.9
Appalachia Operations
MC Mining
Kentucky
0.5
1.0
1.3
CSX, truck, barge
CM
Mettiki
WV, MD
1.8
2.1
2.3
CSX, truck
LW, CM
Tunnel Ridge
West Virginia
6.8
7.4
6.8
CSX, NS, barge
LW, CM
Region Total
9.1
10.5
10.4
TOTAL
27.0
40.0
40.3
(1) Closed
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CSX
-
CSX Railroad
EVW
-
Evansville Western Railroad
NS
-
Norfolk Southern Railroad
PAL
-
Paducah & Louisville Railroad
CM
-
Continuous Miner
LW
-
Longwall
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, 2020, we had approximately 41,000 developed and undeveloped net acres held at a weighted average royalty of 16.8%. Our net acres standardized to 1/8th royalty equates to approximately 55,500 net royalty acres, including approximately 3,988 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, 2020 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.
As of December 31, 2020
Crude Oil
Natural Gas
Natural Gas Liquids
Total
(MBbl)
(MMcf)
(MBbl)
(MBOE) (2)
Estimated proved developed reserves
5,073
23,505
2,252
11,244
Estimated proved undeveloped reserves
2,071
9,565
868
4,533
Total estimated proved reserves (1)
7,144
33,069
3,120
15,777
(1) Proved reserves of approximately 972 MBOE were attributable to noncontrolling interests as of December 31, 2020.
(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, 2020 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 2020. The average realized product prices weighted by production over the remaining lives of the properties are $36.95/Bbl for oil, $0.88/Mcf of natural gas and $7.99 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 2020, NGL prices averaged approximately 26% of the posted oil prices during the course of the year with an additional $2.30/Bbl deducted for transportation costs.
The following table summarizes our changes in proved undeveloped reserves (in MBOE):
Beginning balance, January 1, 2020
3,110
Transfers of PUDs to estimated proved developed
(115)
Extensions and discoveries
1,221
Revisions of previous estimates
317
Ending balance, December 31, 2020
4,533
During the year ended December 31, 2020, we converted 115 MBOE of PUD reserves to proved developed reserves as applicable wells began production. Extensions and discoveries contributed 2,238 MBOE resulting in a net increase of 1,221 MBOE despite a reduction of 1,017 MBOE due to expired permits. Revisions of previous estimates of 317 MBOE is a result of type curve changes.
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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, 2020, we did not have any expenditures to convert PUDs to proved developed 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, 2020, approximately 28.73% 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, 2020 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,
(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 2020 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 2020 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:
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● 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, 2020 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, 2020 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.
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, 2020.
Developed Acreage
Undeveloped Acreage
Gross
Net Mineral
Net Royalty
Gross
Net Mineral
Net Royalty
Basin
Permian Basin
207,026
4,382
5,626
569,554
14,817
19,364
Anadarko Basin
137,341
4,957
7,069
299,796
11,053
15,745
Williston Basin
102,530
1,706
2,230
124,486
1,931
2,538
Other
22,581
496
635
49,723
1,893
2,334
Total
469,477
11,541
15,560
1,043,560
29,693
39,980
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Oil & Gas Production Prices and Production Costs
For the year ended December 31, 2020, 50.1% of our production and 81.2% 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,
2020
2019
Production:
Oil (MBbls)
948
741
Natural gas (MMcf)
3,635
3,664
Natural gas liquids (MBbls)
337
364
BOE (MBbls)
1,892
1,716
Average Realized Prices:
Oil (per Bbl)
$
39.04
$
54.30
Natural gas (per Mcf)
$
1.52
$
2.01
Natural gas liquids (per Bbl)
$
9.08
$
20.17
BOE (MBbls)
$
24.10
$
32.02
Unit cost per BOE:
Production and ad valorem taxes
$
2.64
$
4.82
Productive Wells
As of December 31, 2020, 6,169 gross productive horizontal wells and 4,121 gross productive vertical wells were located on the acreage in which we have a mineral interest. Of our productive horizontal wells, 912 are considered natural gas wells, while the remaining 5,257 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 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 plaintiff alleges 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 plaintiff seeks 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. We believe their claims are without merit and intend to defend the litigation vigorously. The litigation is in early stages and discovery has not yet begun. We do not believe this litigation will have a material adverse effect on our business, financial position or results of operations.
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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 37,734 record holders of common units at December 31, 2020.
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, 2020, 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. NOT USED
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 income from the production and marketing of coal to major domestic and international utilities and industrial users as well as 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 underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia, as well as a coal-loading terminal in Indiana. In addition, the 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, 2020, we had approximately 1.65 billion tons of proven and probable coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. We believe we control adequate reserves to implement our currently contemplated mining plans. Please see "Item 1. Business—Coal Mining Operations" for further discussion of our mines.
In 2020, we sold 28.2 million tons of coal and produced 27.0 million tons. The coal we sold in 2020 was approximately 10.6% low-sulfur coal, 51.6% medium-sulfur coal and 37.9% 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 11,400 to 13,200. In 2020, approximately 98.4% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices.
During 2020, approximately 94.2% of our tons sold were purchased by United States electric utilities and 3.3% 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 2020 we began 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 2020, approximately 93.0% of our sales tonnage was sold under long-term sales contracts.
As discussed in more detail in "Item 1A. Risk Factors," 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 legislation and initiatives pursued during previous administrations. Additionally, our results of operations could be impacted by our ability to obtain and renew permits necessary for our operations, secure or acquire coal reserves, 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.
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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 may be substantial and are often the determining factor in a coal consumer's contracting decision. The principal expenses related to our minerals interests business are production and ad valorem taxes.
Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize the return of cash to our unitholders by:
● expanding our operations by adding and developing mines and coal reserves in existing, adjacent or neighboring properties;
● extending the lives of our current mining operations through acquisition and development of coal reserves 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 MLP sector; and
● continuing to make investments in oil & gas mineral interests in various geographic locations within producing basins in the continental United States.
As of December 31, 2020, we had three reportable segments: Illinois Basin, Appalachia and Minerals. We also have an "all other" category referred to as Other and Corporate. The two coal 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 Minerals 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 55,500 net royalty acres, which provide us with diversified exposure to industry leading operators consistent with our strategy to grow our oil & gas mineral interest business. The operations within our Minerals reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests.
● Illinois Basin reportable segment includes currently operating mining complexes (a) Gibson County Coal's mining complex, which includes the Gibson South mine, (b) Warrior's mining complex, (c) River View's mining complex and (d) the Hamilton mining complex. The Illinois Basin reportable segment also includes our Mt. Vernon coal-loading terminal in Indiana which operates on the Ohio River.
The Illinois Basin reportable segment also includes 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, (d) the Hopkins County Coal mining complex, and (e) Sebree's mining complex. The non-operating mining complexes are in various stages of reclamation.
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● Appalachia 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. The Tunnel Ridge mining complex mines reserves in both West Virginia and to a lesser extent, Pennsylvania. The Appalachia reportable segment also includes Penn Ridge assets, which is primarily coal mineral interests.
● Minerals reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II, and includes Alliance Minerals equity interest in both AllDale III and Cavalier Minerals. AR Midland acquired its mineral interests in the Wing 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 AllDale III, respectively.
● Other and Corporate includes marketing and administrative activities, the Matrix Group, Alliance Coal's coal brokerage activity and Alliance Minerals' prior equity investment in Kodiak. In February 2019, Kodiak redeemed our equity investment. In addition, Other and Corporate includes certain Alliance Resource Properties' land and coal mineral interest activities, Pontiki Coal, LLC's workers' compensation and pneumoconiosis liabilities, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, and 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" and " — Note 13 – Investments" of this Annual Report on Form 10-K for more information on AROP Funding, Alliance Finance and Kodiak redemption, respectively.
Market Developments and Our Response for the year ended December 31, 2020
We began the year anticipating our results for the year ended December 31, 2020 would be negatively impacted by challenging coal market conditions primarily due to low natural gas prices, tepid coal demand and the overhang of coal supply. During the first half of the year, mild weather conditions and deteriorating natural gas prices placed increased pressure on the performance of our coal operations. Also, during the first half of the year, our Minerals segment results were impacted by natural gas prices remaining low and the collapse in oil prices following actions by the Organization of Petroleum Exporting Countries and Russia. These downward pressures increased substantially during the first half of the year for both our coal operations and mineral interest activities due to the disruptions to global economies in response to the COVID-19 pandemic resulting in unprecedented demand destruction across all energy markets.
In response to these challenges, we halted production at all of our mining complexes in the Illinois Basin at the end of March and our MC Mining complex in East Kentucky in early April. With an objective of reducing coal production to match existing contracted sales commitments for 2020, we curtailed production at these operations while continuing to meet customer obligations from coal inventories already produced. Throughout the first half of 2020 we monitored coal inventories at each location and worked closely with customers to determine when it would be necessary to resume coal production. Underground production operations resumed in the second quarter at each of our mining complexes and production has continued since that time. However, several mines continue running at less than capacity due to a limited spot market in the United States and a seaborne market that continues to be sub-economic for United States production, but now showing signs of potential pricing improvements. Also in response to these market conditions, we took numerous steps to optimize cash flows, reduce working capital requirements and strictly control capital expenditures and expenses. In addition, the Board of Directors began suspending cash distributions to unitholders with the quarter ended March 31, 2020 and has continued that through the quarter ended December 31, 2020. The Board of Directors intends to reassess its distribution policy at its meeting following the quarter ending March 31, 2021. Future unitholder distributions will be subject to ongoing Board of Directors' review of a number of factors including business and market conditions, our future financial and operating performance outlook and other capital allocation priorities.
During the second half of the year we saw improved economic activity, increased coal demand and some recovering oil & gas production volumes and prices which positively impacted our performance compared to the first half of the year. Higher commodity prices and lower well costs led oil & gas operators to begin bringing previously shut-in wells back online and slowly resume permitting, drilling and completion activity across the regions in which we hold mineral interests.
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Impact of the COVID-19 Pandemic
During the year 2020, a variety of measures in the United States and abroad in response to the COVID-19 pandemic resulted in a reduction in the global demand for energy. These measures included travel restrictions, gathering bans and stay-at-home orders. All of our operations are classified as essential in the states in which we operate. Therefore, to protect our employees during the COVID-19 pandemic, we implemented numerous health and safety protocols designed to contain and mitigate the risk of infection from COVID-19. We continually evaluate the need for further safeguards as the pandemic continues.
As discussed above, we curtailed coal production during the year 2020 in response to global energy demand destruction caused by the COVID-19 pandemic, including the temporary cessation of production at various operations in both the Illinois Basin and Appalachian regions. In light of the downturn in market conditions during the year 2020 and the ongoing uncertainty surrounding the COVID-19 pandemic, we took the following additional actions:
● To mitigate the reduced revenues from lower coal sales volumes and depressed commodity prices impacting our minerals segment, we took numerous efforts to optimize cash flows, reduce working capital requirements and strictly control capital expenditures, operating expenses and general and administrative expenses. Our cost control initiatives during the year 2020 resulted in significant reductions in expenses in each of these categories compared to 2019. The cost reductions are discussed in more detail below.
● On April 26, 2020, the employment of 116 employees of the Gibson County mining complex and 78 employees of the Hamilton mining complex was terminated permanently.
● As stated previously, the Board of Directors began suspending the cash distributions to unitholders with the quarter ended March 31, 2020 and has continued through the quarter ended December 31, 2020.
● In March 2020, we withdrew our initial 2020 operating and financial guidance provided on January 27, 2020, which did not reflect the impact of the COVID-19 pandemic.
● On March 9, 2020, we strengthened our liquidity by entering into a $537.75 million (reducing to $459.5 million on May 23, 2021) revolving credit facility with a termination date of March 9, 2024, replacing the $494.75 million revolving credit facility that was set to expire on May 23, 2021. Please read "Item 8. Financial Statements and Supplementary Data — Note 8 – Long-term Debt" for more information on revolving credit facility.
● We also reduced our total debt by $185.5 million during 2020, further enhancing our liquidity.
We are continuing to monitor and may take further actions to minimize any adverse impact caused by the COVID-19 pandemic.
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 produced; (4) Price per BOE; (5) Segment Adjusted EBITDA Expense per ton; (6) EBITDA; and (7) Segment Adjusted EBITDA.
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.
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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.
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
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. Lower 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.
Year Ended December 31,
Year Ended December 31,
2020
2019
2020
2019
(in thousands)
(per ton/BOE sold)
Tons sold
28,212
39,289
N/A
N/A
Tons produced
26,990
39,981
N/A
N/A
Coal sales
$
1,232,272
$
1,762,442
$
43.68
$
44.86
Coal - Segment Adjusted EBITDA Expense (1) (2)
$
857,143
$
1,197,085
$
30.38
$
30.47
BOE sold (3)
1,792
1,611
N/A
N/A
Oil & gas royalties (4)
$
42,912
$
51,735
$
23.95
$
32.12
(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 our Minerals segment.
(3) Barrels of oil equivalent ("BOE") for natural gas volumes is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
(4) Average sales price per BOE is defined as oil & gas royalties (excluding lease bonus revenue) divided by total BOE.
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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 region, in response to weak market conditions during 2020.
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.
Coal - Segment Adjusted EBITDA Expense . Segment Adjusted EBITDA Expense, excluding our Minerals segment, decreased 28.4% to $857.1 million in 2020, primarily as a result of reduced tons sold. Segment Adjusted EBITDA Expense per ton decreased slightly in 2020 to $30.38 per ton, compared to $30.47 per ton in 2019. The decrease is attributed primarily to ongoing 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.
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 $0.62 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.
Other revenues . Other revenues were principally comprised of Mt. Vernon transloading revenues in our Illinois Basin segment, oil & gas lease bonuses in our Minerals segment and Matrix Design sales in Other & Corporate. 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.
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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 reserves 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 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, oil & gas royalties, BOE volumes and Segment Adjusted EBITDA Expense by segment are as follows:
Year Ended December 31,
2020
2019
Increase (Decrease)
(in thousands)
Segment Adjusted EBITDA
Coal - Illinois Basin
$
236,911
$
385,200
$
(148,289)
(38.5)
%
Coal - Appalachia
172,288
215,950
(43,662)
(20.2)
%
Minerals
39,773
46,997
(7,224)
(15.4)
%
Other and Corporate
6,580
32,911
(26,331)
(80.0)
%
Elimination
(9,063)
(9,057)
(6)
(0.1)
%
Total Segment Adjusted EBITDA (2)
$
446,489
$
672,001
$
(225,512)
(33.6)
%
Tons sold
Coal - Illinois Basin
19,113
28,480
(9,367)
(32.9)
%
Coal - Appalachia
9,099
10,809
(1,710)
(15.8)
%
Other and Corporate
—
564
(564)
(1)
Elimination
—
(564)
564
(1)
Total tons sold
28,212
39,289
(11,077)
(28.2)
%
Coal sales
Coal - Illinois Basin
$
755,208
$
1,128,588
$
(373,380)
(33.1)
%
Coal - Appalachia
477,064
628,406
(151,342)
(24.1)
%
Other and Corporate
—
22,138
(22,138)
(1)
Elimination
—
(16,690)
16,690
(1)
Total coal sales
$
1,232,272
$
1,762,442
$
(530,170)
(30.1)
%
Other revenues
Coal - Illinois Basin
$
2,026
$
13,034
$
(11,008)
(84.5)
%
Coal - Appalachia
14,954
11,166
3,788
33.9
%
Minerals
229
1,301
(1,072)
(82.4)
%
Other and Corporate
25,124
34,712
(9,588)
(27.6)
%
Elimination
(10,517)
(12,173)
1,656
13.6
%
Total other revenues
$
31,816
$
48,040
$
(16,224)
(33.8)
%
BOE volume and oil & gas royalties
Volume - BOE (3)
1,792
1,611
181
11.2
%
Oil & gas royalties
$
42,912
$
51,735
$
(8,823)
(17.1)
%
Segment Adjusted EBITDA Expense
Coal - Illinois Basin
$
520,324
$
756,423
$
(236,099)
(31.2)
%
Coal - Appalachia
319,730
423,623
(103,893)
(24.5)
%
Minerals
4,106
7,811
(3,705)
(47.4)
%
Other and Corporate
18,543
36,845
(18,302)
(49.7)
%
Elimination
(1,454)
(19,806)
18,352
92.7
%
Total Segment Adjusted EBITDA Expense
$
861,249
$
1,204,896
$
(343,647)
(28.5)
%
(1) Percentage change not meaningful.
(2) 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)."
(3) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).
Illinois Basin – Segment Adjusted EBITDA decreased 38.5% to $236.9 million in 2020 from $385.2 million in 2019. The decrease of $148.3 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
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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 31.2% to $520.3 million in 2020 from $756.4 million in 2019 primarily as a result of reduced tons sold. Segment Adjusted EBITDA Expense per ton increased $0.66 per ton sold to $27.22 from $26.56 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 – Segment Adjusted EBITDA decreased 20.2% to $172.3 million for 2020 from $216.0 million in 2019. The decrease of $43.7 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 international markets, amid the COVID-19 pandemic. Coal sales price per ton sold in 2020 decreased 9.8% compared to 2019 primarily due to reduced metallurgical tons sold and price realizations at our Mettiki mine. Segment Adjusted EBITDA Expense decreased 24.5% to $319.7 million in 2020 from $423.6 million in 2019 due to reduced tons sold and decreased per ton costs. Segment Adjusted EBITDA Expense per ton decreased $4.05 per ton sold to $35.14 compared to $39.19 per ton sold in 2019. The lower per ton expense in 2020 resulted primarily from fewer longwall move days and improved recoveries at both our Tunnel Ridge and Mettiki mines, reduced roof support expenses per ton and the absence of higher cost purchased tons sold in 2020, partially offset by curtailed production in the region during 2020 increasing fixed costs per ton. See also certain cost variances described above under "–Coal - Segment Adjusted EBITDA Expense."
Minerals – Segment Adjusted EBITDA decreased to $39.8 million for 2020 from $47.0 million in 2019 reflecting reduced average sales price per BOE due to reduced demand amid the COVID-19 pandemic, partially offset by increased production volumes from the additional mineral interests acquired in the Wing Acquisition in August 2019 and from continued drilling and development activities.
Other and Corporate – Segment Adjusted EBITDA decreased by $26.3 million to $6.6 million in 2020 compared to $32.9 million in 2019. The decrease was primarily attributable to lower equity securities income as a result of the redemption of our preferred interest in Kodiak in 2019, decreased coal brokerage activity and lower mining technology product sales from the Matrix Group.
2019 Compared with 2018
For discussion and analysis of 2019 compared to 2018, please refer to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" of our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on February 20, 2020 and is incorporated by reference herein.
Reconciliation of non-GAAP "Segment Adjusted EBITDA" to GAAP "net income (loss)" and reconciliation of non-GAAP "Segment Adjusted EBITDA Expense" to GAAP "Operating Expenses"
Segment Adjusted EBITDA (a non-GAAP financial measure) is defined as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization, asset and goodwill impairments, acquisition gain and general and administrative expenses. Segment Adjusted EBITDA is a key component of consolidated EBITDA, which is used as a supplemental financial measure by 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 is also used as a supplemental financial measure by our management for reasons similar to those stated in the previous explanation of EBITDA. In addition, the exclusion of corporate general and administrative expenses, which are discussed above under "—Analysis of Historical Results of Operations," from consolidated Segment Adjusted EBITDA allows management 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.
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The following is a reconciliation of consolidated Segment Adjusted EBITDA to net income (loss), the most comparable GAAP financial measure:
Year Ended December 31,
2020
2019
(in thousands)
Consolidated Segment Adjusted EBITDA
$
446,489
$
672,001
General and administrative
(59,806)
(72,997)
Depreciation, depletion and amortization
(313,387)
(309,075)
Asset impairments
(24,977)
(15,190)
Goodwill impairment
(132,026)
—
Interest expense, net
(45,478)
(45,496)
Acquisition gain
—
177,043
Income tax (expense) benefit
(35)
211
Acquisition gain attributable to noncontrolling interest
—
(7,083)
Net income (loss) attributable to ARLP
$
(129,220)
$
399,414
Noncontrolling interest
169
7,512
Net income (loss)
$
(129,051)
$
406,926
Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other income (expense). Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of Segment Adjusted EBITDA in addition to coal sales, royalty revenues and other revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses.
The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expense, the most comparable GAAP financial measure:
Year Ended December 31,
2020
2019
(in thousands)
Segment Adjusted EBITDA Expense
$
861,249
$
1,204,896
Outside coal purchases
—
(23,357)
Other income (expense)
(1,593)
561
Operating expenses (excluding depreciation, depletion and amortization)
$
859,656
$
1,182,100
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Ongoing Acquisition Activities
Consistent with our business strategy, from time to time we engage in discussions with potential sellers regarding our possible acquisitions of certain assets and/or companies of the sellers. For more information on acquisitions, please read "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions" of this Annual Report on Form 10-K.
Liquidity and Capital Resources
Liquidity
We have historically satisfied our working capital requirements and funded our capital expenditures, investments and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions. We believe that existing cash balances, future cash flows from operations and investments, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional investments, debt payments, commitments and distribution payments. Nevertheless, our ability to satisfy our working capital requirements, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control, including the COVID-19 pandemic. Based on our recent operating cash flow results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we anticipate remaining in compliance with the covenants of the Credit Agreement and expect to have sufficient liquidity to fund our operations and growth strategies. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future covenant compliance or liquidity may be adversely affected. Please see "Item 1A. Risk Factors."
In responding to weak market conditions, lower commodity prices, and the lockdown initiated in the first quarter of 2020 to certain areas of the global economy due to the COVID-19 pandemic, the Partnership took numerous actions to optimize cash flows and preserve liquidity by reducing capital expenditures, working capital, costs and expenses, including adjusting its corporate support structure to better align with current operating levels. We have also benefited from certain provisions of the Coronavirus Aid Relief and Economic Security Act of 2020 which modestly increased our short-term liquidity.
Additional actions to enhance our liquidity include our Board of Directors' decisions to suspend cash distributions beginning with the quarter ended March 31, 2020 and continuing through the quarter ended December 31, 2020. We have also strengthened our liquidity by entering into a $537.75 million (reducing to $459.5 million on May 23, 2021) revolving credit facility with a termination date of March 9, 2024, replacing the $494.75 million revolving credit facility that was set to expire on May 23, 2021. On June 5, 2020, we entered into a $14.7 million equipment financing arrangement which provides for forty-eight monthly payments with an implicit interest rate of 6.1%, maturing on June 5, 2024. In addition, in January 2021, we extended the term of the Securitization Facility to January 2022 and reduced the borrowing availability under the facility to $60.0 million from $100 million. We have further enhanced our liquidity by reducing our total debt by $185.5 million during the year ended December 31, 2020.
In May 2018, the Board of Directors approved the establishment of a unit repurchase program authorizing us to repurchase up to $100 million of ARLP common units. The program has no time limit and we 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 us to repurchase any dollar amount or number of units. Since inception through December 31, 2020, we have purchased units for a total of $93.5 million under the program. During the year ended December 31, 2020, we did not repurchase and retire any units. Please read "Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities" for more information on the unit repurchase program.
Mine Development Project
In 2018, we began development of MC Mining's Excel Mine No. 5 which continued through 2019 and into 2020. In July 2020, the Excel Mine No. 5 began production. We expect the Excel Mine No. 5 will enable us to access an additional 15 million tons of coal reserves with an expected mine life of approximately 12 years assuming production levels similar to MC Mining's former Excel Mine No. 4.
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Cash Flows
Cash provided by operating activities was $400.6 million for 2020 compared to $514.9 million for 2019. The decrease in cash provided by operating activities was primarily due to a net loss in 2020 as compared to net income in 2019 adjusted for changes from certain non-cash items discussed above such as the acquisition gain and impairments. The decrease in net income was partially offset by a favorable working capital changes primarily related to trade receivables and inventories.
Net cash used in investing activities was $125.1 million for 2020 compared to $488.1 million for 2019. The decrease in cash used in investing activities was primarily attributable to the AllDale and Wing Acquisitions in 2019 and decreased capital expenditures for mine infrastructure and equipment at various mines in 2020. The decreased net cash used compared to 2019 was partially offset by cash received from the redemption of our Kodiak equity securities in 2019.
Net cash used in financing activities was $256.4 million for 2020 compared to $234.4 million for 2019. The increase in cash used in financing activities was primarily attributable to increase in payments on equipment financings and lower net proceeds from borrowings under the revolving credit facility. These 2020 increases in cash used were partially offset by proceeds received for equipment financings and reduced distributions paid to unitholders in 2020.
Contractual Obligations
We have various commitments primarily related to long-term debt, including finance and operating leases, obligations for estimated future asset retirement obligations costs, workers' compensation and pneumoconiosis, capital projects and pension funding. We expect to fund these commitments with existing cash balances, future cash flows from operations and investments as well as cash provided from borrowings of debt or issuance of equity.
The following table provides details regarding our contractual cash obligations as of December 31, 2020:
Less
Contractual
than 1
1-3
3-5
More than
Obligations
Total
year
years
years
5 years
(in thousands)
Long-term debt
$
603,780
$
73,199
$
41,041
$
489,540
$
—
Future interest obligations (1)
144,405
36,038
67,897
40,470
—
Operating leases
21,858
2,346
4,306
3,368
11,838
Finance leases (2)
2,521
912
1,051
278
280
Purchase obligations for capital projects
19,667
19,667
—
—
—
Reclamation obligations (3)
229,952
6,411
5,293
7,918
210,330
Workers' compensation and pneumoconiosis benefit (3)
294,951
11,165
18,313
14,977
250,496
Pension benefit (3)
65,634
5,629
12,223
13,108
34,674
$
1,382,768
$
155,367
$
150,124
$
569,659
$
507,618
(1) Interest on variable-rate, long-term debt was calculated using rates effective at December 31, 2020 for the remaining term of outstanding borrowings.
(2) Includes amounts classified as interest.
(3) Future commitments for reclamation obligations, workers' compensation and pneumoconiosis and pension are shown at undiscounted amounts. These obligations are primarily statutory, not contractual.
Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include coal reserve leases, indemnifications, transportation obligations and financial instruments with off-balance sheet risk, such as bank letters of credit and surety bonds. Liabilities related to these arrangements are not reflected in our consolidated
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balance sheets, and we do not expect these off-balance sheet arrangements to have any material adverse effects on our financial condition, results of operations or cash flows.
We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers' compensation and other obligations as follows as of December 31, 2020:
Workers'
Reclamation
Compensation
Obligation
Obligation
Other
Total
(in millions)
Surety bonds
$
171.1
$
85.2
$
16.7
$
273.0
Letters of credit
—
10.0
16.8
26.8
Capital Expenditures
Capital expenditures decreased to $121.1 million in 2020 compared to $305.9 million in 2019. See our discussion of "Cash Flows" above concerning the decrease in capital expenditures.
We currently project average estimated annual maintenance capital expenditures over the next five years of approximately $4.90 per ton produced. Our anticipated total capital expenditures, including maintenance capital expenditures, for 2021 are estimated in a range of $120.0 million to $125.0 million. Management anticipates funding 2021 capital requirements with our December 31, 2020 cash and cash equivalents of $55.6 million, cash flows from operations and investments, borrowings under revolving credit and securitization facilities and cash provided from the issuance of debt or equity. We will continue to have significant capital requirements over the long term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.
Insurance
Effective October 1, 2020, we renewed our annual property and casualty insurance program. Our property insurance was procured from our wholly owned captive insurance company, 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.
Debt Obligations
Credit Facility. On March 9, 2020, our Intermediate Partnership entered into a Fifth Amended and Restated Credit Agreement (the "Credit Agreement") with various financial institutions. The Credit Agreement provides for a $537.75 million revolving credit facility, reducing to $459.5 million on May 23, 2021, including a sublimit of $125 million for the issuance of letters of credit and a sublimit of $15.0 million for swingline borrowings (the "Revolving Credit Facility"), with a termination date of March 9, 2024. The Credit Facility replaced the $494.75 million revolving credit facility extended to the Intermediate Partnership under its Fourth Amended and Restated Credit Agreement, dated as of January 27, 2017, by various banks and other lenders that would have expired on May 23, 2021. Concurrently with the entry into the Credit Agreement, we reorganized the entities holding our oil & gas interests such that Alliance Royalty, LLC became a direct wholly owned subsidiary of Alliance Minerals. We incurred debt issuance costs in 2020 of $5.8 million in connection with the Credit Agreement. These debt issuance costs are deferred and amortized as a component of interest expense over the term of the Revolving Credit Facility.
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The Credit Agreement is guaranteed by certain of our Intermediate Partnership's material direct and indirect subsidiaries (the "Restricted Subsidiaries") and is secured by substantially all of the assets of the Restricted Subsidiaries. The Credit Agreement is also guaranteed by Alliance Minerals but the oil and gas minerals assets of Alliance Minerals and its direct and indirect subsidiaries (collectively with Alliance Minerals, the "Unrestricted Subsidiaries") are not collateral under the Credit Agreement. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) the Base Rate at the greater of three benchmarks or (ii) a Eurodollar Rate, plus margins for (i) or (ii), as applicable, that fluctuate depending upon the ratio of Consolidated Debt to Consolidated Cash Flow (each as defined in the Credit Agreement). The Eurodollar Rate, with applicable margin, under the Revolving Credit Facility was 3.01% as of December 31, 2020. At December 31, 2020, we had $21.8 million of letters of credit outstanding with $428.5 million available for borrowing under the Revolving Credit Facility. We incur an annual commitment fee of 0.35% on the undrawn portion of the Revolving Credit Facility. We utilize the Revolving Credit Facility, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments.
The Credit Agreement contains various restrictions affecting the Intermediate Partnership and its Restricted Subsidiaries including, among other things, restrictions on incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates, including transactions with Unrestricted Subsidiaries. In each case, these restrictions are subject to various exceptions. In addition, the payment of cash distributions is restricted if such payment would result in a fixed charge coverage ratio of less than 1.0 to 1.0 (as defined in the Credit Agreement) for the four most recently ended fiscal quarters. The Credit Agreement requires the Intermediate Partnership to maintain (a) a debt to cash flow ratio of not more than 2.5 to 1.0, (b) a cash flow to interest expense ratio of not less than 3.0 to 1.0 and (c) a first lien debt to cash flow ratio of not more than 1.5 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt to cash flow ratio, cash flow to interest expense ratio and first lien debt to cash flow ratio were 1.53 to 1.0, 8.45 to 1.0 and 0.52 to 1.0, respectively, for the trailing twelve months ended December 31, 2020. We remained in compliance with the covenants of the Credit Agreement as of December 31, 2020 and anticipate remaining in compliance with the covenants.
Net restricted assets, as defined by the Securities and Exchange Commission, refers to the amount of our consolidated subsidiaries’ net assets for which the ability to transfer funds to ARLP in the form of cash dividends, loans, advances, or transfers is restricted. As a result of the restrictions contained in the Credit Agreement and our current compliance ratios, the amount of our net restricted assets at December 31, 2020, was $240.8 million.
Senior Notes. On April 24, 2017, the Intermediate Partnership and Alliance Finance, issued an aggregate principal amount of $400.0 million of senior unsecured notes due 2025 ("Senior Notes") in a private placement to qualified institutional buyers. The Senior Notes have a term of eight years, maturing on May 1, 2025 (the "Term") and accrue interest at an annual rate of 7.5%. Interest is payable semi-annually in arrears on each May 1 and November 1. The indenture governing the Senior Notes contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitations on asset sales. The issuers of the Senior Notes may redeem all or a part of the notes at any time at redemption prices set forth in the indenture governing the Senior Notes.
Accounts Receivable Securitization. On December 5, 2014, certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership entered into a $100.0 million accounts receivable securitization facility ("Securitization Facility"). Under the Securitization Facility, certain subsidiaries sell certain trade receivables on an ongoing basis to our Intermediate Partnership, which then sells the trade receivables to AROP Funding, a wholly owned bankruptcy-remote special purpose subsidiary of our Intermediate Partnership, which in turn borrows on a revolving basis up to $100.0 million secured by the trade receivables. After the sale, Alliance Coal, as servicer of the assets, collects the receivables on behalf of AROP Funding. The Securitization Facility bears interest based on a Eurodollar Rate. The agreement governing the Securitization Facility contains customary terms and conditions, including limitations with regards to certain customer credit ratings. In January 2021, we extended the term of the Securitization Facility to January 2022 and reduced the borrowing availability under the facility to $60.0 million. The Securitization Facility was previously scheduled to mature in January 2021. At December 31, 2020, we had a $55.9 million outstanding balance under the Securitization Facility.
May 2019 Equipment Financing . On May 17, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $10.0 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "May 2019 Equipment Financing"). The May 2019 Equipment Financing contains
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customary terms and events of default and provides for thirty-six monthly payments with an implicit interest rate of 6.25%, maturing on May 1, 2022. Upon maturity, the equipment will revert back to the Intermediate Partnership.
November 2019 Equipment Financing . On November 6, 2019, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $53.1 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "November 2019 Equipment Financing"). The November 2019 Equipment Financing contains customary terms and events of default and an implicit interest rate of 4.75%, providing for a four year term with forty-seven monthly payments of $1.0 million and a balloon payment of $11.6 million upon maturity on November 6, 2023. At maturity, the equipment will revert back to the Intermediate Partnership.
June 2020 Equipment Financing . On June 5, 2020, the Intermediate Partnership entered into an equipment financing arrangement accounted for as debt, wherein the Intermediate Partnership received $14.7 million in exchange for conveying its interest in certain equipment owned indirectly by the Intermediate Partnership and entering into a master lease agreement for that equipment (the "June 2020 Equipment Financing"). The June 2020 Equipment Financing contains customary terms and events of default and provides for forty-eight monthly payments with an implicit interest rate of 6.1%, maturing on June 5, 2024. Upon maturity, the equipment will revert back to the Intermediate Partnership.
Other. We also have an agreement with a bank to provide additional letters of credit in an amount of $5.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers' compensation benefits. At December 31, 2020, we had $5.0 million in letters of credit outstanding under this agreement.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. We discuss these estimates and judgments with the audit committee of the Board of Directors ("Audit Committee") periodically. Actual results may differ from these estimates. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of our consolidated financial statements:
Business Combinations and Goodwill
We account for business acquisitions using the purchase method of accounting. See "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions" for more information on the Wing and AllDale Acquisitions. Assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date. The excess of purchase price over fair value of net assets acquired is recorded as goodwill. Given the time it takes to obtain pertinent information to finalize the acquired business' balance sheet, it may be several quarters before we are able to finalize those initial fair value estimates. Accordingly, it is not uncommon for the initial estimates to be subsequently revised. The results of operations of acquired businesses are included in the consolidated financial statements from the acquisition date.
For the Wing Acquisition, we determined a fair value for the acquired mineral interests using a weighting of both income and market approaches. Our income approach primarily comprised of a discounted cash flow model. The assumptions used in the discounted cash flow model included estimated production, projected cash flows, forward oil & gas prices and a risk-adjusted discount rate. Our market approach consisted of the observation of acquisitions in the Permian Basin to determine a market price for similar mineral interests.
For the AllDale Acquisition, in addition to valuing the acquired assets and liabilities, we were required to value our previously held equity method investments in AllDale I & II just prior to the acquisition and record a gain as the fair value was determined to be higher than the carrying value of our equity method investments. We used a discounted cash flow model to re-measure our equity method investments immediately prior to the AllDale Acquisition as well as to value the mineral interests acquired. Assumptions used in our discounted cash flow model are similar to those discussed in the Wing Acquisition above.
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The only indefinite-lived intangible that the Partnership currently has is goodwill. Goodwill is not amortized, but subject to annual reviews on November 30th for impairment at the reporting unit level. Goodwill is assessed for impairment more frequently if events or changes in circumstances indicate that it is more likely than not that goodwill is impaired. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed or operated. A reporting unit is an operating segment or a component that is one level below an operating segment.
The Partnership computes the fair value of its reporting units primarily using the income approach (discounted cash flow analysis). The computations require management to make significant estimates. Critical estimates are used as part of these evaluations include, among other things, the discount rate applied to future earnings reflecting a weighted average cost of capital rate, and projected coal price assumptions. Our estimate of the forward coal sales price curve and future sales volumes are critical assumptions used in our discounted cash flow analysis.
A discounted cash flow analysis requires us to make various judgmental assumptions about sales, operating margins, capital expenditures, working capital and coal sales prices. Assumptions about sales, operating margins, capital expenditures and coal sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows. In determining the fair value of our reporting units, we are required to make significant judgments and estimates regarding the impact of anticipated economic factors on our business. The forecast assumptions used in our assessments make certain assumptions about future pricing, volumes and expected maintenance capital expenditures. Assumptions are also made for a "normalized" perpetual growth rate for periods beyond the long range financial forecast period.
At December 31, 2019, we had $136.4 million of goodwill, of which $132.0 million was associated with the reporting unit representing our Hamilton mine. The goodwill associated with our Hamilton mine was recorded in conjunction with our acquisition of the Hamilton mine on July 31, 2015. During the first quarter of 2020, we assessed certain events and changes in circumstances, including a) adverse industry and market developments, including the impact of the COVID-19 pandemic, b) our response to these developments, including temporarily ceasing production at several mines, including Hamilton and c) our actual performance during the quarter. After consideration of these events and changes in circumstances, we performed an interim test of the goodwill associated with the Hamilton reporting unit comparing Hamilton's carrying amount to its fair value.
We estimated the fair value of the Hamilton reporting unit using a discounted cash flow model. The assumptions used in the discounted cash flow model considered market conditions at the time of the assessment and our estimate of the mine's performance in future years based on the information available to us. The fair value of the Hamilton reporting unit was determined to be below its carrying amount (including goodwill) by more than the recorded balance of goodwill associated with the reporting unit. Accordingly, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill allocated to the Hamilton reporting unit. This impairment charge reduced our consolidated goodwill balance to $4.4 million. During the first quarter of 2020 and as part of our annual impairment evaluation on November 30, 2020, we also performed tests on our goodwill balance associated with our MAC reporting unit using a discounted cash flow model and concluded no impairment was necessary. There were no impairments of goodwill during 2019 or 2018.
Our estimates of fair value are sensitive to changes in variables, certain of which relate to broader macroeconomic conditions outside our control. As a result, actual performance in the near and longer-term could be different from these expectations and assumptions. This could be caused by events such as strategic decisions made in response to economic and competitive conditions and the impact of economic factors, such as over production in coal and low prices of natural gas. In addition, some of the inherent estimates and assumptions used in determining fair value of the reporting units are outside the control of management, including interest rates, cost of capital and our credit ratings. While we believe we have made reasonable estimates and assumptions to calculate the fair value of the reporting units and other intangible assets, it is possible a material change could occur. See "Item 8. Financial Statements and Supplementary Data—Note 5 – Goodwill Impairment."
Oil & Gas Reserve Values
Estimated oil & gas reserves and estimated market prices for oil & gas are a significant part of our depletion calculations, impairment analyses, and other estimates. Following are examples of how these estimates affect financial results:
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● an increase (decrease) in estimated proved oil & gas reserves can reduce (increase) our units of production depreciation, depletion and amortization rates; and
● changes in oil & gas reserves and estimated market prices both impact projected future cash flows from our mineral interests. This in turn can impact our periodic impairment analysis.
The process of estimating oil & gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, our proved reserves estimates are compared to proved reserves that are audited by independent experts in connection with our required year-end reporting. The data may change substantially over time as a result of numerous factors, including the historical 12 month average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil & gas mineral interests and have an impact on our depreciation, depletion and amortization expense prospectively.
Estimates of future commodity prices utilized in our impairment analyses consider market information including published forward oil & gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating third party operator drilling decisions and our expected acquisition plans, if any. Prices for future periods will impact the production economics underlying oil & gas reserve estimates. In addition, changes in the price of oil & gas also impact certain costs associated with our expected underlying production and future capital costs. The prices of oil & gas are volatile and change from period to period, thus are expected to impact our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil & gas mineral interests. There were no impairments of our oil & gas mineral interests during 2020.
Workers ' Compensation and Pneumoconiosis (Black Lung) Benefits
We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. We generally provide for these claims through self-insurance programs. Workers' compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuary estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. See "Item 8. Financial Statements and Supplementary Data—Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits" for additional discussion. We had accrued liabilities for workers' compensation of $54.7 million and $53.4 million for these costs at December 31, 2020 and 2019, respectively. A one-percentage-point reduction in the discount rate would have increased operating expense by approximately $4.3 million at December 31, 2020. We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for a particular claim year have been met. Our receivables for traumatic injury claims under this policy as of December 31, 2020 and 2019 are $7.1 million and $7.7 million, respectively.
Coal mining companies are subject to Federal Coal Mine Health and Safety Act of 1969, as amended, 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 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. We had accrued liabilities of $108.5 million and $97.7 million for the pneumoconiosis benefits at December 31, 2020 and 2019, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2020 by approximately $4.4 million. Under the service cost method used to estimate our pneumoconiosis benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions, such as the discount rate, are amortized over the remaining service period of active miners.
The discount rate for workers' compensation and pneumoconiosis is derived by applying the Financial Times Stock Exchange Pension Discount Curve to the projected liability payout. Other assumptions, such as claim development patterns, mortality, disability incidence and medical costs, are based upon standard actuarial tables adjusted for our actual historical experiences whenever possible. We review all actuarial assumptions periodically for reasonableness and consistency and update such factors when underlying assumptions, such as discount rates, change or when sustained changes in our historical experiences indicate a shift in our trend assumptions are warranted.
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Impairment of Long-Lived Assets
In addition to oil & gas reserves discussed above in the Oil & Gas Reserve Values section, we review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based upon estimated undiscounted future cash flows. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include:
● A significant decrease in the market price of a long-lived asset;
● A significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition;
● A significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset, including an adverse action of assessment by a regulator;
● An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
● A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; or
● A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The term more likely that not refers to a level of likelihood that is more than 50 percent.
The above factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. If there is an indication that the carrying amount of an asset may not be recovered, we compare our estimate of undiscounted future cash flows attributable to the asset to the carrying value of the asset. Individual assets are grouped for impairment review purposes based on the lowest level for which there is identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a by-mine basis. Assumptions about sales, operating margins, capital expenditures and sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, t he amount of impairment is measured by the difference between the carrying value and the fair value of the asset. The fair value of impaired assets is typically determined based on various factors, including the present values of expected future cash flows using a risk adjusted discount rate, the marketability of coal properties and the estimated fair value of assets that could be sold or used at other operations. We recorded asset impairments of $25.0 million, $15.2 million and $40.5 million in 2020, 2019 and 2018, respectively. See "Item 8. Financial Statements and Supplementary Data—Note 4 – Long-Lived Asset Impairments".
Asset Retirement Obligations
SMCRA and similar state statutes require that mined property be restored in accordance with specified standards and an approved reclamation plan. A liability is recorded for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred or acquired and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support surface acreage for both our underground mines and past surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Accrued liabilities of $127.9 million and $137.5 million for these costs are recorded at December 31, 2020 and 2019, respectively. See "Item 8. Financial Statements and Supplementary Data—Note 19 – Asset Retirement Obligations" for additional information. The liability for asset retirement and closing procedures is sensitive to changes in cost estimates, estimated mine lives and timing of post-mine reclamation activities. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.
Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. Depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets.
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On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustments for permit changes approved by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Adjustments to the liability associated with these assumptions resulted in a decrease of $11.9 million for the year ended December 31, 2020. There were no material adjustments to the liability associated with these assumptions for the year ended December 31, 2019.
While the precise amount of these future costs cannot be determined with certainty, we have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted and recorded at the present value of those estimates. Discounting resulted in reducing the accrual for asset retirement obligations by $102.1 million and $102.9 million at December 31, 2020 and 2019. We estimate that the aggregate undiscounted cost of final mine closure is approximately $230.0 million and $240.5 million at December 31, 2020 and 2019, respectively. If our assumptions differ from actual experiences, or if changes in the regulatory environment occur, our actual cash expenditures and costs that we incur could be materially different than currently estimated.
Shelf Registration Statement
In February 2018, we filed with the SEC a universal shelf registration statement allowing us to issue from time to time an indeterminate amount of debt or equity securities ("2018 Registration Statement"). At February 23, 2021, we had not utilized any amounts available under the 2018 Registration Statement.
Related – Party Transactions
See "Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions" for a discussion of our related-party transactions.
Accruals of Other Liabilities
We had accruals for other liabilities, including current obligations, totaling $321.3 million and $315.9 million at December 31, 2020 and 2019, respectively. These accruals were chiefly comprised of workers' compensation benefits, pneumoconiosis benefits, and costs associated with asset retirement obligations. These obligations are self-insured except for certain excess insurance coverage for workers' compensation. The accruals of these items were based on estimates of future expenditures based on current legislation, related regulations and other developments. Thus, from time to time, our results of operations may be significantly affected by changes to these liabilities. Please see "Item 8. Financial Statements and Supplementary Data—Note 19 – Asset Retirement Obligations" and "—Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits."
Inflation
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. Please see "Item 1A. Risk Factors."
New Accounting Standards
See "Item 8. Financial Statements and Supplementary Data—Note 2 – Summary of Significant Accounting Policies" for a discussion of new accounting standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
We have significant long-term sales contracts as evidenced by approximately 93.0% of our sales tonnage being sold under long-term sales contracts in 2020. Most of the long-term sales contracts are 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. For additional discussion of coal supply agreements, please see "Item 1. Business—Coal Marketing and Sales" and "Item 8. Financial Statements and
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Supplementary Data—Note 23 – Concentration of Credit Risk and Major Customers." As of February 1, 2021, our nominal commitment under contract was approximately 24.1 million tons in 2021.
Our results of operations are highly dependent upon the prices we receive for our coal, oil and natural gas. Regarding coal, the short-term sales contracts favored by some of our coal customers leave us more exposed to risks of declining coal price periods. Regarding oil & natural gas, as seen in our 2020 results, lower sales price realizations, caused by lower global energy demand during the COVID-19 pandemic and actions of major oil producing countries, had a significant impact on our royalty revenues. Please see discussions above, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for more information regarding the impact of the COVID-19 pandemic and lower oil and natural gas prices on the results of our operations for 2020.
We have exposure to coal and oil & gas sales prices and price risk for supplies that are used directly or indirectly in the normal course of coal and oil & gas production such as steel, electricity and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. Historically, we have not utilized any commodity price-hedges or other derivatives related to either our sales price or supply cost risks but may do so in the future.
Credit Risk
In 2020, approximately 94.2% of our tons sold were purchased by United States electric utilities and 3.3% were sold into the international markets through brokered transactions. Therefore, our credit risk is primarily with domestic electric power generators and reputable global brokerage firms. Our policy is to independently evaluate each customer's creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay. Such credit risks from customers may impact the borrowing capacity of our Securitization Facility. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Debt Obligations – Accounts Receivable Securitization ".
Exchange Rate Risk
Almost all of our transactions are denominated in United States dollars, and as a result, we do not have material exposure to currency exchange-rate risks. However, because coal is sold internationally in United States dollars, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. If our competitors' currencies decline against the United States dollar or against foreign purchasers' local currencies, those competitors may be able to offer lower prices for coal to these 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 to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets.
Interest Rate Risk
Borrowings under the Revolving Credit Facility and Securitization Facility are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates and we have not utilized interest rate derivative instruments related to our outstanding debt. We had $87.5 million in borrowings under the Revolving Credit Facility and $55.9 million in borrowings under the Securitization Facility at December 31, 2020. A one percentage point increase in the interest rates related to the Revolving Credit Facility and Securitization Facility would result in an annualized increase in interest expense of $1.4 million, based on borrowing levels at December 31, 2020. With respect to our fixed-rate borrowings, we had $400.0 million in borrowings under our Senior Notes and $60.4 million in borrowings under our equipment financings at December 31, 2020. A one percentage point increase in interest rates would result in a decrease of approximately $18.1 million in the estimated fair value of these borrowings.
The table below provides information about our market sensitive financial instruments and constitutes a "forward-looking statement." The fair values of long-term debt are estimated using discounted cash flow analyses, based upon our incremental borrowing rates for similar types of borrowing arrangements as of December 31, 2020 and 2019.
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The carrying amounts and fair values of financial instruments are as follows:
Fair Value
Expected Maturity Dates
December 31,
as of December 31, 2020
2021
2022
2023
2024
2025
Thereafter
Total
2020
(dollars in thousands)
Fixed rate debt
$
17,299
$
16,071
$
24,970
$
2,040
$
400,000
$
—
$
460,380
$
376,781
Weighted-average interest rate
7.23
%
7.31
%
7.40
%
7.50
%
7.50
%
—
Variable rate debt
$
55,900
$
—
$
—
$
87,500
$
—
$
—
$
143,400
$
141,536
Weighted-average interest rate (1)
2.97
%
3.01
%
3.01
%
3.01
%
—
—
Fair Value
Expected Maturity Dates
December 31,
as of December 31, 2019
2020
2021
2022
2023
2024
Thereafter
Total
2019
(dollars in thousands)
Fixed rate debt
$
13,158
$
13,847
$
12,403
$
21,072
$
—
$
400,000
$
460,480
$
407,775
Weighted-average interest rate
7.20
%
7.26
%
7.33
%
7.41
%
7.50
%
7.50
%
Variable rate debt
$
—
$
328,800
$
—
$
—
$
—
$
—
$
328,800
$
328,431
Weighted-average interest rate (1)
4.12
%
4.39
%
—
—
—
—
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