10-K

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

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 1/8th, 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.  

1

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

49

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

51

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 SO2 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, the 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	%		—			—			—			—

(1) Interest rate of variable rate debt equal to the rate effective at December 31, 2020 and 2019, held constant for the remaining term of the outstanding borrowing.

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ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page
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
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

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Alliance Resource Management GP, LLC

and the Partners of Alliance Resource Partners, L.P.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Alliance Resource Partners, L.P. and subsidiaries (the Partnership) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), cash flows and partners’ capital for each of the three years in the period ended December 31, 2020, and the related notes and financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”).  In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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	Valuation of workers’ compensation and pneumoconiosis benefits
Description of the Matter	As more fully described at Note 20 to the consolidated financial statements, the Partnership provides income replacement and medical treatment for work-related traumatic injury claims, as required by applicable laws. Workers' compensation laws also compensate survivors of workers who suffer employment-related deaths.  Certain of the Partnership’s mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents. At December 31, 2020, the Partnership’s aggregate workers’ compensation and pneumoconiosis benefits were $163 million. Auditing management’s estimate of the workers’ compensation and pneumoconiosis benefits was complex due to the use of a blend of actuarial projection methods and numerous assumptions including claim development patterns, costs, and mortality in the liability calculations.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls over management’s workers’ compensation and pneumoconiosis benefits process. For example, we tested controls over management’s review of the liability calculations and the appropriateness of the significant assumptions used, including the completeness and accuracy of the underlying data. To test the workers’ compensation and pneumoconiosis benefits, our audit procedures included, among others, evaluating the methodology used, the significant actuarial assumptions described above and the underlying data used by the Partnership. We involved our actuarial specialists to assist in evaluating management’s methodology and for testing the claim development patterns, costs and mortality assumptions. We compared the claim development pattern and cost assumptions used by management for consistency with historical experience and current trends. We also developed independent ranges and compared those ranges to management’s best estimate.  To evaluate the use of mortality tables, we assessed whether the information used by management is consistent with publicly-available information. We also tested the completeness and accuracy of the underlying data used by management.
	Long-lived asset recoverability analyses
Description of the Matter	As more fully described in Note 4 to the consolidated financial statements, in 2020, due to the uncertainty related to energy demand, the Partnership performed recoverability tests on its coal mining operations. Based on the Partnership’s recoverability analyses, it is projected to recover all asset costs, excluding current year impairments which are discussed further in Note 4.

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Auditing the Partnership’s coal asset recoverability analyses involved subjectivity, as management’s estimates to determine future cash flows were based on assumptions about future market and economic conditions. Significant assumptions used in the Partnership’s future cash flows included estimates of future sales volumes, sales prices, operating margins and capital expenditures.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls over its recoverability test process. For example, we tested controls over management’s review of the significant assumptions underlying the future cash flows and of the completeness and accuracy of the data used in performance of the analysis. To test the Partnership’s asset recoverability analyses, our audit procedures included, among others, evaluating the appropriateness of the methodology used to develop the cash flow models, as well as testing the significant assumptions used and the completeness and accuracy of the underlying data. We evaluated management’s assumptions by comparing key inputs to current industry, market and economic trends, as well as customer contract terms and historical financial relationships. We also performed sensitivity analyses and a retrospective comparison of forecasted cash flows to actual historical data.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2011.

Tulsa, Oklahoma

February 23, 2021

85

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2020 AND 2019

(In thousands, except unit data)

	December 31,
	2020		2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	55,574	$	36,482
Trade receivables		104,579		161,679
Other receivables		3,481		256
Inventories, net		56,407		101,305
Advance royalties		4,168		1,844
Prepaid expenses and other assets		21,565		18,019
Total current assets		245,774		319,585
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost		3,554,090		3,684,008
Less accumulated depreciation, depletion and amortization		(1,753,845)		(1,675,022)
Total property, plant and equipment, net		1,800,245		2,008,986
OTHER ASSETS:
Advance royalties		56,791		52,057
Equity method investments		27,268		28,529
Goodwill		4,373		136,399
Operating lease right-of-use assets		15,004		17,660
Other long-term assets		16,561		23,478
Total other assets		119,997		258,123
TOTAL ASSETS	$	2,166,016	$	2,586,694
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	47,511	$	80,566
Accrued taxes other than income taxes		25,054		15,768
Accrued payroll and related expenses		28,524		36,575
Accrued interest		5,132		5,664
Workers' compensation and pneumoconiosis benefits		10,646		11,175
Current finance lease obligations		766		8,368
Current operating lease obligations		1,854		3,251
Other current liabilities		21,919		21,062
Current maturities, long-term debt, net		73,199		13,157
Total current liabilities		214,605		195,586
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities, net		519,421		768,194
Pneumoconiosis benefits		105,068		94,389
Accrued pension benefit		46,965		44,858
Workers' compensation		47,521		45,503
Asset retirement obligations		121,487		133,018
Long-term finance lease obligations		1,458		2,224
Long-term operating lease obligations		13,078		14,316
Other liabilities		24,146		23,182
Total long-term liabilities		879,144		1,125,684
Total liabilities		1,093,749		1,321,270
PARTNERS' CAPITAL:
ARLP Partners' Capital:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively		1,148,565		1,331,482
Accumulated other comprehensive loss		(87,674)		(77,993)
Total ARLP Partners' Capital		1,060,891		1,253,489
Noncontrolling interest		11,376		11,935
Total Partners' Capital		1,072,267		1,265,424
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	2,166,016	$	2,586,694

See notes to consolidated financial statements.

86

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands, except unit and per unit data)

	Year Ended December 31,
	2020		2019		2018
SALES AND OPERATING REVENUES:
Coal sales	$	1,232,272	$	1,762,442	$	1,844,808
Oil & gas royalties		42,912		51,735		—
Transportation revenues		21,129		99,503		112,385
Other revenues		31,816		48,040		45,664
Total revenues		1,328,129		1,961,720		2,002,857
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)		859,656		1,182,100		1,207,713
Transportation expenses		21,129		99,503		112,385
Outside coal purchases		—		23,357		1,466
General and administrative		59,806		72,997		68,298
Depreciation, depletion and amortization		313,387		309,075		280,225
Settlement gain		—		—		(80,000)
Asset impairments		24,977		15,190		40,483
Goodwill impairment		132,026		—		—
Total operating expenses		1,410,981		1,702,222		1,630,570
INCOME (LOSS) FROM OPERATIONS		(82,852)		259,498		372,287
Interest expense (net of interest capitalized of $1,325, $1,211 and $1,306, respectively)		(45,613)		(45,875)		(40,218)
Interest income		135		379		159
Equity method investment income		907		2,203		22,189
Equity securities income		—		12,906		15,696
Acquisition gain		—		177,043		—
Other income (expense)		(1,593)		561		(2,621)
INCOME (LOSS) BEFORE INCOME TAXES		(129,016)		406,715		367,492
INCOME TAX EXPENSE (BENEFIT)		35		(211)		22
NET INCOME (LOSS)		(129,051)		406,926		367,470
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		(169)		(7,512)		(866)
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	$	(129,220)	$	399,414	$	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER	$	—	$	—	$	1,560
LIMITED PARTNERS	$	(129,220)	$	399,414	$	365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$	(1.02)	$	3.07	$	2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED		127,164,659		128,116,670		130,758,169

See notes to consolidated financial statements.

87

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands)

	Year Ended December 31,
	2020		2019		2018
NET INCOME (LOSS)	$	(129,051)	$	406,926	$	367,470
OTHER COMPREHENSIVE INCOME (LOSS):
Defined benefit pension plan
Amortization of prior service cost (1)		186		186		186
Net actuarial loss		(5,522)		(7,350)		(3,326)
Amortization of net actuarial loss (1)		4,128		3,922		3,608
Total defined benefit pension plan adjustments		(1,208)		(3,242)		468
Pneumoconiosis benefits
Net actuarial gain (loss)		(7,787)		(23,298)		4,599
Amortization of net actuarial loss (gain) (1)		(686)		(4,582)		2
Total pneumoconiosis benefits adjustments		(8,473)		(27,880)		4,601
OTHER COMPREHENSIVE INCOME (LOSS)		(9,681)		(31,122)		5,069
COMPREHENSIVE INCOME (LOSS)		(138,732)		375,804		372,539
Less: Comprehensive income attributable to noncontrolling interest		(169)		(7,512)		(866)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO ARLP	$	(138,901)	$	368,292	$	371,673

(1) Amortization of prior service cost and actuarial gain or loss is included in the computation of net periodic benefit cost (see Notes 16 and 20 for additional details).

See notes to consolidated financial statements.

88

ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands)

	Year Ended December 31,
	2020		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(129,051)	$	406,926	$	367,470
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		313,387		309,075		280,225
Non-cash compensation expense		3,345		11,934		12,114
Asset retirement obligations		4,033		4,087		3,926
Coal inventory adjustment to market		3,245		4,895		1,455
Equity investment income		(907)		(2,203)		(22,189)
Distributions from equity method investments		907		2,203		21,971
Income from equity securities paid-in-kind		—		(712)		(15,696)
Net loss (gain) on sale of property, plant and equipment		(5,850)		109		(1,285)
Asset impairment		24,977		15,190		40,483
Goodwill impairment		132,026		—		—
Acquisition gain, net		—		(177,043)		—
Cash received on redemption of equity securities in excess of investment		—		(11,482)		—
Valuation allowance of deferred tax assets		1,151		(413)		(1,560)
Other		6,631		5,677		3,171
Changes in operating assets and liabilities:
Trade receivables		56,172		20,841		6,757
Other receivables		(3,225)		3,726		(249)
Inventories, net		30,522		(35,082)		(747)
Prepaid expenses and other assets		(2,514)		6,136		7,387
Advance royalties		(7,690)		(9,876)		(8,782)
Accounts payable		(24,282)		(17,671)		(813)
Accrued taxes other than income taxes		9,286		(994)		(3,614)
Accrued payroll and related benefits		(8,051)		(6,538)		7,362
Pneumoconiosis benefits		2,340		(2,292)		1,837
Workers' compensation		1,355		3,845		(4,900)
Other		(7,162)		(15,443)		22
Total net adjustments		529,696		107,969		326,875
Net cash provided by operating activities		400,645		514,895		694,345
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures		(121,101)		(305,858)		(233,480)
Decrease in accounts payable and accrued liabilities		(8,773)		(81)		(1,051)
Proceeds from sale of property, plant and equipment		3,762		1,266		2,409
Contributions to equity method investments		—		—		(15,600)
Distributions received from investments in excess of cumulative earnings		988		2,501		2,473
Payments for acquisitions of businesses, net of cash acquired		—		(320,232)		—
Cash received from redemption of equity securities		—		134,288		—
Net cash used in investing activities		(125,124)		(488,116)		(245,249)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under securitization facility		46,100		184,500		304,600
Payments under securitization facility		(64,000)		(202,700)		(285,000)
Proceeds from equipment financings		14,705		63,086		—
Payments on equipment financings		(14,805)		(2,607)		—
Borrowings under revolving credit facilities		70,000		400,000		245,000
Payments under revolving credit facilities		(237,500)		(320,000)		(100,000)
Payments on finance lease obligations		(8,368)		(46,725)		(29,353)
Payment of debt issuance costs		(6,280)		—		—
Payments for purchases of units under unit repurchase program		—		(22,892)		(70,604)
Payments for taxes related to net settlement of issuance of units in deferred compensation plans		(1,310)		(7,817)		(2,081)
Cash settlement of grants under deferred compensation plan		(2,490)		—		—
Cash contributions by General Partner		—		—		41
Cash contribution by affiliated entity		—		—		2,142
Cash obtained in Simplification Transactions		—		—		1,139
Distributions paid to Partners		(51,753)		(278,425)		(275,902)
Other		(728)		(867)		(1,684)
Net cash used in financing activities		(256,429)		(234,447)		(211,702)
NET CHANGE IN CASH AND CASH EQUIVALENTS		19,092		(207,668)		237,394
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		36,482		244,150		6,756
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	55,574	$	36,482	$	244,150

See notes to consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands, except unit data)

	Number of					Accumulated
	Limited					Other
	Partner	Limited Partners'		General Partners’		Comprehensive		Noncontrolling		Total Partners'
	Units	Capital		Capital (Deficit)		Income (Loss)		Interest		Capital
Balance at January 1, 2018	130,704,217	$	1,183,219	$	14,859	$	(51,940)	$	5,348	$	1,151,486
Comprehensive income:
Net income	—		365,044		1,560		—		866		367,470
Actuarially determined long-term liability adjustments	—		—		—		5,069		—		5,069
Total comprehensive income											372,539
Settlement of deferred compensation plans	199,039		(2,745)		—		—		—		(2,745)
Issuance of units to Owners of SGP in Simplification Transactions	1,322,388		14,742		(15,106)		—		—		(364)
Issuance of units to SGP related to Exchange Transaction	20,960		—		—		—		—		—
Simplification Transactions fees	—		(96)		—		—		—		(96)
Contribution of units and cash by affiliated entity	(467,018)		2,142		—		—		—		2,142
Purchase of units under unit repurchase program	(3,684,075)		(70,604)		—		—		—		(70,604)
Common unit-based compensation	—		12,114		—		—		—		12,114
Distributions on deferred common unit-based compensation	—		(3,855)		—		—		—		(3,855)
General Partner contribution	—		—		41		—		—		41
Distributions from consolidated company to noncontrolling interest	—		—		—		—		(924)		(924)
Distributions to Partners	—		(270,693)		(1,354)		—		—		(272,047)
Balance at December 31, 2018	128,095,511		1,229,268		—		(46,871)		5,290		1,187,687
Comprehensive income:
Net income	—		399,414		—		—		7,512		406,926
Actuarially determined long-term liability adjustments	—		—		—		(31,122)		—		(31,122)
Total comprehensive income											375,804
Settlement of deferred compensation plans	596,650		(7,817)		—		—		—		(7,817)
Purchase of units under unit repurchase program	(1,776,564)		(22,892)		—		—		—		(22,892)
Common unit-based compensation	—		11,934		—		—		—		11,934
Distributions on deferred common unit-based compensation	—		(3,670)		—		—		—		(3,670)
Distributions from consolidated company to noncontrolling interest	—		—		—		—		(867)		(867)
Distributions to Partners	—		(274,755)		—		—		—		(274,755)
Balance at December 31, 2019	126,915,597		1,331,482		—		(77,993)		11,935		1,265,424
Comprehensive income (loss):
Net income (loss)	—		(129,220)		—		—		169		(129,051)
Actuarially determined long-term liability adjustments	—		—		—		(9,681)		—		(9,681)
Total comprehensive loss											(138,732)
Settlement of deferred compensation plans	279,622		(3,800)		—		—		—		(3,800)
Common unit-based compensation	—		3,345		—		—		—		3,345
Distributions on deferred common unit-based compensation	—		(986)		—		—		—		(986)
Distributions from consolidated company to noncontrolling interest	—		—		—		—		(728)		(728)
Distributions to Partners	—		(50,767)		—		—		—		(50,767)
Other	—		(1,489)		—		—		—		(1,489)
Balance at December 31, 2020	127,195,219	$	1,148,565	$	—	$	(87,674)	$	11,376	$	1,072,267

See notes to consolidated financial statements.

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ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

1.ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Consolidated Financial Statements

● 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.

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol "ARLP."  ARLP was formed in May 1999 and completed its initial public offering on August 19, 1999 when it acquired substantially all of the coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation ("ARH"), and its subsidiaries. We are managed by our general partner, MGP, a Delaware limited liability company which holds a non-economic general partner interest in ARLP.  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 the transactions.  See discussions under Partnership Simplification regarding changes in ownership of ARLP and MGP as a result of the Simplification Transactions in 2018.

Partnership Simplification

On February 22, 2018, the board of directors ("Board of Directors") of MGP and the board of directors of AGP 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 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.  

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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.

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 "AllDale Acquisition Date"), we acquired 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") and the general partner interests in AllDale I & II (the "AllDale Acquisition").  As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres in premier oil & gas resource plays.  The AllDale Acquisition provides us with diversified exposure to industry leading operators and is consistent with our general business strategy to grow our Minerals segment. See Note 3 – Acquisitions for more information.

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 enhances our ownership position in the Permian Basin, expands our exposure to industry leading operators and furthers our business strategy to grow our Minerals segment.  Following the Wing Acquisition, we hold approximately 55,700 net royalty acres in premier oil & gas basins including our investment in AllDale Minerals III, LP ("AllDale III").  See Note 3 – Acquisitions for more information.

Presentation

The consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2020 and 2019, and results of our operations, comprehensive income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2020.  All of our intercompany transactions and accounts have been eliminated.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation—The consolidated financial statements present the consolidated financial position, results of operations and cash flows of ARLP, the Intermediate Partnership, Alliance Coal and other directly and indirectly wholly- and majority-owned subsidiaries of ARLP.  For the periods presented prior to the Simplification Transactions, MGP's interests in both Alliance Coal and the Intermediate Partnership are reported as part of the general partner's interest in the ARLP Partnership's consolidated financial statements.  All intercompany transactions and accounts have been eliminated.  See Note 1 – Organization and Presentation for more information regarding the Simplification Transactions.

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Variable Interest Entity ("VIE")—VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. A VIE must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE's primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by other parties. See Note 12 – Variable Interest Entities for further information.

Estimates—The preparation of consolidated financial statements in conformity with generally accepted accounting principles of the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates. Significant estimates and assumptions include:

● Impairment assessments of investments, property, plant and equipment, and goodwill;

● Asset retirement obligations;

● Pension valuation variables;

● Workers' compensation and pneumoconiosis valuation variables;

● Acquisition related purchase price allocations;

● Life of mine assumptions;

● Oil & gas reserve quantities and carrying amounts; and

● Determination of oil & gas revenue accruals

These significant estimates and assumptions are discussed throughout these notes to the consolidated financial statements.

Fair Value Measurements—We apply fair value measurements to certain assets and liabilities.  Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations.  Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid).  Valuation techniques used in our fair value measurements are based upon observable and unobservable inputs.  Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

● Level 1 – Quoted prices for identical assets and liabilities in active markets that we have the ability to access at the measurement date.

● Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

● Level 3 – Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. Significant fair value measurements are used in our significant estimates and are discussed throughout these notes.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less.

Cash Management—The cash flows from operating activities section of our consolidated statements of cash flows reflects immaterial adjustments representing book overdrafts.  We did not have material book overdrafts at December 31, 2020, 2019 and 2018.

Inventories—Coal inventories are stated at the lower of cost or net realizable value on a first-in, first-out basis.  Supply inventories are stated at an average cost basis, less a reserve for obsolete and surplus items.

Business Combinations—For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.

Goodwill—Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead is evaluated for impairment periodically. We evaluate goodwill for impairment annually on November 30th, or more often if events or circumstances indicate that goodwill might be 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. During 2020, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill allocated to our Hamilton reporting unit.  See Note 5 – Goodwill Impairment for more information.  There were no impairments of goodwill during 2019 or 2018.

Property, Plant and Equipment—Expenditures which extend the useful lives of existing plant and equipment assets are capitalized.  Interest costs associated with major asset additions are capitalized during the construction period.  Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred.  Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Land, machinery and equipment under finance lease agreements are capitalized and amortized over the useful lives of the assets given that in each case, ownership transfers at the end of the lease term.  Preparation plants, processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method over a range from 1 to 22 years.  Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the estimated useful lives of the assets, ranging from 1 to 22 years, limited by the remaining estimated life of each mine.  Depreciable lives for buildings, office equipment and improvements range from 1 to 22 years. Gains or losses arising from retirements are included in operating expenses.  Depletion of coal mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage, which equals estimated proven and probable reserves. Therefore, our coal mineral rights are depleted based on only proven and probable reserves. See Oil & Gas Reserve Quantities and Carrying Amounts below for a discussion of our accounting policies for oil & gas properties.

Mine Development Costs—Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized on a units of production method based on the estimated proven and probable reserves.  Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.  The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete.  Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.  

Leases—We lease buildings and equipment under operating lease agreements that provide for the payment of minimum rentals.  We also have noncancelable lease agreements with third parties for land and equipment under finance

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lease obligations.  Some of our arrangements within these agreements have both lease and non-lease components, which are generally accounted for separately.  We have elected a practical expedient to account for lease and non-lease components as a single lease component for leases of buildings and office equipment.  Our leases have approximate lease terms of one year to 20 years, some of which include automatic renewals up to ten years which are likely to be exercised, and some of which include options to terminate the lease within one year.  We also hold numerous mineral reserve leases with both related parties as well as third parties, none of which are accounted for as an operating lease or as a finance lease.  

We review each agreement to determine if an arrangement within the agreement contains a lease at the inception of an arrangement.  Once an arrangement is determined to contain either an operating or finance lease with a term greater than 12 months, we recognize a lease liability for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term based on the present value of lease payments over the lease term. The lease term includes all noncancelable periods defined in the lease as well as periods covered by options to extend the lease that we are reasonably certain to exercise.  As an implicit borrowing rate cannot be determined under most of our leases, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments.

Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease term including any reasonably assured renewal periods, while those determined to be finance leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the income statement.  The determination of whether a lease is accounted for as a finance lease or an operating lease requires management to make estimates primarily about the fair value of the asset and its estimated economic useful life.

Long-Lived Asset Impairment—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.  To the extent the carrying amount is not recoverable, the amount of impairment is measured by the difference between the carrying value and the fair value of the asset (See Note 4 – Long-Lived Asset Impairments).

Oil & Gas Reserve Quantities and Carrying Amounts—We are wholly dependent on third-party operators to explore, develop, produce and operate the properties associated with our mineral interests.  We follow the successful efforts method of accounting for our oil & gas mineral interests. Under this method, costs to acquire mineral interests in oil & gas properties are capitalized when incurred. The costs of mineral interests in unproved properties are capitalized pending the results of exploration and leasing efforts by operators. As mineral interests in unproved properties are determined to be proved, the related costs are transferred to proved oil & gas properties.

Mineral interests in oil & gas properties are grouped using a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, which we may also refer to as a depletable group. Mineral interests in proved oil & gas properties are depleted based on the units-of-production method.  Proved reserves are quantities of oil & gas that can be estimated with reasonable certainty to be recoverable in the future from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations.  Proved developed resources are the quantities expected to be recovered through our operators' existing wells with existing equipment, infrastructure and operating methods.

We evaluate impairment of our mineral interests in proved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable group basis. We compare the undiscounted projected future cash flows expected in connection with a depletable group to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable group exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future expenditures, and a risk-adjusted discount rate.

Our mineral interests in unproved properties are also assessed for impairment periodically on a depletable group basis when facts and circumstances indicate that the carrying value may not be recoverable.  Impairment of individual unproved properties whose acquisition costs are relatively significant are assessed on a property-by-property basis, and an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value for the property.  Impairment of unproved properties whose acquisition costs are not individually significant are assessed on a group basis.

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Any amount of loss to be recognized and the amount of a valuation allowance needed to provide for impairment of those properties is determined by amortizing those properties in the aggregate on the basis of historical experience and other relevant information, such as the relative proportion of such properties on which proved reserves have been found in the past.  The carrying value of unproved properties, including unleased mineral rights, are determined based on management's assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

Upon the sale of a complete depletable group, the book value thereof, less proceeds or salvage value, are charged to income. Upon the sale or retirement of an aggregation of interests which make up less than a complete depletable group, the proceeds are credited to accumulated depreciation, depletion and amortization, unless doing so would significantly alter the depreciation, depletion and amortization rate of the depletable group, in which case a gain or loss would be recorded.

Intangibles—Intangibles subject to amortization include contracts with covenants not to compete, customer contracts acquired from other parties and mining permits.  Intangibles other than customer contracts are amortized on a straight-line basis over their useful life.  Intangibles for customer contracts are amortized on a per unit basis over the terms of the contracts.  Amortization expense attributable to intangibles was $4.9 million, $9.1 million and $6.9 million for the years ending December 31, 2020, 2019 and 2018, respectively.  Our intangibles are included in Prepaid expenses and other assets and Other long-term assets on our consolidated balance sheets at December 31, 2020 and 2019.  Our intangibles are summarized as follows:

	December 31, 2020						December 31, 2019
			Accumulated		Intangibles,				Accumulated		Intangibles,
	Original Cost		Amortization		Net		Original Cost		Amortization		Net
	(in thousands)
Non-compete agreements	$	—	$	—	$	—	$	9,803	$	(9,440)	$	363
Customer contracts and other		10,623		(5,744)		4,879		32,371		(24,258)		8,113
Mining permits		1,500		(373)		1,127		1,500		(307)		1,193
Total	$	12,123	$	(6,117)	$	6,006	$	43,674	$	(34,005)	$	9,669

Amortization expense attributable to intangible assets is estimated as follows:

Year Ended December 31,		(in thousands)
2021	$	2,831
2022		1,600
2023		647
2024		66
2025		66
Thereafter		795

Investments—Our investments and ownership interests in equity securities without readily determinable fair values in entities in which we do not have a controlling financial interest or significant influence are accounted for using a measurement alternative other than fair value which is historical cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same entity.  Distributions received on those investments are recorded as income unless those distributions are considered a return on investment, in which case the historical cost is reduced.  We accounted for our ownership interests in Kodiak Gas Services, LLC ("Kodiak") as equity securities without readily determinable fair values.  In the first quarter of 2019, Kodiak redeemed our preferred interests and therefore Kodiak ceased to be an equity security investment. See Note 13 – Investments for further discussion of this investment.    

Our investments and ownership interests in entities in which we do not have a controlling financial interest are accounted for under the equity method of accounting if we have the ability to exercise significant influence over the entity.  Investments accounted for under the equity method are initially recorded at cost, and the difference between the basis of our investment and the underlying equity in the net assets of the joint venture at the investment date, if any, is amortized over the lives of the related assets that gave rise to the difference.  

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As of December 31, 2020 and 2019, we held an equity method investment in AllDale III through our subsidiary, Alliance Minerals.  Prior to the AllDale Acquisition, our equity method investments also included AllDale I & II, both held through Cavalier Minerals.  AllDale III and AllDale I & II are collectively referred to as the "AllDale Partnerships."  See Note 13 – Investments for further discussion of our equity method investment in AllDale III and Note 3 – Acquisitions for discussion of the AllDale Acquisition.    

We review our investments for impairment whenever events or changes in circumstances indicate a loss in the value of the investment may be other-than-temporary.

Advance Royalties—Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments.  Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset.  As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed.  Our Advance royalties are summarized as follows:

	December 31,
	2020		2019
	(in thousands)
Advance royalties, affiliates (see Note 21 – Related-Party Transactions)	$	48,389	$	41,216
Advance royalties, third-parties		12,570		12,685
Total advance royalties	$	60,959	$	53,901

Asset Retirement Obligations—Our coal mining operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan.  We record a liability for the fair value of the estimated cost of future mine asset retirement and closing procedures, escalated for inflation then discounted, on a present value basis in the period 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.  Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time.  The depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets. 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.  Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis.  See Note 19 – Asset Retirement Obligations for more information.

Pension Benefits—The funded status of our pension benefit plan is recognized separately in our consolidated balance sheets as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan's benefit obligation. Pension obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates including expected return on assets, discount rates, mortality assumptions, employee turnover rates and retirement dates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary (See Note 16 – Employee Benefit Plans).

The discount rate is determined for our pension benefit plan based on an approach specific to our plan. The year end discount rate is determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows.

The expected long-term rate of return on plan assets is determined based on broad equity and bond indices, the investment goals and objectives, the target investment allocation and on the average annual total return for each asset class.

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Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive loss until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants' average remaining future years of service.  

Workers' Compensation and Pneumoconiosis (Black Lung) Benefits—We are liable for workers' compensation benefits for traumatic injuries and benefits for black lung disease (or pneumoconiosis).  Both traumatic claims and pneumoconiosis benefits are covered through our self-insured programs.  In addition, certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis benefits to eligible employees and former employees and their dependents.  

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.  Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial 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.

Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis obligation.  Our actuarial calculations are based on numerous assumptions including claim development patterns, medical costs and mortality.  Actuarial gains or losses are amortized over the remaining service period of active miners.  See Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for more information on Workers' Compensation and Pneumoconiosis Benefits.

Coal Revenue Recognition—Revenues from coal supply contracts with customers, which primarily relate to sales of thermal coal, are recognized at the point in time when control of the coal passes to the customer.  We have determined that each ton of coal represents a separate and distinct performance obligation.  Our coal supply contracts and other revenue contracts vary in length from short-term to long-term sales contracts and do not typically have significant financing components.  Transportation revenues represent the fulfillment costs incurred for the services provided to customers through third-party carriers and for which we are directly reimbursed.  Other revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, other coal contract fees and other handling and service fees.  Performance obligations under these contracts are typically satisfied upon transfer of control of the goods or services to our customer which is determined by the contract and could be upon shipment or upon delivery.  

The estimated transaction price from each of our contracts is based on the total amount of consideration we expect to be entitled to under the contract.  Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services, government imposition claims, per ton price fluctuations based on certain coal sales price indices and anticipated payments in lieu of shipments.  We have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.  The estimated transaction price for each contract is allocated to our performance obligations based on relative standalone selling prices determined at contract inception.  Variable consideration is allocated to a specific part of the contract in many instances, such as if the variable consideration is based on production activities for coal delivered during a certain period or the outcome of a customer's ability to accept coal shipments over a certain period.

Contract assets are recorded as trade receivables and reported separately in our consolidated balance sheet from other contract assets as title passes to the customer and our right to consideration becomes unconditional.  Payments for coal shipments are typically due within two to four weeks of performance.  We typically do not have material contract assets that are stated separately from trade receivables as our performance obligations are satisfied as control of the goods or services passes to the customer thereby granting us an unconditional right to receive consideration.  Contract liabilities relate to consideration received in advance of the satisfaction of our performance obligations.  Contract liabilities are recognized as revenue at the point in time when control of the good or service passes to the customer.

Oil & Gas Revenue Recognition—Oil & gas royalty revenues are recognized at the point in time when control of the product is transferred to the purchaser by the lessee and collectability of the sales price is reasonably assured. Oil & gas are priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The royalty we receive is tied to a market index, with certain adjustments based on,

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among other factors, whether a well connects to a gathering or transmission line, quality and heat content of the product, and prevailing supply and demand conditions.

We also periodically earn revenue from lease bonuses. We recognize lease bonus revenue when we execute a lease of our mineral interests to exploration and production companies. A lease agreement represents our contract with an operator, which is generally an exploration and production company.  The contract will a) generally transfer the rights to any oil or gas discovered, b) grant us a right to a specified royalty interest from the operator, and c) require the operator to commence drilling and complete operations within a specified time period. Control of the minerals transfers to the operator when the lease agreement is executed.  At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we do not adjust the expected amount of consideration for the effects of any significant financing component.

As a non-operator, we have limited visibility into the timing of when new wells start producing.  In addition, production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices from our properties are estimated and recorded within the Trade receivables line item in our consolidated balance sheets.  Generally, the difference between our estimates and the actual amounts received for oil & gas royalty revenue are immaterial and recorded in the month that payment is received from the third-party purchaser unless new production information is received prior to the payment allowing us to update the estimate recorded.

Common Unit-Based Compensation—We have the Long-Term Incentive Plan ("LTIP") for certain employees and officers of MGP and its affiliates who perform services for us.  As part of the LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance based vesting requirements, entitle the LTIP participant to receive ARLP common units.  Annual grant levels and vesting provisions of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval of the compensation committee of our general partner ("Compensation Committee").  Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests.  If it is not probable that the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant.  Assuming the financial tests are expected to be met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants.  We expect to settle restricted unit grants by delivery of ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants.  We account for forfeitures of non-vested LTIP restricted unit grants as they occur.  As provided under the distribution equivalent rights ("DERs") provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period.  If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid.

We utilize the Supplemental Executive Retirement Plan ("SERP") to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units.  The SERP is administered by the Compensation Committee.

Our directors participate in the MGP Amended and Restated Deferred Compensation Plan for Directors ("Directors' Deferred Compensation Plan"). Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units.  Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units.

For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units.  All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

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The fair value of restricted common unit grants under the LTIP, SERP and the Directors' Deferred Compensation Plan are determined on the grant date of the award and recognized as compensation expense on a pro rata basis for LTIP and SERP awards, as appropriate, over the requisite service period. Compensation expense is fully recognized on the grant date for quarterly distributions credited to SERP accounts and Directors' Deferred Compensation Plan awards. The corresponding liability is classified as equity and included in limited partners' capital in the consolidated financial statements (See Note 17 – Compensation Plans).

Income Taxes—We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code.  Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in our consolidated financial statements.  Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in our partnership is not available to us. We have certain subsidiaries that are subject to federal and state income taxes.  These income taxes are not material to our financial position or results of operations.  

New Accounting Standards Issued and Adopted—In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirement for Fair Value Measurement ("ASU 2018-13").  ASU 2018-13 amended the fair value measurement guidance by removing and modifying certain disclosure requirements, while also adding new disclosure requirements including the requirement to disclose the range and weighted average of significant unobservable inputs used to develop certain Level 3 measurements.  These changes are to be applied prospectively for only the most recent interim or annual period presented in the year of adoption.  We adopted ASU 2018-13 on January 1, 2020.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13").  ASU 2016-13 changes the impairment model for most financial assets and certain other instruments to require the use of a new forward-looking "expected loss" model that generally will result in earlier recognition of allowances for losses.  The new standard provides for the use of a modified retrospective transition method that allows for a cumulative-effect adjustment to retained earnings upon adoption.  The new standard also requires disclosure of significantly more information related to these items.  We adopted ASU 2016-13 on January 1, 2020. Because of the credit profile of our customers, the fact that we do not have a history of credit losses on our financial instruments and the absences of any material expected losses, the adoption of ASU 2016-13 did not have any material impact on our consolidated financial statements.

3.ACQUISITIONS

AllDale I & II

On the AllDale Acquisition Date, we acquired all of the limited partner interests not owned by Cavalier Minerals in AllDale I & II and the general partner interests in AllDale I & II for $176.2 million, which was funded with cash on hand and borrowings under the Revolving Credit Facility.  As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres strategically positioned primarily in the core of the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins.  The AllDale Acquisition provides us with diversified exposure to industry leading operators and is consistent with our general business strategy to grow our Minerals segment.  

Because the underlying mineral interests held by AllDale I & II include royalty interests in both producing properties and unproved properties, we have determined that the AllDale Acquisition should be accounted for as a business combination and the underlying assets and liabilities of AllDale I & II should be recorded at their AllDale Acquisition Date fair value on our consolidated balance sheet.

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The final total fair value of the cash paid in the AllDale Acquisition and our previous investments were as follows:

	As of January 3, 2019
	(in thousands)
Cash	$	176,205
Previously held investments		307,322
Total	$	483,527

Prior to the AllDale Acquisition Date, we accounted for our investments in AllDale I & II, held through Cavalier Minerals, as equity method investments. The combined fair value of our equity method investments on the AllDale Acquisition Date was $307.3 million.  We re-measured our equity method investments, which had an aggregate carrying value of $130.3 million immediately prior to the AllDale Acquisition.  The re-measurement resulted in a gain of $177.0 million which is recorded in the Acquisition gain line item in our consolidated statements of income.

The following table summarizes the final fair value allocation of assets acquired and liabilities assumed as of the AllDale Acquisition Date:

	(in thousands)
Cash and cash equivalents	$	900
Mineral interests in proved properties		184,032
Mineral interests in unproved properties		291,190
Receivables		9,326
Accounts payable		(1,921)
Net assets acquired	$	483,527

Our previous equity method investments in AllDale I & II were held through Cavalier Minerals.  Bluegrass Minerals Management, LLC ("Bluegrass Minerals") continues to hold a 4% membership interest (the "Bluegrass Interest") as well as a profits interest in Cavalier Minerals as it did before the AllDale Acquisition.  This Bluegrass Interest represents an indirect noncontrolling interest in AllDale I & II.  The AllDale Acquisition Date fair value of the Bluegrass Interest was $12.3 million.  

The fair value of our previous equity method investments, the mineral interests and the Bluegrass Interest were determined using an income approach primarily comprised of discounted cash flow models.  The assumptions used in the discounted cash flow models include estimated production, projected cash flows, forward oil & gas prices and a risk adjusted discount rate.  Certain assumptions used are not observable in active markets, therefore the fair value measurements represent Level 3 fair value measurements.  AllDale I & II's carrying value of the receivables and accounts payable represent their fair value given their short-term nature.  

The amounts of revenue and earnings, exclusive of the acquisition gain, of AllDale I & II included in our consolidated statements of income from the AllDale Acquisition Date through December 31, 2019 are as follows:

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	48,411
Net income		18,543

The following represents our actual and pro forma consolidated revenues and net income for the year ended December 31, 2018. Pro forma revenues and net income assumes AllDale I & II had been included in our consolidated results since January 1, 2018.  These amounts have been calculated after applying our accounting policies.  Pro forma information is not necessary for the year ended December 31, 2019 as the AllDale Acquisition occurred at the beginning of 2019.  Additionally, our pro forma results have been adjusted to remove the effect of our past equity method investments in AllDale I & II.

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	Year Ended
	December 31,
	2018
	(in thousands)
Total revenues
As reported	$	2,002,857
Pro forma		2,042,545
Net income
As reported	$	367,470
Pro forma		358,741

Wing

On August 2, 2019 (the "Wing Acquisition Date"), our subsidiary, AR Midland acquired from Wing approximately 9,000 net royalty acres in the Midland Basin, with exposure to more than 400,000 gross acres, for a cash purchase price of $144.9 million.  The purchase price was funded with cash on hand and borrowings under our Revolving Credit Facility discussed in Note 8 – Long-Term Debt.  The Wing Acquisition enhances our ownership position in the Permian Basin, expands our exposure to industry leading operators and furthers our business strategy to grow our Minerals segment.  Concurrent with the Wing Acquisition, JC Resources LP, an entity owned by Mr. Craft, acquired from Wing, in a separate transaction, mineral interests that we elected not to acquire.

Because the mineral interests acquired in the Wing Acquisition include royalty interests in both producing properties and unproved properties, we have determined that the acquisition should be accounted for as a business combination and the underlying assets should be recorded at fair value as of the Wing Acquisition Date on our consolidated balance sheet. During the year ended December 31, 2020, we recorded adjustments to our mineral interests in proved and unproved properties after receiving additional information regarding proved and unproved reserve quantities, production and projections as of the Wing Acquisition Date.  In addition, we increased our receivables by $0.3 million as a result of information received from operators concerning royalty payments owed to us from production that occurred prior to the Wing Acquisition Date.  

The following table summarizes our final fair value allocation of assets acquired as of the Wing Acquisition Date incorporating measurement period adjustments made to the allocation:

	As Previously
	Reported		Adjustments		Final
			(in thousands)
Mineral interests in proved properties	$	58,084		16,987	$	75,071
Mineral interests in unproved properties		84,976		(17,275)		67,701
Receivables		1,867		288		2,155
Net assets acquired	$	144,927			$	144,927

The fair value of the mineral interests was determined using a weighting of both income and market approaches.  Our income approach primarily comprised 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 weighted average cost of capital.  Our market approach consisted of the observation of recent acquisitions in the Permian Basin to determine a market price for similar mineral interests.  Certain assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  The carrying value of the receivables represents the fair value given the short-term nature of the receivables.

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The amounts of revenue and earnings from the mineral interests acquired in the Wing Acquisition included in our consolidated statements of income from the Wing Acquisition Date through December 31, 2019 are as follows:

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	4,625
Net income		1,291

The following represents our actual and pro forma consolidated revenues and net income for the years ended December 31, 2019 and 2018. Pro forma revenues and net income assumes the mineral interests acquired in the Wing Acquisition had been included in our consolidated results since January 1, 2018. These pro forma amounts have been calculated after applying our accounting policies.

	Year Ended
	December 31,
	2019		2018
	(in thousands)
Total revenues
As reported	$	1,961,720	$	2,002,857
Pro forma		1,966,291		2,008,559
Net income
As reported	$	406,926	$	367,470
Pro forma		411,217		372,810

4. LONG-LIVED ASSET IMPAIRMENTS

During the year ended December 31, 2020, we recorded $25.0 million of non-cash asset impairment charges in our Illinois Basin segment due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment at our idled operations and greenfield coal reserves as a result of weakened coal market conditions.

During the year ended December 31, 2019, we recorded an asset impairment charge of $15.2 million in our Illinois Basin segment due to the cessation of coal production at our Dotiki mine, effective August 16, 2019, in an effort to focus on maximizing production at our lower-cost mines in the segment. We adjusted the carrying value of Dotiki's assets from $35.9 million to its fair value of $25.8 million and accrued $5.1 million with respect to scheduled payments to WKY CoalPlay for leased coal reserves from which we may not receive future economic benefit.  See Note 12 – Variable Interest Entities for more information about WKY CoalPlay.

During the year ended December 31, 2018, due to the reduction of Dotiki’s economic mine life, we recorded a $34.3 million impairment charge when we adjusted the carrying value of Dotiki's assets from $85.3 million to its fair value of $51.0 million.  We also had a decrease in the fair value of an option entitling us to lease certain coal reserves, which resulted in an impairment charge of $6.2 million.  Both of these impairment charges were incurred in our Illinois Basin segment.

The fair values of the impaired assets were determined using a combination of market and income approaches, both of which represent Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions of marketability of certain assets as well as discounted cash flows over the remaining life of the assets.

With the uncertainty related to energy demand as a result of weak electricity demand and an oversupply and lack of storage for oil and natural gas during the quarter ended March 31, 2020 (the "First Quarter"), both due in part to the COVID-19 pandemic and other market and production factors impacting both our coal mining operations and our mineral interests activities, we performed recoverability tests during the First Quarter using undiscounted cash flows based on our estimate of sales volume and prices, operating margins and capital expenditures from information available to us and

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determined we would be able to recover the costs of our assets, excluding the impaired assets discussed above.  Amid cost reduction efforts, increased customer commitments for coal, a modest recovery in commodity futures prices and increased clarity into production levels by operators of our oil & gas mineral interests during the year, we determined impairment of our long-lived assets subsequent to the First Quarter was not necessary.  The cash flow estimates used in our impairment assessments, by their very nature, are dependent on conditions that could materially change in future periods based on new information.  If in future periods changes to these estimates were to materially reduce our expected cash flows, additional impairments could be necessary.

See Note 2 – Summary of Significant Accounting Policies – Long-Lived Asset Impairment for more information on our accounting policy for asset impairments.

5.GOODWILL IMPAIRMENT

At December 31, 2019, our consolidated balance sheet included $136.4 million of goodwill, of which $132.0 million was associated with the reporting unit representing our Hamilton County Coal, LLC ("Hamilton") mine, which is included in our Illinois Basin segment. 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, 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 First 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 an income approach utilizing a discounted cash flow model.  The assumptions used in the discounted cash flow model included estimated production, forward coal prices, operating expenses, capital expenditures and a weighted average cost of capital.  Our forecasts of future cash flows 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. Key assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  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 and as part of our annual impairment evaluation on November 30, 2020, we also performed tests on ARLP's remaining goodwill balances not associated with Hamilton and concluded no impairment was necessary for our other reporting units.

6. INVENTORIES

Inventories consist of the following:

	December 31,
	2020		2019
	(in thousands)
Coal	$	19,756	$	63,645
Supplies (net of reserve for obsolescence of $5,547 and $5,555, respectively)		36,651		37,660
Total inventories, net	$	56,407	$	101,305

For the year ended December 31, 2020, we recorded lower of cost or net realizable value adjustments of $3.2 million to our coal inventories as a result of lower coal sale prices and higher cost per ton due to the impact of lower production on our fixed costs per ton in addition to the impact of challenging market conditions on our production levels.  The lower of cost or net realizable value adjustments reflect the impacts of the challenging market conditions and were primarily attributable to the Mettiki and Hamilton mining complexes.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for inventories.

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7.PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following:

	December 31,
	2020		2019
	(in thousands)
Mining equipment and processing facilities	$	1,896,324	$	1,937,642
Land and coal mineral rights		454,310		453,237
Oil & gas mineral interests (1)		616,904		618,282
Buildings, office equipment and improvements		279,938		304,111
Construction and mine development in progress		25,799		86,876
Mine development costs		280,815		283,860
Property, plant and equipment, at cost		3,554,090		3,684,008
Less accumulated depreciation, depletion and amortization		(1,753,845)		(1,675,022)
Total property, plant and equipment, net	$	1,800,245	$	2,008,986

(1) Oil & gas mineral interests acquired in the AllDale and Wing Acquisitions. See Note 3 – Acquisitions for more information.

At December 31, 2020 and 2019, land and coal mineral rights above include $37.5 million and $40.1 million, respectively, of carrying value associated with coal reserves attributable to properties where we or a third party to which we lease reserves are not currently engaged in mining operations or leasing to third parties, and therefore, the coal reserves are not currently being depleted.  We believe that the carrying value of these coal reserves will be recovered.  

At December 31, 2020 and 2019, our oil & gas mineral interests noted in the table above includes the carrying value of our unproved oil & gas mineral interests totaling $340.5 million and $376.2 million, respectively.  As discussed in Note 2 – Summary of Significant Accounting Policies, we generally do not record depletion expense for our unproved oil & gas mineral interests; however, we do review for impairment as needed throughout the year.

During 2020 and 2019, we incurred $13.1 million and $13.2 million, respectively, in mine development costs, primarily related to the development of our Excel Mine No. 5 at our MC Mining complex.  All past capitalized mine development costs are associated with other mines that shifted to the production phase in past years and we are amortizing these costs accordingly.  We believe that the carrying value of the past development costs will be recovered.  For information regarding long-lived asset impairments please see Note 4 – Long-Lived Asset Impairments.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for property, plant and equipment.

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8.LONG-TERM DEBT

Long-term debt consists of the following:

					Unamortized Discount and
	Principal				Debt Issuance Costs
	December 31,				December 31,
	2020		2019		2020		2019
	(in thousands)
Revolving credit facility	$	87,500	$	255,000	$	(7,196)	$	(3,050)
Senior notes		400,000		400,000		(3,964)		(4,879)
Securitization facility		55,900		73,800		—		—
May 2019 equipment financing		4,956		8,199		—		—
November 2019 equipment financing		42,367		52,281		—		—
June 2020 equipment financing		13,057		—		—		—
		603,780		789,280		(11,160)		(7,929)
Less current maturities		(73,199)		(13,157)		—		—
Total long-term debt	$	530,581	$	776,123	$	(11,160)	$	(7,929)

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 $6.3 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.  

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.

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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 Resource Finance Corporation (as co-issuer), a wholly owned subsidiary of the Intermediate Partnership ("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, LLC ("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 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.  Upon 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.

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Aggregate maturities of long-term debt are payable as follows:

Year Ended
December 31,	(in thousands)
2021	$	73,199
2022		16,071
2023		24,970
2024		89,540
2025		400,000
	$	603,780

9.LEASES

The components of lease expense were as follows:

	December 31,
	2020		2019
	(in thousands)
Finance lease cost:			$
Amortization of right-of-use assets	$	704		14,608
Interest on lease liabilities		377		2,085
Operating lease cost		3,873		9,169
Short-term lease cost		84		464
Variable lease cost		1,375		1,360
Total lease cost	$	6,413	$	27,686

Rental expense was $5.2 million, $11.0 million and $14.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Supplemental cash flow information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3,870		9,124
Operating cash flows for finance leases	$	377		891
Financing cash flows for finance leases	$	8,368		46,725
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	278		25,593

Supplemental balance sheet information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Finance leases:
Property and equipment finance lease assets, gross	$	5,485	$	30,610
Accumulated depreciation		(3,867)		(20,564)
Property and equipment finance lease assets, net	$	1,618	$	10,046

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	December 31,
	2020		2019
Weighted average remaining lease term
Operating leases		13.4 years		13.1 years
Finance leases		3.9 years		1.6 years
Weighted average discount rate
Operating leases		6.0 %		6.0 %
Finance leases		8.0 %		6.0 %

Maturities of lease liabilities as of December 31, 2020 were as follows:

	Operating leases		Finance leases
	(in thousands)
2021	$	2,346	$	912
2022		2,245		912
2023		2,061		139
2024		1,841		139
2025		1,527		139
Thereafter		11,838		280
Total lease payments		21,858		2,521
Less imputed interest		(6,926)		(297)
Total	$	14,932	$	2,224

10.FAIR VALUE MEASUREMENTS

The following table summarizes our fair value measurements within the hierarchy not included elsewhere in these notes:

	December 31, 2020						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)
Long-term debt	$	—	$	518,317	$	—	$	—	$	736,206	$	—
Total	$	—	$	518,317	$	—	$	—	$	736,206	$	—

See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding fair value hierarchy levels.

The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued and other liabilities, due from affiliates and due to affiliates approximate fair value due to the short maturity of those instruments.

The estimated fair value of our long-term debt, including current maturities, is based on interest rates that we believe are currently available to us in active markets for issuance of debt with similar terms and remaining maturities (See Note 8 – Long-Term Debt).  The fair value of debt, which is based upon these interest rates, is classified as a Level 2 measurement under the fair value hierarchy.

11.PARTNERS' CAPITAL

Distributions

Our available cash that is not used for unit repurchases may, at the discretion of our general partner, be distributed within 45 days after the end of each quarter to unitholders of record.  Available cash is generally defined in the partnership agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by MGP in its reasonable discretion for future cash requirements.  These reserves are retained to provide for the conduct of our business,

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the payment of debt principal and interest and to provide funds for future distributions.  The following table summarizes the quarterly per unit distribution paid during each quarter of 2018 through 2020:

	Year Ended December 31,
	2020		2019		2018
First Quarter	$	0.400	$	0.530	$	0.510
Second Quarter	$	—	$	0.535	$	0.515
Third Quarter	$	—	$	0.540	$	0.520
Fourth Quarter	$	—	$	0.540	$	0.525

In response to the disruptions to the economy and the uncertainty surrounding the COVID-19 pandemic, the Board of Directors of ARLP's general partner began suspending cash distributions to unitholders with the First Quarter and has continued through the quarter ended December 31, 2020.

Simplification Transactions

On May 31, 2018, as part of the Simplification Transactions discussed in Note 1 – Organization and Presentation, ARLP issued 1,322,388 ARLP common units to the Owners of SGP in exchange for causing SGP to contribute to ARLP all of SGP's limited partner interests 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.

The Simplification Transactions are accounted for prospectively as an exchange of equity interests between entities under common control. Since ARLP and AHGP were under common control both before and after the Simplification Transactions, no fair value adjustment was made to the assets or liabilities of AHGP and its subsidiaries and no gain or loss was recognized on our consolidated financial statements.

Unit Repurchase Program

In May 2018, the Board of Directors approved the establishment of a unit repurchase program authorizing us to repurchase and retire 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.  No unit repurchases were made during the year ended December 31, 2020.  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.  

Affiliated Entity Contributions

An affiliated entity controlled by Mr. Craft made a capital contribution of $2.1 million during the year ended December 31, 2018 for the purpose of funding certain general and administrative expenses.  On June 29, 2018, the members of this affiliated entity contributed 467,018 ARLP common units for similar purposes.

Other

The noncontrolling interest in our consolidated balance sheets represents Bluegrass Minerals' ownership interest in Cavalier Minerals.   Our accumulated other comprehensive loss consists of unrecognized actuarial gains and losses as well as unrecognized prior service costs related to our pension and pneumoconiosis benefits.   See Note 12 – Variable Interest Entities, Note 16 –Employee Benefit Plans and Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for further information.

12.VARIABLE INTEREST ENTITIES

Cavalier Minerals

On November 10, 2014, our subsidiary, Alliance Minerals, and Bluegrass Minerals entered into a limited liability company agreement (the "Cavalier Agreement") to create Cavalier Minerals, which was formed to indirectly acquire oil & gas mineral interests through its ownership in AllDale I & II.  Alliance Minerals owns a 96% member interest in Cavalier Minerals, and Bluegrass Minerals owns a 4% member interest in Cavalier Minerals and a profits interest which entitles it to receive distributions equal to 25% of all distributions (including in liquidation) after all members have recovered their

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investment.  Distributions with respect to Bluegrass Minerals' profits interest will be offset by all distributions received by Bluegrass Minerals from the former general partners of AllDale I & II.  To date, there has been no profits interest distribution.  Bluegrass Minerals was Cavalier Minerals' managing member prior to the AllDale Acquisition (see Note 3 – Acquisitions).  In conjunction with the AllDale Acquisition, we became the managing member in Cavalier Minerals.  Total contributions to and cumulative distributions from Cavalier Minerals are as follows:

	Alliance		Bluegrass
	Minerals		Minerals
	(in thousands)
Contributions	$	143,112	$	5,963
Distributions		89,380		3,723

We have concluded that Cavalier Minerals is a VIE which we consolidate as the primary beneficiary because we are the managing member and a substantial equity owner in Cavalier Minerals.  Bluegrass Minerals' equity ownership of Cavalier Minerals is accounted for as noncontrolling ownership interest in our consolidated balance sheets.  In addition, earnings attributable to Bluegrass Minerals are recognized as noncontrolling interest in our consolidated statements of income.

AllDale III

In February 2017, Alliance Minerals committed to directly invest $30.0 million in AllDale III which was created for similar investment purposes as AllDale I & II.  Alliance Minerals completed funding of this commitment in 2018. Alliance Minerals' limited partner interest in AllDale III at December 31, 2020 was 13.9%.

The AllDale III Partnership Agreement includes a 25% profits interest for the general partner, subject to a return hurdle equal to the greater of 125% of cumulative capital contributions and a 10% internal rate of return, and following an 80/20 "catch-up" provision for the general partner.  

Since AllDale III is structured as a limited partnership with the limited partners 1) not having the ability to remove the general partner and 2) not participating significantly in the operational decisions, we concluded that AllDale III is a VIE.  We are not the primary beneficiary of AllDale III as we do not have the power to direct the activities that most significantly impact AllDale III's economic performance.  We account for our ownership interest in the income or loss of AllDale III as an equity method investment.  We record equity income or loss based on AllDale III's distribution structure.  See Note 13 – Investments for more information.

WKY CoalPlay

On November 17, 2014, SGP Land, LLC ("SGP Land"), a wholly owned subsidiary of SGP, and two limited liability companies ("Craft Companies") owned by irrevocable trusts established by Mr. Craft and his children entered into a limited liability company agreement to form WKY CoalPlay, LLC ("WKY CoalPlay").  WKY CoalPlay was formed, in part, to purchase and lease coal reserves.  WKY CoalPlay is managed by one of the Craft Companies.  In December 2014 and February 2015, we entered into various coal reserve leases with WKY CoalPlay.  See Note 21 – Related-Party Transactions for further information on our lease terms with WKY CoalPlay.

We concluded that WKY CoalPlay was a VIE because of our ability to exercise options to acquire reserves under lease with WKY CoalPlay (Note 21 – Related-Party Transactions), which was not within the control of the equity holders and, if it had occurred, could potentially limit the expected residual return to the owners of WKY CoalPlay.  We hold no economic or governance rights related to WKY CoalPlay and our options did not give us any rights to impact WKY CoalPlay's economic performance.  We therefore concluded that we were not the primary beneficiary of WKY CoalPlay.  These options expired in December 2020 and February 2021.  Upon the expiration of these options, WKY CoalPlay ceased to be a VIE.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for variable interest entities.

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13.INVESTMENTS

AllDale III

As discussed in Note 12 – Variable Interest Entities, we account for our ownership interest in the income or loss of AllDale III as an equity method investment.  We record equity income or loss based on AllDale III's distribution structure.  The changes in our equity method investment in AllDale III for each of the periods presented were as follows:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Beginning balance	$	28,529	$	28,974	$	14,182
Contributions		—		—		15,600
Equity method investment income		907		2,203		547
Distributions received		(1,895)		(2,648)		(1,355)
Other		(273)		—		—
Ending balance	$	27,268	$	28,529	$	28,974

As discussed in Note 4 – Long-Lived Asset Impairments, there was uncertainty related to energy demand in the First Quarter as a result of weak electricity demand and an oversupply and lack of storage for oil and natural gas, both due in part to the COVID-19 pandemic and other market and production factors, which could have impacted our investment in AllDale III.  As a result, as part of our First Quarter impairment assessment, we compared the fair value of our investment to its carrying value and concluded that the fair value exceeded the carrying value and no impairment in our investment was necessary.  In our subsequent impairment assessments, amid a modest recovery in commodity futures prices and increased clarity into production levels by operators during the year, we again compared the fair value of our investment to its carrying value and concluded no impairment was necessary.  To calculate the fair value of the investment we used an income approach utilizing a discounted cash flow model based on our estimate of both production, prices and expenses from information available to us.  Key assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  The cash flow estimates used in our assessments, by their very nature, are dependent on conditions that could materially change in future periods based on new information.  If in future periods changes to these estimates were to materially reduce our expected cash flows, an impairment of our investment could be necessary.

Kodiak

On July 19, 2017, Alliance Minerals purchased $100 million of Series A-1 Preferred Interests from Kodiak, a privately-held company providing large-scale, high-utilization gas compression assets to customers operating primarily in the Permian Basin.  This structured investment provided us with a quarterly cash or payment-in-kind return.  On February 8, 2019, Kodiak redeemed our preferred interest for $135.0 million in cash resulting in an $11.5 million gain due to an early redemption premium. The gain is included in the Equity securities income line item.  We no longer hold any ownership interests in Kodiak.  Prior to the redemption, we accounted for our ownership interests in Kodiak as equity securities without readily determinable fair values.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for investments.

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14.REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table illustrates the disaggregation of our revenues by type, including a reconciliation to our segment presentation as presented in Note 24 – Segment Information.

	Illinois						Other and
	Basin		Appalachia		Minerals		Corporate		Elimination		Consolidated
	(in thousands)
Year Ended December 31, 2020
Coal sales	$	755,208	$	477,064	$	—	$	—	$	—	$	1,232,272
Oil & gas royalties		—		—		42,912		—		—		42,912
Transportation revenues		12,817		8,312		—		—		—		21,129
Other revenues		2,026		14,954		229		25,124		(10,517)		31,816
Total revenues	$	770,051	$	500,330	$	43,141	$	25,124	$	(10,517)	$	1,328,129
Year Ended December 31, 2019
Coal sales	$	1,128,588	$	628,406	$	—	$	22,138	$	(16,690)	$	1,762,442
Oil & gas royalties		—		—		51,735		—		—		51,735
Transportation revenues		94,686		4,817		—		—		—		99,503
Other revenues		13,034		11,166		1,301		34,712		(12,173)		48,040
Total revenues	$	1,236,308	$	644,389	$	53,036	$	56,850	$	(28,863)	$	1,961,720
Year Ended December 31, 2018
Coal sales	$	1,197,143	$	635,530	$	—	$	43,393	$	(31,258)	$	1,844,808
Transportation revenues		106,947		5,435		—		3		—		112,385
Other revenues		16,999		3,000		—		38,096		(12,431)		45,664
Total revenues	$	1,321,089	$	643,965	$	—	$	81,492	$	(43,689)	$	2,002,857

The following table illustrates the amount of our transaction price for all current coal supply contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2020 and disaggregated by segment and contract duration.

							2024 and
	2021		2022		2023		Thereafter		Total
	(in thousands)
Illinois Basin coal revenues	$	653,208	$	253,654	$	187,570	$	140,750	$	1,235,182
Appalachia coal revenues		318,984		95,471		—		—		414,455
Total coal revenues (1)	$	972,192	$	349,125	$	187,570	$	140,750	$	1,649,637

(1) Coal revenues generally consists of consolidated revenues excluding our Minerals segment.

15.EARNINGS PER LIMITED PARTNER UNIT

We utilize the two-class method in calculating basic and diluted earnings per limited partner unit ("EPU").  Subsequent to the Simplification Transactions, net income attributable to ARLP is only allocated to limited partners and participating securities under deferred compensation plans.  Net losses attributable to ARLP are allocated to limited partners but not to participating securities.  Prior to the Simplification Transactions, net income attributable to ARLP was allocated to our general partner, limited partners and participating securities under deferred compensation plans in accordance with their respective partnership ownership percentages.  As a result of the Simplification Transactions, MGP no longer holds economic interests in the Intermediate Partnership or Alliance Coal.  We currently do not make distributions or allocate income and losses to MGP in our calculation of EPU.  Please see Note 1 – Organization and Presentation for more information on the Simplification Transactions.

Our participating securities under deferred compensation plans include rights to nonforfeitable distributions or distribution equivalents. Our participating securities are outstanding awards under our LTIP and phantom units in notional accounts under our SERP and the Directors' Deferred Compensation Plan.  

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The following is a reconciliation of net income (loss) attributable to ARLP used for calculating basic and diluted earnings per unit and the weighted-average units used in computing EPU.

	Year Ended December 31,
	2020		2019		2018
	(in thousands, except per unit data)
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Adjustment:
General partner's equity ownership (1)		—		—		(1,560)
Limited partners' interest in net income (loss) attributable to ARLP		(129,220)		399,414		365,044
Less:
Distributions to participating securities		—		(4,254)		(5,114)
Undistributed earnings attributable to participating securities		—		(2,237)		(1,641)
Net income (loss) attributable to ARLP available to limited partners	$	(129,220)	$	392,923	$	358,289
Weighted-average limited partner units outstanding – basic and diluted		127,165		128,117		130,758
Earnings per limited partner unit - basic and diluted (2)	$	(1.02)	$	3.07	$	2.74

(1) Amounts presented for periods subsequent to the first quarter of 2018 reflect the impact of the Simplification Transactions, which ended net income allocations and quarterly cash distributions to MGP after May 31, 2018.  Prior to the Simplification Transactions, MGP maintained a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal and thus received quarterly distributions and income and loss allocations during this time period.

(2) Diluted EPU gives effect to all potentially dilutive common units outstanding during the period using the treasury stock method.  Diluted EPU excludes all potentially dilutive units calculated under the treasury stock method if their effect is anti-dilutive.  For the years ended December 31, 2020, 2019 and 2018, the combined total of LTIP, SERP and Directors' Deferred Compensation Plan units of 773,664, 1,284,013 and 1,658,908, respectively, were considered anti-dilutive under the treasury stock method.

16.EMPLOYEE BENEFIT PLANS

Defined Contribution Plans—Eligible employees currently participate in a defined contribution profit sharing and savings plan ("PSSP") that we sponsor.  The PSSP covers all regular full-time employees.  PSSP participants may elect to make voluntary contributions to this plan up to a specified amount of their compensation. We make matching contributions based on a percent of an employee's eligible compensation and also make an additional non-matching contribution.  Our contribution expense for the PSSP was approximately $16.1 million, $21.1 million and $19.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Defined Benefit Plan—Eligible employees and former employees of certain of our mining operations participate in a defined benefit plan (the "Pension Plan") that we sponsor.  The Pension Plan is closed to new applicants.  Participants in the Pension Plan are no longer receiving benefit accruals for service.  Participants can participate in enhanced benefits provisions under the PSSP.  The benefit formula for the Pension Plan is a fixed-dollar unit based on years of service.

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The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2020 and 2019 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements:

	December 31,
	2020		2019
	(dollars in thousands)
Change in benefit obligations:
Benefit obligations at beginning of year	$	136,425	$	118,958
Interest cost		4,185		4,864
Actuarial loss		12,396		17,084
Benefits paid		(5,072)		(4,481)
Benefit obligations at end of year		147,934		136,425
Change in plan assets:
Fair value of plan assets at beginning of year		91,567		75,823
Employer contribution		1,739		5,559
Actual return on plan assets		12,735		14,666
Benefits paid		(5,072)		(4,481)
Fair value of plan assets at end of year		100,969		91,567
Funded status at the end of year	$	(46,965)	$	(44,858)
Amounts recognized in balance sheet:
Non-current liability	$	(46,965)	$	(44,858)
Amounts recognized in accumulated other comprehensive income consists of:
Prior service cost	$	(754)	$	(940)
Net actuarial loss		(46,519)		(45,125)
	$	(47,273)	$	(46,065)
Weighted-average assumption to determine benefit obligations as of December 31,
Discount rate		2.37%		3.15%
Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,
Discount rate		3.15%		4.17%
Expected return on plan assets		6.50%		6.50%

The actuarial loss components of the change in benefit obligations in 2020 and 2019 were primarily attributable to decreases in the discount rate compared to the prior year-end, offset in part by updated mortality tables.  

The expected long-term rate of return used to determine our pension liability is based on a 1.5% active management premium in addition to an asset allocation assumption of:

	Asset allocation
As of December 31, 2020	assumption
Equity securities	62%
Fixed income securities	33%
Real estate	5%
	100%

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The actual return on plan assets was 14.2% and 19.2% for the years ended December 31, 2020 and 2019, respectively.

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Components of net periodic benefit cost:
Interest cost	$	4,185	$	4,864	$	4,462
Expected return on plan assets		(5,861)		(4,932)		(5,784)
Amortization of prior service cost		186		186		186
Amortization of net loss		4,128		3,922		3,608
Net periodic benefit cost (1)	$	2,638	$	4,040	$	2,472

(1) Nonservice components of net periodic benefit cost are included in the Other income (expense) line item within our consolidated statements of income.

	Year Ended December 31,
	2020		2019
	(in thousands)
Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive loss:
Net actuarial loss	$	(5,522)	$	(7,350)
Reversal of amortization item:
Prior service cost		186		186
Net actuarial loss		4,128		3,922
Total recognized in accumulated other comprehensive loss		(1,208)		(3,242)
Net periodic benefit cost		(2,638)		(4,040)
Total recognized in net periodic benefit cost and accumulated other comprehensive loss	$	(3,846)	$	(7,282)

Estimated future benefit payments as of December 31, 2020 are as follows:

Year Ended
December 31,	(in thousands)
2021	$	5,629
2022		5,954
2023		6,269
2024		6,488
2025		6,620
2026-2030		34,674
	$	65,634

We expect to contribute $6.5 million to the Pension Plan in 2021.  

The Compensation Committee has appointed an investment manager with full investment authority with respect to Pension Plan investments subject to investment guidelines and compliance with ERISA or other applicable laws.  The investment manager employs a series of asset allocation strategy phases to glide the portfolio risk commensurate with both plan characteristics and market conditions.  The objective of the allocation policy is to reach and maintain fully funded status.  The total portfolio allocation will be adjusted as the funded ratio of the Pension Plan changes and market conditions warrant.  The target allocation includes investments in equity and fixed income commingled investment funds.  Total

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account performance is reviewed at least annually, using a dynamic benchmark approach to track investment performance.  General asset allocation guidelines at December 31, 2020 are as follows:

	Percentage of Total Portfolio
	Minimum	Target	Maximum
Equity securities	45%	62%	80%
Fixed income securities	10%	33%	55%
Real estate	0%	5%	10%

Equity securities include domestic equity securities, developed international securities, emerging markets equity securities and real estate investment trust.  Fixed income securities include domestic and international investment grade fixed income securities, high yield securities and emerging markets fixed income securities.  Fixed income futures may also be utilized within the fixed income securities asset allocation.  

The following information discloses the fair values of our Pension Plan assets by asset category:

	December 31,
	2020		2019
	(in thousands)
Cash and cash equivalents (a)	$	3,888	$	2,958
Commingled investment funds measured at net asset value (b):
Equities - Global		17,549		10,028
Equities - United States		31,835		26,812
Equities - United States futures		(2,616)		—
Equities - International developed markets		8,920		10,528
Equities - International developed markets futures		(4,921)		—
Equities - International emerging markets		6,600		8,410
Equities - International emerging markets futures		(975)		—
Fixed income - Investment grade		25,703		26,186
Fixed income - High yield		10,056		—
Fixed income - Emerging markets		2,664		—
Fixed income - Futures		(1,265)		—
Real estate		3,531		4,355
Other		—		2,290
Total	$	100,969	$	91,567

(a) Cash and cash equivalents represents a Level 1 fair value measurement.  See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding the definitions of fair value hierarchy levels.

(b) Investments measured at fair value using the net asset value per share (or its equivalent) have not been classified within the fair value hierarchy.  The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the fund's assets at fair value less liabilities, divided by the number of units outstanding.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for pension benefits.

17.COMMON UNIT-BASED COMPENSATION PLANS

Long-Term Incentive Plan

We maintain the LTIP for certain employees and officers of MGP and its affiliates who perform services for us.  As part of our LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance-based vesting requirements, entitle the LTIP participant to receive ARLP common units.  Annual grant levels and vesting provisions of restricted units for designated participants are

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recommended by Mr. Craft, subject to review and approval of the Compensation Committee.  Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests.  If it is not probable the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant.  Assuming the financial tests are met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants.  We expect to settle restricted unit grants by delivery of ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants.  We account for forfeitures of non-vested LTIP restricted unit grants as they occur.  As provided under the DERs provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid.  

A summary of non-vested LTIP grants of restricted units is as follows:

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Non-vested grants at January 1, 2018	1,694,026	$	19.62	$	33,372
Granted	511,305		20.40
Vested (1)	(331,502)		34.61
Forfeited	(45,749)		17.40
Non-vested grants at December 31, 2018	1,828,080		17.18		31,699
Granted	682,155		18.63
Vested (1)	(885,381)		12.38
Forfeited	(21,476)		20.84
Non-vested grants at December 31, 2019	1,603,378		20.39		17,349
Granted (2)	1,430,489		5.02
Vested (3)	(919,524)		21.70
Grants canceled (4)	(675,302)		18.62
Forfeited	(8,552)		20.16
Non-vested grants at December 31, 2020	1,430,489		5.02		6,409

(1) During the years ended December 31, 2019 and 2018, we issued 596,650 and 191,858, respectively, unrestricted common units to LTIP participants.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.

(2) In December 2020, we modified the vesting requirements for certain restricted units that we granted in February 2020 which were determined to be improbable of vesting under the original vesting requirements (the "2020 Grants"). The new vesting requirements make it probable the modified restricted units will vest.  Also in December 2020, an additional 578,114 restricted units under these modified vesting requirements were granted.  The grant date fair value reflects the modification date fair value for those awards that were modified.

(3) In February 2020, we issued 279,622 unrestricted common units to LTIP participants as a result of satisfying the vesting requirements for 424,486 restricted units that were granted in 2017.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.  In December 2020, we accelerated the vesting requirements for 495,038 restricted units that were granted in 2018 (the "2018 Grants") and settled these restricted units in cash.

(4) In December 2020, 675,302 restricted units that were granted in 2019 (the "2019 Grants") were canceled since it was determined that the vesting requirements for these restricted units were not probable of being satisfied.

For the years ended December 31, 2020, 2019 and 2018, our LTIP expense for grants of restricted units was $8.1 million, $10.4 million and $10.8 million, respectively.  LTIP expense for grants of restricted units for the year ended December 31, 2020 includes the impact of the reversal of the 2019 Grants, the modification of the 2020 Grants and incremental compensation cost associated with the cash settlement of the 2018 Grants.  The cash settlement of the 2018

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Grants was the first time we have settled restricted units in cash and we currently do not expect to do so again in the future.  The cash settlement of the 2018 Grants resulted in $5.4 million in incremental compensation cost.  The 2019 Grants were determined to be not probable of vesting therefore $4.8 million of cumulative previously recognized expense was reversed in 2020, offset in part by related DERs for the 2019 Grants previously recorded to equity and then expensed in 2020.  The 2020 Grants were determined to be improbable of vesting therefore the Compensation Committee modified the awards to change the vesting requirement, which made the grants probable of vesting, and granted additional restricted units under these modified vesting requirements as previously discussed.  As a result, the grant date fair value of the modified awards was changed to reflect the modification date fair value of the awards resulting in a net reduction in LTIP expense of $1.0 million for the year ended, December 31, 2020.

The total obligation associated with LTIP grants of restricted units as of December 31, 2020 and 2019 was $1.3 million and $20.2 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets.  As of December 31, 2020, there was $5.8 million in total unrecognized compensation expense related to the non-vested LTIP restricted unit grants that are expected to vest.  That expense is expected to be recognized over a weighted-average period of 2.0 years.

Approximately 1.7 million units remain available under the LTIP for issuance in the future, assuming all grants currently issued and outstanding are settled with common units, without reduction for tax withholding, no future forfeitures occur and DERs are paid in cash versus additional phantom units.

Supplemental Executive Retirement Plan and Directors' Deferred Compensation Plan

We utilize the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units.  The SERP is administered by the Compensation Committee.

Our directors participate in the Directors' Deferred Compensation Plan. Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units.  Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units.

For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units.  All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

A summary of SERP and Directors' Deferred Compensation Plan activity is as follows:

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Phantom units outstanding as of January 1, 2018	561,784	$	28.64	$	11,067
Granted	84,417		18.78
Issued (1)	(10,364)		27.92
Phantom units outstanding as of December 31, 2018	635,837		27.34		11,025
Granted	111,012		14.50
Issued (1)	(115,484)		25.20
Phantom units outstanding as of December 31, 2019	631,365		25.48		6,831
Granted	129,265		5.25
Phantom units outstanding as of December 31, 2020	760,630		22.04		3,408

(1) During the years ended December 31, 2019 and 2018, we issued ARLP common units of 115,484 and 7,181, respectively, to participants under the SERP and Directors' Deferred Compensation Plan.  Units issued in 2018 were net of units settled in cash to satisfy tax withholding obligations.

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Total SERP and Directors' Deferred Compensation Plan expense was $0.7 million, $1.6 million and $1.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.  As of December 31, 2020 and 2019, the total obligation associated with the SERP and Directors' Deferred Compensation Plan was $16.8 million and $16.1 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for unit-based compensation.

18.SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2020		2019		2018
		(in thousands)
Cash Paid For:
Interest	$	44,226	$	43,093	$	38,450
Income taxes	$	12	$	—	$	34
Non-Cash Activity:
Accounts payable for purchase of property, plant and equipment	$	5,731	$	14,504	$	14,585
Right-of-use assets acquired by operating lease	$	278		25,593		—
Market value of common units issued under deferred compensation plans before tax withholding requirements	$	3,837	$	17,415	$	6,142

19.ASSET RETIREMENT OBLIGATIONS

The majority of our operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan.  

The following table presents the activity affecting the asset retirement and mine closing liability:

	Year Ended December 31,
	2020		2019
	(in thousands)
Beginning balance	$	137,514	$	137,114
Accretion expense		4,033		4,087
Payments		(1,769)		(2,948)
Allocation of liability associated with acquisitions, mine development and change in assumptions		(11,880)		(739)
Ending balance	$	127,898	$	137,514

For the year ended December 31, 2020, the allocation of liability associated with acquisition, mine development and change in assumptions was a net decrease of $11.9 million.  This net decrease was attributable to lower cost assumptions and completion of certain reclamation obligations across all operations, permit modifications and extension of projected mine life estimates at certain mines, partially offset by acquisition of property with existing reclamation liabilities.  

For the year ended December 31, 2019, the allocation of liability associated with acquisition, mine development and change in assumptions was immaterial.

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The impact of discounting our estimated cash flows resulted in reducing the accrual for asset retirement obligations by $102.1 million and $102.9 million at December 31, 2020 and 2019, respectively. Estimated payments of asset retirement obligations as of December 31, 2020 are as follows:

Year Ended
December 31,	(in thousands)
2021	$	6,411
2022		2,723
2023		2,570
2024		3,317
2025		4,601
Thereafter		210,330
Aggregate undiscounted asset retirement obligations		229,952
Effect of discounting		(102,054)
Total asset retirement obligations		127,898
Less: current portion		(6,411)
Non-current asset retirement obligations	$	121,487

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis.  As of December 31, 2020 and 2019, we had approximately $171.1 million and $181.6 million, respectively, in surety bonds outstanding to secure the performance of our reclamation obligations.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for asset retirement obligations.

20.ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

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.  Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents.  Both pneumoconiosis and traumatic claims are covered through our self-insured programs.

The following is a reconciliation of the changes in workers' compensation liability (including current and long-term liability balances):

	December 31,
	2020		2019
	(in thousands)
Beginning balance	$	53,384	$	49,539
Accruals increase		5,146		7,162
Payments		(8,482)		(11,320)
Interest accretion		1,278		1,606
Valuation loss		3,413		6,397
Ending balance	$	54,739	$	53,384

The discount rate used to calculate the estimated present value of future obligations for workers' compensation was 1.95% and 2.81% at December 31, 2020 and 2019, respectively.

The valuation losses in both 2020 and 2019 were primarily attributable to a decrease in the discount rate used to calculate the estimated present value of future obligations as well as unfavorable changes in claims development in their respective years.

As of December 31, 2020 and 2019, we had $95.2 million and $90.2 million, respectively, in surety bonds and letters of credit outstanding to secure workers' compensation obligations.

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We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for the particular claim year have been met.  Our workers' compensation liability above is presented on a gross basis and does not include our expected receivables on our insurance policy.  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. Our receivables are included in Other long-term assets on our consolidated balance sheets.

The following is a reconciliation of the changes in pneumoconiosis benefit obligations:

	December 31,
	2020		2019
	(in thousands)
Benefit obligations at beginning of year	$	97,683	$	72,095
Service cost		3,526		2,593
Interest cost		2,998		3,044
Actuarial (gain) loss		7,787		23,298
Benefits and expenses paid		(3,498)		(3,347)
Benefit obligations at end of year	$	108,496	$	97,683

The following is a reconciliation of the changes in the pneumoconiosis benefit obligation recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Net actuarial gain (loss)	$	(7,787)	$	(23,298)	$	4,599
Reversal of amortization item:
Net actuarial (gain) loss		(686)		(4,582)		2
Total recognized in accumulated other comprehensive loss	$	(8,473)	$	(27,880)	$	4,601

The discount rate used to calculate the estimated present value of future obligations for pneumoconiosis benefits was 2.38%, 3.12% and 4.13% at December 31, 2020, 2019 and 2018, respectively.

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Amount recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	40,399	$	31,927	$	4,047

The actuarial loss component of the change in benefit obligations in 2020 was primarily attributable to a) a decrease in the discount rate used to calculate the estimated present value of the future obligations and b) an increase in the assumptions regarding future medical benefits and legal expenses. These components were partially offset in part by favorable demographic changes in the at-risk population.  The actuarial loss component of the change in benefit obligations in 2019 was primarily attributable to a) a decrease in the discount rate used to calculate the estimated present value of the future obligations and b) an increase in Federal and State benefit levels. These components were offset in part by favorable demographic changes in the at-risk population.  

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Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for pneumoconiosis and workers' compensation benefits:

	December 31,
	2020		2019
	(in thousands)
Workers’ compensation claims	$	54,739	$	53,384
Pneumoconiosis benefit claims		108,496		97,683
Total obligations		163,235		151,067
Less current portion		(10,646)		(11,175)
Non-current obligations	$	152,589	$	139,892

Both the pneumoconiosis benefit and workers' compensation obligations were unfunded at December 31, 2020 and 2019.

The pneumoconiosis benefit and workers' compensation expense consists of the following components:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Black lung benefits:
Service cost	$	3,526	$	2,593	$	2,525
Interest cost (1)		2,998		3,044		2,542
Net amortization (1)		(686)		(4,582)		2
Total pneumoconiosis expense		5,838		1,055		5,069
Workers' compensation expense		12,305		17,541		11,270
Net periodic benefit cost	$	18,143	$	18,596	$	16,339

________________________________________

(1) Interest cost and net amortization is included in the Other income (expense) line item within our consolidated statements of income (see Note 2 – Summary of Significant Accounting Policies).

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for workers' compensation and pneumoconiosis benefits.

21.RELATED-PARTY TRANSACTIONS

We have continuing related-party transactions with MGP and its affiliates.  The Board of Directors and its conflicts committee ("Conflicts Committee") review our related-party transactions that involve a potential conflict of interest between our general partner or its affiliates and ARLP or its subsidiaries or any other partner of ARLP to determine that such transactions are fair and reasonable to ARLP.  As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below that had such potential conflict of interest as fair and reasonable to ARLP.

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Affiliate Coal Lease Agreements

The following table summarizes advanced royalties outstanding and related payments and recoupments under our affiliate coal lease agreements:

				WKY CoalPlay
				Towhead		Webster		Henderson		WKY
		SGP/Craft Foundations		Coal		Coal		Coal		CoalPlay
				Henderson						Henderson
		Tunnel		& Union		Webster		Henderson		& Union
		Ridge		Counties, KY		County, KY		County, KY		Counties, KY		Total
		Acquired		Acquired		Acquired		Acquired		Acquired
		2005		December 2014		December 2014		December 2014		February 2015
	(in thousands)
As of January 1, 2018		$	3,000	$	10,684	$	5,356	$	7,566	$	6,387	$	32,993
Payments			—		3,597		2,570		2,520		2,131		10,818
Recoupment			(3,000)		(204)		(31)		—		(36)		(3,271)
Unrecoupable			—		—		(7,895)		—		—		(7,895)
As of December 31, 2018			—		14,077		—		10,086		8,482		32,645
Payments			4,500		3,597		2,568		2,521		2,131		15,317
Recoupment			(3,000)		(1,071)		—		—		(107)		(4,178)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2019			1,500		16,603		—		12,607		10,506		41,216
Payments			3,000		3,597		2,568		2,522		2,132		13,819
Recoupment			(3,000)		(1,022)		—		—		(56)		(4,078)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2020		$	1,500	$	19,178	$	—	$	15,129	$	12,582	$	48,389

SGP/Craft Foundations—In January 2005, we acquired Tunnel Ridge from ARH.  In connection with this acquisition, we assumed a coal lease with SGP.  Under the terms of the lease, Tunnel Ridge is required to pay an annual minimum royalty of $3.0 million.  The lease expires the earlier of January 1, 2033 or upon the exhaustion of the mineable and merchantable leased coal.  Tunnel Ridge incurred $6.1 million, $7.2 million and $6.0 million in earned royalties in 2020, 2019 and 2018 respectively.  As of January 1, 2019 the property subject to this lease is owned by the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation, an undivided one-half interest each (the "Craft Foundations").

WKY CoalPlay—In February 2015, WKY CoalPlay entered into a coal lease agreement with Alliance Resource Properties, LLC ("Alliance Resource Properties") regarding coal reserves located in Henderson and Union Counties, Kentucky. The lease has an initial term of 20 years and provides for earned royalty payments to WKY CoalPlay of 4.0% of the coal sales price and annual minimum royalty payments of $2.1 million. All annual minimum royalty payments are recoupable from future earned royalties. Alliance Resource Properties also was granted an option to acquire the leased reserves at any time during a three-year period beginning in February 2018 for a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in these reserves taking into account payments previously made under the lease (See Note 12 – Variable Interest Entities).

In December 2014, WKY CoalPlay's subsidiaries, Towhead Coal Reserves, LLC and Henderson Coal Reserves, LLC entered into coal lease agreements with Alliance Resource Properties.  The leases have initial terms of 20 years and provide for earned royalty payments of 4.0% of the coal sales price to both and annual minimum royalty payments of $3.6 million and $2.5 million, respectively.  All annual minimum royalty payments for each agreement are recoupable from future earned royalties related to their respective agreements.  Each agreement granted Alliance Resource Properties an option to acquire the leased reserves at any time during a three-year period beginning in December 2017 for a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in the reserves taking into account payments previously made under the leases. These options expired in December 2020. (See Note 12 – Variable Interest Entities).

In December 2014, WKY CoalPlay's subsidiary, Webster Coal Reserves, LLC entered into a coal lease agreement with Alliance Resource Properties.  The lease has an initial term of 7 years and provides for earned royalty payments of 4.0% of the coal sales price and annual minimum payments of $2.6 million.  The agreement grants Alliance Resource Properties an option to acquire the leased reserves at any time during a three year period beginning in December 2017 for

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a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in the reserves taking into account payments previously made under the lease (See Note 12 – Variable Interest Entities).  In the third quarter of 2019 it was determined that the balance of advanced royalties, the advance royalty payment in 2020 and the remaining advanced royalty payment expected in 2021 totaling $2.6 million, may not be recouped as a result of the reduction of the Dotiki’s economic mine life determined in 2018 and the subsequent ceasing of production in the third quarter of 2019.  We accrued the expected future advance payments and recognized the charge in Asset Impairment expense in the third quarter of 2019.  See Note 4 – Long-Lived Asset Impairments for more information.

Cavalier Minerals– As discussed in Note 12 – Variable Interest Entities, through our subsidiaries, we hold a non-economic managing member interest and a 96% non-managing member interest in Cavalier Minerals and, Bluegrass Minerals, a third party, holds a 4% non-managing member interest and a profits interest.  See Note 13 – Investments for information on payments made and distributions received by Cavalier Minerals.  

22.COMMITMENTS AND CONTINGENCIES

Commitments—We lease buildings and equipment under operating lease agreements that provide for the payment of both minimum and contingent rentals.  We also have noncancelable coal reserve leases as discussed in Note 21 – Related-Party Transactions and noncancelable leases with a third party for equipment under finance lease obligations. For information regarding future minimum lease payments see Note 9 – Leases.

Contractual Commitments—In connection with planned capital projects, we have contractual commitments of approximately $21.0 million at December 31, 2020.  As of December 31, 2020, we had no commitments to purchase coal from external production sources in 2021 and thereafter.

General Litigation—On March 9, 2018, we finalized an agreement with a customer and certain of its affiliates to settle breach of contract litigation we initiated in January 2015.  The agreement provided for a $93.0 million cash payment to us, execution of a new coal supply agreement with the customer, continued export transloading capacity for our Appalachian mines and the acquisition of certain coal reserves for $2.0 million from an affiliate of the customer.  The $93.0 million cash payment we received was the total compensation recorded in our consolidated statements of income for the agreement.  We have paid or accrued in total, $13.0 million of legal fees and associated incentive compensation costs related to this settlement which resulted in a net gain of $80.0 million reflected in the Settlement gain line item in our consolidated statements of income.

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership.  We record an accrual for a potential loss related to these matters when, in management's opinion, such loss is probable and reasonably estimable.  Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity.  However, if the results of these matters were different from management's current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

Other—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.

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23.CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

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.  Our sales into the international coal market are considered exports and 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.  No individual country was attributed greater than 10% of total domestic and export tons sold during the years ended December 31, 2020, 2019 and 2018.  

We have significant long-term coal supply agreements, some of which contain prospective price adjustment provisions designed to reflect changes in market conditions, labor and other production costs and, in the infrequent circumstance when the coal is sold other than free on board the mine, changes in transportation rates.  Our major customers are defined as those customers from which we derive at least ten percent of our total revenues, including transportation revenues.  Total revenues from major customers are as follows:

		Year Ended December 31,
	Segment	2020		2019		2018
		(in thousands)
Customer A	Illinois Basin	$	197,379	$	228,500	$	219,115
Customer B	Appalachia		—		213,319		—
Customer C	Illinois Basin		157,271		—		—
Customer D	Illinois Basin/Appalachia		137,785		—		—

Trade accounts receivable from major customers totaled approximately $32.0 million and $26.3 million at December 31, 2020 and 2019, respectively.  Our bad debt experience has historically been insignificant.  Financial conditions of our customers could result in a material change to our bad debt expense in future periods.  The coal supply agreements with these customers expire in 2022 for Customer C and Customer D and 2020 for Customer A.

24.SEGMENT INFORMATION

We operate in the United States as 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.  We aggregate multiple operating segments into three reportable segments, Illinois Basin, Appalachia, and Minerals.  We also have an "all other" category referred to as Other and Corporate.  Our 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 two coal segments include seven mining complexes operating in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia and a coal loading terminal in Indiana on the Ohio River.  The Minerals reportable segment aggregates our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins.  The operations within our Minerals reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests.

The Illinois Basin reportable segment includes currently operating mining complexes (a) Gibson County Coal, LLC's ("Gibson") mining complex, which includes the Gibson South mine, (b) the Warrior Coal, LLC ("Warrior") mining complex, (c) the River View Coal, LLC ("River View") mining complex and (d) the Hamilton mining complex. The Illinois Basin reportable segment also includes our currently operating Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") coal loading terminal in Indiana on the Ohio River.

The Illinois Basin reportable segment also includes Mid-America Carbonates, LLC ("MAC")  and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal, LLC's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, (d) the Hopkins County Coal, LLC mining complex, and (e) Sebree Mining, LLC's mining complex.    

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The Appalachia reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining, LLC ("MC Mining") mining complex. The Mettiki mining complex includes Mettiki Coal (WV), LLC's Mountain View mine and Mettiki Coal, LLC's preparation plant.  The Appalachia reportable segment also includes the Penn Ridge assets, which are primarily coal mineral interests.

The Minerals reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale III (Note 13 – Investments) and Cavalier Minerals.  AR Midland acquired its mineral interest in the Wing Acquisition (Note 3 – Acquisitions).

Other and Corporate includes marketing and administrative activities, Matrix Design Group, LLC and its subsidiaries ("Matrix Design"), Alliance Design Group, LLC ("Alliance Design") (collectively, Matrix Design and Alliance Design referred to as 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 (see Note 13 – Investments).  In addition, Other and Corporate includes certain Alliance Resource Properties, LLC's 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 and Alliance Finance (both discussed in Note 8 – Long-Term Debt).

In response to the impacts of the COVID-19 pandemic, we announced on March 30, 2020 a temporary cessation of coal production at our River View, Gibson, Hamilton and Warrior mining complexes in our Illinois Basin segment and on April 9, 2020 a temporary cessation of coal production at our MC Mining complex in our Appalachia segment.  Underground production operations resumed in the second quarter of 2020 at each of our mining complexes.  All of our seven mining complexes are now producing coal.  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.  Due to the ongoing and unforeseen impacts of the COVID-19 pandemic, on April 26, 2020, the employment of 116 employees of Gibson and 78 employees of the Hamilton mining complexes was terminated permanently.  In addition to reduced production levels and employment adjustments, we took numerous actions in 2020 to optimize cash flows and preserve liquidity by reducing capital expenditures, working capital, costs and expenses, including adjusting our corporate support structure to better align to current operating levels.

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Reportable segment results are presented below.

	Illinois						Other and		Elimination
	Basin		Appalachia		Minerals		Corporate		(1)		Consolidated
	(in thousands)
Year Ended December 31, 2020
Revenues - Outside	$	770,051	$	500,330	$	43,141	$	14,607	$	—	$	1,328,129
Revenues - Intercompany		—		—		—		10,517		(10,517)		—
Total revenues (2)		770,051		500,330		43,141		25,124		(10,517)		1,328,129
Segment Adjusted EBITDA Expense (3)		520,324		319,730		4,106		18,543		(1,454)		861,249
Segment Adjusted EBITDA (4)		236,911		172,288		39,773		6,580		(9,063)		446,489
Total assets		1,018,916		448,567		613,916		477,469		(392,852)		2,166,016
Capital expenditures		48,648		70,960		—		1,493		—		121,101
Year Ended December 31, 2019
Revenues - Outside	$	1,219,618	$	644,389	$	53,036	$	44,677	$	—	$	1,961,720
Revenues - Intercompany		16,690		—		—		12,173		(28,863)		—
Total revenues (2)		1,236,308		644,389		53,036		56,850		(28,863)		1,961,720
Segment Adjusted EBITDA Expense (3)		756,423		423,623		7,811		36,845		(19,806)		1,204,896
Segment Adjusted EBITDA (4)		385,200		215,950		46,997		32,911		(9,057)		672,001
Total assets		1,373,516		500,027		643,213		541,261		(471,323)		2,586,694
Capital expenditures (5)		189,270		111,739		—		4,849		—		305,858
Year Ended December 31, 2018
Revenues - Outside	$	1,289,898	$	643,898	$	—	$	69,061	$	—	$	2,002,857
Revenues - Intercompany		31,191		67		—		12,431		(43,689)		—
Total revenues (2)		1,321,089		643,965		—		81,492		(43,689)		2,002,857
Segment Adjusted EBITDA Expense (3)		796,370		398,243		—		52,321		(35,134)		1,211,800
Segment Adjusted EBITDA (4)		417,773		240,286		21,323		44,864		(8,555)		715,691
Total assets		1,380,912		440,518		161,312		589,010		(177,004)		2,394,748
Capital expenditures		166,468		64,037		—		2,975		—		233,480

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations, coal sales and purchases between operations within different segments, sales of receivables to AROP Funding, financing between segments and insurance premiums paid to Wildcat Insurance.

(2) Revenues included in the Other and Corporate column are primarily attributable to the outside and affiliate revenues at the Matrix Group and coal brokerage activities.  In additions, Other and Corporate includes affiliate revenues for administrative and Wildcat Insurance services.

(3) Segment Adjusted EBITDA Expense includes operating expenses, coal purchases and other income. Transportation expenses are excluded as transportation revenues are recognized in an amount equal to transportation expenses when title passes to the customer.  

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The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expenses (excluding depreciation, depletion and amortization):

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Segment Adjusted EBITDA Expense	$	861,249	$	1,204,896	$	1,211,800
Outside coal purchases		—		(23,357)		(1,466)
Other income (expense)		(1,593)		561		(2,621)
Operating expenses (excluding depreciation, depletion and amortization)	$	859,656	$	1,182,100	$	1,207,713

(4) Segment Adjusted EBITDA is defined 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.    Consolidated Segment Adjusted EBITDA is reconciled to net income (loss) as follows:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Consolidated Segment Adjusted EBITDA	$	446,489	$	672,001	$	715,691
General and administrative		(59,806)		(72,997)		(68,298)
Depreciation, depletion and amortization		(313,387)		(309,075)		(280,225)
Settlement gain		—		—		80,000
Asset impairments		(24,977)		(15,190)		(40,483)
Goodwill impairment		(132,026)		—		—
Interest expense, net		(45,478)		(45,496)		(40,059)
Acquisition gain		—		177,043		—
Income tax (expense) benefit		(35)		211		(22)
Acquisition gain attributable to noncontrolling interest		—		(7,083)		—
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Noncontrolling interest		169		7,512		866
Net income (loss)	$	(129,051)	$	406,926	$	367,470

.

(5) Capital Expenditures shown exclude the AllDale Acquisition on January 3, 2019 and the Wing Acquisition on August 2, 2019 (Note 3 – Acquisitions).

25.SUBSEQUENT EVENTS

Other than the event described in Note 8, there were no subsequent events.

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SUPPLEMENTAL OIL & GAS RESERVE INFORMATION (UNAUDITED)

These supplemental oil & gas reserve information disclosures are required for periods in which a company has significant oil & gas producing activities.  A company is considered to have significant oil & gas producing activities if any of its revenues, results of operations or assets from oil & gas producing activities exceed 10% of consolidated revenues, results of operations or assets for the year being measured.  Subsequent to our 2019 acquisitions of oil and gas mineral interests, we are considered to have significant oil & gas producing activities.  We were not considered to have significant oil & gas producing activities in periods prior to 2019 when we held equity method investments in the AllDale Partnerships and therefore have not included these reserve disclosures periods prior to 2019.

Geographical Area of Operation

All of our proved oil & gas reserves are located within the continental United States with the majority concentrated in Texas, Oklahoma, New Mexico and North Dakota.  The following supplemental disclosures about our proved oil & gas reserves including costs incurred, capitalized cost, results of operations and cash flows are presented on a consolidated basis.

Costs Incurred in Oil & Gas Property Acquisitions

Costs incurred in oil & gas property acquisitions are presented below:

	Year Ended
	December 31,
	2020		2019
	(in thousands)
Acquisition costs of properties
Proved	$	—	$	242,116
Unproved		—		376,166
Total	$	—	$	618,282

Property acquisition costs for 2019 include non-cash amounts for the AllDale Acquisition.  In connection with the AllDale Acquisition, we marked our previously held equity method investments to a fair value of $307.3 million, resulting in a $177.0 million gain.  See Note 3 – Acquisitions in our consolidated financial statements for more information regarding 2019 acquisition activity.

Oil & Gas Capitalized Costs

Aggregate capitalized costs related to oil & gas activities with applicable accumulated depreciation, depletion, and amortization are presented below:

	As of December 31,
	2020				2019
	(in thousands)
	Consolidated		Our Share of an Equity Method Investee		Consolidated		Entity's Share of Equity Method Investee
Proved properties	$	273,665	$	8,331	$	242,116	$	8,217
Unproved properties		343,239		20,287		376,166		20,531
Total (1)		616,904		28,617		618,282		28,748
Less accumulated depreciation, depletion and amortization		(48,019)		(1,985)		(22,658)		(1,194)
Oil & gas properties, net	$	568,885	$	26,633	$	595,624	$	27,554

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(1) The change in total capitalized cost reflects sales of proved and unproved properties in 2020 of $1.1 million and measurement period adjustments associated with the Wing Acquisition of $0.3 million discussed in Note 3 – Acquisitions of our consolidated financial statements.

Results of Operations from Oil & Gas Activities

The following schedule sets forth the revenues and expenses related to our oil & gas mineral interests. It does not include any interest costs or general and administrative costs, and therefore, is not necessarily indicative of the contribution to the results of our Minerals segment.

	Year Ended
	December 31,
	2020		2019
	(in thousands)
Consolidated activities
Oil & gas royalties	$	42,912	$	51,735
Other revenues		229		1,301
Production costs and severance taxes		(4,611)		(7,859)
Depreciation, depletion and amortization		(25,376)		(22,658)
Total results of oil & gas activities	$	13,154	$	22,519
Our share of an equity method investee
Oil & gas royalties	$	2,674	$	3,200
Other revenues		22		190
Production costs and severance taxes		(374)		(411)
Depreciation, depletion and amortization		(748)		(854)
Total results of oil & gas activities	$	1,574	$	2,125

Oil & Gas Reserves

Proved oil & gas reserve estimates as of December 31, 2020 were prepared by our internal engineering team and 95% of those reserves were audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers.  Proved reserves are estimated under existing economic and operating conditions based upon the 12-month unweighted average of the first-of-the-month prices.

Due to the inherent uncertainties and the limited nature of reservoir data, such estimates are subject to change as additional information becomes available.  The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimate. Revisions result primarily from new information obtained from development drilling and production history and from changes in economic factors.

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The net proved developed and undeveloped oil & gas reserves quantities of the mineral interests attributable to us are summarized below:

	Crude Oil		Natural Gas		Natural Gas Liquids		Total
	(MBbl)		(MMcf)		(MBbl)		(MBOE)
Consolidated activities
As of January 1, 2019		—		—		—		—
Purchases of minerals in place		6,509		30,055		3,477		14,995
Revisions of previous estimates		1,015		1,956		(548)		793
Production		(700)		(3,382)		(347)		(1,611)
As of December 31, 2019 (1)		6,824		28,629		2,582		14,177
Revisions of previous estimates		(194)		2,679		343		596
Extensions and discoveries		1,095		3,039		347		1,949
Production		(905)		(3,301)		(337)		(1,792)
Sales of minerals in place		(18)		(29)		(3)		(26)
As of December 31, 2020 (1)		6,802		31,017		2,932		14,904

(1) Proved reserves of approximately 972 MBOE and 1,208 MBOE were attributable to noncontrolling interests, as of December 31, 2020 and 2019, respectively.

	Crude Oil		Natural Gas		Natural Gas Liquids		Total
	(MBbl)		(MMcf)		(MBbl)		(MBOE)
Our share of an equity method investee
As of January 1, 2019		295		2,205		—		662
Revisions of previous estimates		78		11		153		234
Sales of minerals in place		(7)		(8)		—		(8)
Production		(41)		(282)		(17)		(105)
As of December 31, 2019		325		1,926		136		783
Revisions of previous estimates		(0)		(1)		(2)		(3)
Extensions and discoveries		62		461		54		193
Production		(44)		(334)		—		(100)
As of December 31, 2020		342		2,052		188		873
Total consolidated and equity interests in reserves at December 31, 2020		7,144		33,069		3,120		15,777
Net proved developed reserves as of December 31, 2019		5,766		24,449		2,009		11,850
Net proved developed reserves as of December 31, 2020		5,073		23,504		2,252		11,244
Net proved undeveloped reserves as of December 31, 2019		1,383		6,106		709		3,110
Net proved undeveloped reserves as of December 31, 2020		2,071		9,565		868		4,533

Natural gas reserves are converted to BOE based on a 6:1 ratio: six Mcf of natural gas converts to one BOE.

Notable changes in proved reserves during the year ended December 31, 2020, included:

● Net change due to extensions and discoveries: The increases are a result of the addition of new properties by the operators under which we own mineral interests.  In 2020, a net addition of 2,142 MBOE occurred primarily from the completion of 655 new wells on our acreage and from the addition of 877 new proved undeveloped locations due to permitting and drilling activity.

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● Revisions: Increases in oil & gas are also due to changes in the underlying commodity prices during the year and revisions of previous quantity estimates.

Standardized Measure of Discounted Future Net Cash Flows

In accordance with SEC and FASB requirements, future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-of-the-month commodity prices for the year ended December 31, 2020. All prices are adjusted for quality, transportation fees, energy content and regional basis differentials. Future cash inflows are computed by applying applicable prices relating to our proved reserves to the year end quantities of those reserves. Future production costs are derived based on current costs assuming continuation of existing economic conditions.  There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the ARLP Partnership is generally not subject to federal income taxes.  The ARLP Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion.

While due care was taken in preparation of the following cash flow projections, we do not represent that this data is the fair value of our oil & gas properties, or a fair estimate of the present value of cash flows to be obtained from their development and production. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices are expected to vary significantly from those used and actual costs may vary.

	As of December 31,
	2020				2019
	(in thousands)
	Consolidated		Our Share of an Equity Method Investee		Consolidated		Entity's Share of Equity Method Investee
Future cash inflows	$	302,112	$	15,414	$	463,972	$	24,372
Future production costs and severance taxes		(21,555)		(1,244)		(34,997)		(1,515)
Future net cash flows (undiscounted)		280,558		14,171		428,975		22,857
Annual discount 10% for estimated timing		(130,341)		(6,406)		(198,025)		(10,642)
Total standardized measure (1)	$	150,217	$	7,764	$	230,950	$	12,215

(1) Includes standardized discounted future net cash flows of approximately $5.2 million and $12.5 million attributable to noncontrolling interests in the ARLP Partnership's consolidated subsidiaries as of December 31, 2020 and 2019, respectively.

The average realized product prices weighted by production over the remaining lives of the properties are presented in the table below:

	For the Year Ended December 31,
	2020		2019
Oil (per Bbl)	$	36.95	$	52.32
Natural gas (per Mcf)		0.88		1.83
NGLs (per Bbl)		7.99		21.95

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Changes in the standardized measure of discounted future net cash flows related to the proved oil & gas reserves of the properties are as follows:

	As of December 31,
	2020				2019
	(in thousands)
	Consolidated		Our Share of an Equity Method Investee		Consolidated		Entity's Share of Equity Method Investee
Standardized measure, beginning of year	$	230,950	$	12,215	$	—	$	12,845
Purchases and sales of reserves in place, less related costs		(567)		—		231,287		(252)
Sales, net of production costs		(38,301)		(2,300)		(43,875)		(2,788)
Net changes due to extensions and discoveries		15,770		1,344		—		—
Net changes in prices and production costs		(67,524)		(3,906)		10,533		(2,517)
Revisions of previous quantity estimates		(2,843)		(378)		14,560		3,398
Accretion of discount		16,216		870		18,403		1,284
Changes in timing and other		(3,484)		(81)		42		245
Net increase (decrease) in standardized measures		(80,733)		(4,451)		230,950		(630)
Standardized measure, end of year	$	150,217	$	7,764	$	230,950	$	12,215

Net change in prices and production costs occur from one reporting period to another when the SEC reporting price for that period changes.  For 2020, this was a major component of the overall reserves value change from 2019 due mainly to the COVID-19 pandemic crisis and the subsequent decline in oil and gas demand.  

The standardized measure amount at the beginning of 2019 for our share of an Equity Method Investee reflects only our proportionate share of AllDale III's beginning of the year standardized measure amount.  Our previously held equity method investments in AllDale I & II, as a result of the AllDale Acquisition in 2019, are now consolidated on our financial statements.  Accordingly, we reflect the activity for AllDale I & II in our consolidated standardized measure amounts and not the Equity Method amounts.

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SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ALLIANCE RESOURCE PARTNERS, L.P.

CONDENSED BALANCE SHEETS (PARENT)

DECEMBER 31, 2020 AND 2019

(In thousands, except unit data)

	December 31,
	2020		2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,174	$	2,176
Total current assets		2,174		2,176
OTHER ASSETS:
Investments in consolidated subsidiaries		1,146,491		1,329,406
Total other assets		1,146,491		1,329,406
TOTAL ASSETS	$	1,148,665	$	1,331,582
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued taxes other than income taxes	$	100	$	100
Total current liabilities		100		100
Total liabilities		100		100
PARTNERS' CAPITAL:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively		1,148,565		1,331,482
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,148,665	$	1,331,582

See accompanying notes.

CONDENSED STATEMENTS OF OPERATIONS (PARENT)

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands, except unit and per unit data)

	Year Ended December 31,
	2020		2019		2018
EXPENSES:
General and administrative	$	—	$	41	$	30
Total operating expenses		—		41		30
INCOME (LOSS) FROM OPERATIONS		—		(41)		(30)
Interest income		24		34		22
Equity in earnings of consolidated subsidiaries		(129,244)		399,421		366,612
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	$	(129,220)	$	399,414	$	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER	$	—	$	—	$	1,560
LIMITED PARTNERS	$	(129,220)	$	399,414	$	365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$	(1.02)	$	3.07	$	2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED		127,164,659		128,116,670		130,758,169

See accompanying notes.

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CONDENSED STATEMENTS OF CASH FLOWS (PARENT)

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands)

	Year Ended December 31,
	2020		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:	$	51,751	$	278,308	$	275,924
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions paid to Partners		(51,753)		(278,425)		(275,902)
Net cash used in financing activities		(51,753)		(278,425)		(275,902)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(2)		(117)		22
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,176		2,293		2,271
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,174	$	2,176	$	2,293

See accompanying notes.

NOTES TO FINANCIAL INFORMATION (PARENT)

1.BASIS OF PRESENTATION

In these parent-company-only financial statements, our investment in consolidated subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries and reduced by distributions received from subsidiaries since the date of acquisition.  These parent-company-only financial statements should be read in conjunction with our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.

2.GUARANTEES

As the parent of the Intermediate Partnership, we are a guarantor of both the Credit Agreement and Senior Notes discussed in "Item 8. Financial Statements and Supplementary Data—Note 8 – Long-Term Debt" of this Annual Report on Form 10-K.  In addition to these guarantees, we have provided guarantees on surety indemnity agreements and financially guaranteed certain coal supply agreements. The duration of these guarantees varies and the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2020 is not material.

3.CASH DISTRIBUTIONS RECEIVED

We received distributions of $51.8 million, $278.4 million and $275.9 million from our consolidated subsidiaries during the years ended December 31, 2020, 2019, and 2018, respectively.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.CONTROLS AND PROCEDURES

Disclosure Controls and Procedures.  We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosures.  As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 ("Exchange Act"), we have evaluated, under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act) as of December 31, 2020.  Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective as of December 31, 2020.

Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud.  A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.  Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the ARLP Partnership have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur.  Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control.  The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.  Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.  Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.  We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

Management's Annual Report on Internal Control over Financial Reporting.  Management of the ARLP Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Exchange Act.  The ARLP Partnership's internal control over financial reporting is designed to provide reasonable assurance to our management and Board of Directors of our general partner regarding the preparation and fair presentation of published financial statements.  Our controls are designed to provide reasonable assurance that the ARLP Partnership's assets are protected from unauthorized use and that transactions are executed in accordance with established authorizations and properly recorded.  The internal controls are supported by written policies and are complemented by a staff of competent business process owners and an internal auditor supported by competent and qualified external resources used to assist in testing the operating effectiveness of the ARLP Partnership's internal control over financial reporting.  Management concluded that the design and operations of our internal controls over financial reporting at December 31, 2020 are effective and provide reasonable assurance the books and records accurately reflect the transactions of the ARLP Partnership.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2020.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control—Integrated Framework (2013).  Based on its assessment, management concluded that, as of December 31, 2020, the ARLP Partnership's internal control over financial reporting

137

was effective based on those criteria, and management believes that we have no material internal control weaknesses in our financial reporting process.

Ernst & Young LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2020, as stated in their report that is included herein.

Changes in Internal Controls Over Financial Reporting.  There have not been any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) or Rule 15d-15(f) of the Exchange Act) in the three months ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Alliance Resource Management GP, LLC

and the Partners of Alliance Resource Partners, L.P.

Opinion on Internal Control over Financial Reporting

We have audited Alliance Resource Partners, L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Alliance Resource Partners, L.P. and subsidiaries (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income (loss), cash flows and partners’ capital for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2), and our report dated February 23, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.  

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized

139

acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 23, 2021

ITEM 9B.OTHER INFORMATION

None.

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PART III

ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE GENERAL PARTNER

As is commonly the case with publicly traded limited partnerships, we are managed and operated by our general partner. The following table shows information for executive officers and members of the Board of Directors as of the date of the filing of this Annual Report on Form 10-K.  Executive officers and directors are elected until death, resignation, retirement, disqualification, or removal.

Imothy
Name	Age	Position With Our General Partner
Joseph W. Craft III	70	Chairman, President and Chief Executive Officer
Brian L. Cantrell	61	Senior Vice President and Chief Financial Officer
R. Eberley Davis	63	Senior Vice President, General Counsel and Secretary
Robert J. Fouch	63	Vice President, Controller and Chief Accounting Officer
Robert G. Sachse	72	Executive Vice President
Kirk D. Tholen	48	Senior Vice President and Chief Strategic Officer
Charles R. Wesley	66	Executive Vice President and Director
Timothy J. Whelan	58	Senior Vice President - Sales and Marketing of Alliance Coal, LLC
Thomas M. Wynne	64	Senior Vice President and Chief Operating Officer
Nick Carter	74	Director and Member of Audit, Compensation and Conflicts Committees
Robert J. Druten	73	Director and Member of Audit, Compensation and Conflicts* Committees
John H. Robinson	70	Director and Member of Audit, Compensation* and Conflicts Committees
Wilson M. Torrence	79	Director and Member of Audit* and Compensation Committees

* Indicates Chairman of Committee.

Joseph W. Craft III has been President, Chief Executive Officer ("CEO") and a Director since August 1999, Chairman of the Board of Directors since January 1, 2019, and indirectly owns our general partner.  Previously Mr. Craft served as President of MAPCO Coal Inc. since 1986. During that period, he also was Senior Vice President of MAPCO Inc. and had previously been that company's General Counsel and Chief Financial Officer.  He is a former Chairman and current Board member of the National Coal Council, a Board Member of the National Mining Association, and a Director and past Chairman of the America's Power.  Mr. Craft is a Director and former Chairman of the Kentucky Chamber of Commerce.  He has been a Director of BOK Financial Corporation (NASDAQ: BOKF) since 2007 and chairman of its compensation committee since 2014.  Mr. Craft holds a Bachelor of Science degree in Accounting and a Juris Doctorate degree from the University of Kentucky. Mr. Craft also is a graduate of the Senior Executive Program of the Alfred P. Sloan School of Management at Massachusetts Institute of Technology. The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Craft should serve as a Director include his long history of significant involvement in the coal industry, his demonstrated business acumen and his exceptional leadership of the Partnership since its inception.

Brian L. Cantrell has been Senior Vice President and Chief Financial Officer since October 2003.  Prior to his current position, Mr. Cantrell was President of AFN Communications, LLC from November 2001 to October 2003 where he had previously served as Executive Vice President and Chief Financial Officer after joining AFN in September 2000.  Mr. Cantrell's previous positions include Chief Financial Officer, Treasurer and Director with Brighton Energy, LLC from August 1997 to September 2000; Vice President—Finance of KCS Medallion Resources, Inc.; and Vice President—Finance, Secretary and Treasurer of Intercoast Oil and Gas Company.  Mr. Cantrell is a Certified Public Accountant and holds Master of Accountancy and Bachelor of Accountancy degrees from the University of Oklahoma.

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R. Eberley Davis has been Senior Vice President, General Counsel and Secretary since February 2007.  From 2003 to February 2007, Mr. Davis practiced law in the Lexington, Kentucky office of Stoll Keenon Ogden PLLC.  Prior to joining Stoll Keenon Ogden, Mr. Davis was Vice President, General Counsel and Secretary of Massey Energy Company for one year.  Mr. Davis also served in various positions, including Vice President and General Counsel, for Lodestar Energy, Inc. from 1993 to 2002.  Mr. Davis is an alumnus of the University of Kentucky, where he received a Bachelor of Arts degree in Economics and his Juris Doctorate degree.  He also holds a Master of Business Administration degree from the University of Kentucky.  Mr. Davis is a Trustee of the Energy and Mineral Law Foundation, and a member of the Kentucky Bar Association.

Robert J. Fouch became Chief Accounting Officer in February 2019.  Since August 2006, Mr. Fouch has served as Vice President and Controller.  Prior to his current position, from 1999 to 2006, Mr. Fouch served as Assistant Controller.  Mr. Fouch joined Alliance's predecessor, MAPCO Inc. in 1981 and held a variety of accounting positions of increasing responsibility.  He worked for the audit firm of Deloitte, Haskins and Sells prior to joining MAPCO.  He is a Certified Public Accountant and holds a Bachelor of Science degree in Accounting from Oral Roberts University.

Robert G. Sachse has been Executive Vice President since August 2000.  From November 2006 until the beginning of 2016, Mr. Sachse had responsibility for our coal marketing, sales and transportation functions.  Mr. Sachse was also Vice Chairman of our general partner from August 2000 to January 2007.  Mr. Sachse was Executive Vice President and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO merged with The Williams Companies.  Mr. Sachse held various positions while with MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas Liquids in 1992.  Mr. Sachse holds a Bachelor of Science degree in Business Administration from Trinity University and a Juris Doctorate degree from the University of Tulsa.

Kirk D. Tholen became Senior Vice President and Chief Strategic Officer in December 2019 and also serves as President of ARLP's oil & gas minerals business.  Prior to his current position, Mr. Tholen most recently served as a Managing Director within the Oil & Gas Group and Head of the Acquisitions and Divestitures ("A&D") Practice for Houlihan Lokey in Houston.  From 2012 to 2015, he was Head of A&D for Credit Agricole CIB and was responsible for creating and leading their A&D platform to service domestic and cross-border client transactions as well as assisting in reserve-base lending, equity offerings and high yield debt offerings.  From 2006 to 2012, Mr. Tholen provided business development, marketing, transaction management, negotiating and closing services to clients at Albrecht & Associates, Inc., a sell-side E&P boutique advisory firm.  His previous industry experience also includes serving as a Region Engineer for BJ Services from 1996 to 2006, where he provided drilling and fracturing technical services to clients operating in the lower 48 and Gulf of Mexico predominately as a dedicated in-house engineer focused on drilling and completions for BP, Conoco and Devon.  Mr. Tholen began his career in 1992 joining UNOCAL's Louisiana inland waters and shallow shelf operation and reservoir engineering team.  He holds a Bachelor of Science degree in Chemical Engineering from the University of Louisiana at Lafayette and a Master of Business Administration degree from the University of Houston.

Charles R. Wesley has been a Director since January 2009 and Executive Vice President since March 2009.  Mr. Wesley has served in a variety of capacities since joining the company in 1974, including as Senior Vice President—Operations from August 1996 through February 2009.  Mr. Wesley is a former Chairman of the Board of Directors of the Kentucky Coal Association and also has served the industry as past President of the West Kentucky Mining Institute and National Mine Rescue Association Post 11, and as a director of the Kentucky Mining Institute.  Mr. Wesley holds a Bachelor of Science degree in Mining Engineering from the University of Kentucky.  The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Wesley should serve as a Director include his long history of significant involvement in the coal industry, his successful leadership of the Partnership's operations, and his knowledge and technical expertise in all aspects of producing and marketing coal.

Timothy J. Whelan has been Senior Vice President - Sales and Marketing of Alliance Coal, LLC since May 2013.  Since joining Alliance in September 2003, Mr. Whelan has held several positions with increasing responsibility, serving as Vice President – Sales prior to his current position. Mr. Whelan previously served in various business development positions for MAPCO Inc. and as Director, Power & Gas Origination for Williams Energy Marketing and Trading.  Mr. Whelan has over 30 years of energy industry experience, and is a former board member of the American Coal Council and The Coal Institute. Mr. Whelan holds a Bachelor of Science degree in Finance from the University of Arkansas.

Thomas M. Wynne has been Senior Vice President and Chief Operating Officer since March 2009.  Mr. Wynne joined the company in 1981 as a mining engineer and has held a variety of positions with the company prior to his appointment

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in July 1998 as Vice President—Operations.  Mr. Wynne has served the coal industry on the National Executive Committee for National Mine Rescue and previously as a member of the Coal Safety Committee for the National Mining Association.  In addition, Mr. Wynne is a past Chairman of the Kentucky Coal Association.  Mr. Wynne holds a Bachelor of Science degree in Mining Engineering from the University of Pittsburgh and a Master of Business Administration degree from West Virginia University.

Nick Carter became a Director in April 2015.  Mr. Carter is a member of the Audit, Compensation and Conflicts Committees.  Mr. Carter retired as President and Chief Operating Officer of Natural Resource Partners L.P. (NYSE: NRP) on September 1, 2014, having served in such capacities since 2002 and in other roles for NRP or its affiliates since 1990.  Prior to 1990, Mr. Carter held various positions with MAPCO Coal Corporation and was engaged in the private practice of law.  Mr. Carter also serves on the board of directors, the audit committee and as chairman of the compensation committee of Community Trust Bancorp, Inc. (NASDAQ: CTBI).  Mr. Carter previously served as chairman of the National Council of Coal Lessors for 12 years and as chairman of the West Virginia Chamber of Commerce.  He also previously served as a board member of the West Virginia Coal Association, the Indiana Coal Council, the National Mining Association, and ACCCE.  Mr. Carter has served as a board member of the Kentucky Coal Association for over 20 years and currently is its Treasurer.  Mr. Carter holds Bachelor and Juris Doctorate degrees from the University of Kentucky and a Master of Business Administration degree from the University of Hawaii.  The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Carter should serve as a Director include his extensive experience in the coal and energy industries and in senior corporate leadership.

Robert J. Druten became a Director effective January 1, 2019.  Mr. Druten is Chairman of the Conflicts Committee and is a member of the Audit and Compensation Committees.  From January 2007 through 2018, Mr. Druten was a member of the board of directors of Alliance GP, LLC, the former general partner of AHGP.  From September 1994 until his retirement in August 2006, Mr. Druten served as Executive Vice President and Chief Financial Officer of Hallmark Cards, Inc.  Mr. Druten holds a Bachelor of Science degree in Accounting from the University of Kansas as well as a Masters of Business Administration from Rockhurst University.  Mr. Druten currently serves as Chairman of the Board of Directors of Kansas City Southern Industries, Inc. (NYSE: KSU), a transportation and financial services company, and is Chairman of its executive committee, and is a member of its compensation committee and nominating and governance committees.  Mr. Druten is also a Trustee and Chairman of the Board of Entertainment Properties Trust (NYSE: EPR), a real estate investment trust focused on the acquisition of movie theatre complexes and other entertainment related properties, and is a member of its audit, compensation, finance and governance committees.  Mr. Druten previously served as a director of American Italian Pasta, from 2007 until it was acquired by Ralcorp Holdings in July, 2010, where he was the Chair of the Audit Committee and also served on the Compensation Committee.  The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Druten should serve as Director are demonstrated by his lengthy and distinguished service as Chief Financial Officer of Hallmark, including direct oversight of a public company subsidiary, and his extensive experience serving as a director of public companies in multiple industries.

John H. Robinson became a Director in December 1999.  Mr. Robinson is Chairman of the Compensation Committee and a member of the Audit and Conflicts Committees.  Mr. Robinson is Chairman of Hamilton Ventures, LLC.  From 2003 to 2004, he was Chairman of EPC Global, Ltd., an engineering staffing company.  From 2000 to 2002, he was Executive Director of Amey plc, a British business process outsourcing company.  Mr. Robinson served as Vice Chairman of Black & Veatch, Inc. from 1998 to 2000.  He began his career at Black & Veatch in 1973 and was a General Partner and Managing Partner prior to becoming Vice Chairman when the firm incorporated.  Mr. Robinson is a Director of Coeur Mining Corporation and a member of its executive and audit committees and chairman of its compensation committee.  Mr. Robinson is also a Director of Olsson Associates.  He holds Bachelor and Master of Science degrees in Engineering from the University of Kansas and is a graduate of the Owner-President-Management Program at the Harvard Business School.  The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Robinson should serve as a Director include his significant experience in the engineering and consulting industries, his extensive service in senior corporate leadership positions in both industries and his familiarity with financial matters.

Wilson M. Torrence became a Director in January 2007.  Mr. Torrence is Chairman of the Audit Committee and a member of the Compensation Committee.  From April 2015 through June 2018, Mr. Torrence was also a member of the board of directors of Alliance GP, LLC, the former general partner of AHGP, and chairman of its audit committee.  Mr. Torrence retired from Fluor Corporation in 2006 as a Senior Vice President of Project Development and Investments and after retirement has performed investment and business consulting services for various clients.  Mr. Torrence was employed at Fluor from 1989 to 2006 where, among other roles, he was responsible for the global Project Investment and Structured Finance Group and served as Chairman of Fluor's Investment Committee.  In that position, Mr. Torrence had

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executive responsibility for Fluor's global activities in developing and arranging third-party financing for some of Fluor's clients' construction projects.  Prior to joining Fluor in 1989, Mr. Torrence was President and CEO of Combustion Engineering Corporation's Waste to Energy Division and, during that time, also served as Chairman of the Institute of Resource Recovery, a Washington-based industry advocacy organization.  Mr. Torrence began his career at Mobil Oil Corporation, where he held several executive positions, including Assistant Treasurer of Mobil's International Marketing and Refining Division and Chief Financial and Planning Officer of Mobil Land Development Company.  Mr. Torrence holds a Bachelor and a Master of Business Administration degree from Virginia Tech University.  The specific experience, qualifications, attributes or skills that led to the conclusion Mr. Torrence should serve as a Director include his extensive experience in the construction and energy businesses, his senior corporate finance-related and other leadership positions and his participation in numerous financing transactions.

Board of Directors

Mr. Craft, who has been President and CEO and a member of the Board of Directors since ARLP's inception, assumed the Chairman role effective January 1, 2019 following the retirement of Mr. John P. Neafsey, who served as Chairman from ARLP’s inception through 2018.  We believe this leadership structure of the Board of Directors is appropriate for the Partnership given Mr. Craft's extensive knowledge of our industry, significant ownership position and proven leadership of the Partnership.

The Board of Directors generally administers its risk oversight function through the board as a whole.  The Chairman, President and CEO, who reports to the Board of Directors, and the other executives named above, who report to the Chairman, President and CEO, have day-to-day risk management responsibilities.  At the Board of Directors' request, each of these executives attends the meetings of the Board of Directors, where the Board of Directors routinely receives reports on our financial results, the status of our operations and our safety performance, and other aspects of implementation of our business strategy, with ample opportunity for specific inquiries of management.  In addition, management provides periodic reports of the Partnership's financial and operational performance to each member of the Board of Directors.  The Audit Committee provides additional risk oversight through its quarterly meetings, where it receives a report from the Partnership's internal auditor, who reports directly to the Audit Committee, and reviews the Partnership's contingencies, significant transactions and subsequent events, among other matters, with management and our independent auditors.

The Board of Directors has selected as director nominees individuals with experience, skills and qualifications relevant to the business of the Partnership, such as experience in energy or related industries or with financial markets, expertise in mining, engineering or finance, and a history of service in senior leadership positions.  The Board of Directors has not established a formal process for identifying director nominees, nor does it have a formal policy regarding consideration of diversity in identifying director nominees, but has endeavored to assemble a diverse group of individuals with the qualities and attributes required to provide effective oversight of the Partnership.

Audit Committee

The Audit Committee comprises all four non-employee members of the Board of Directors (Messrs. Carter, Druten, Robinson and Torrence).  After reviewing the qualifications of the current members of the Audit Committee, and any relationships they may have with us that might affect their independence, the Board of Directors has determined that all current Audit Committee members are "independent" as that concept is defined in Section 10A of the Exchange Act, all current Audit Committee members are "independent" as that concept is defined in the applicable rules of NASDAQ Stock Market, LLC, all current Audit Committee members are financially literate, and Mr. Torrence qualifies as an "audit committee financial expert" under the applicable rules promulgated pursuant to the Exchange Act.

Report of the Audit Committee

The Audit Committee oversees our financial reporting process on behalf of the Board of Directors.  Management has primary responsibility for the financial statements and the reporting process including the systems of internal controls.  The Audit Committee has responsibility for the appointment, compensation and oversight of the work of our independent registered public accounting firm and assists the Board of Directors by conducting its own review of our:

● filings with the SEC pursuant to the Securities Act of 1933 ("Securities Act") and the Exchange Act (i.e., Forms 10-K, 10-Q, and 8-K);

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● press releases and other communications by us to the public concerning earnings, financial condition and results of operations, including changes in distribution policies or practices affecting the holders of our units, if such review is not undertaken by the Board of Directors;

● systems of internal controls regarding finance and accounting that management and the Board of Directors have established; and

● auditing, accounting and financial reporting processes generally.

In fulfilling its oversight and other responsibilities, the Audit Committee met eight times during 2020.  The Audit Committee's activities included, but were not limited to: (a) selecting the independent registered public accounting firm, (b) meeting periodically in executive session with the independent registered public accounting firm, (c) reviewing the Quarterly Reports on Form 10-Q for the three months ended March 31, June 30, and September 30, 2020, (d) performing a self-assessment of the committee, (e) reviewing the Audit Committee charter, and (f) reviewing the overall scope, plans and findings of our internal auditor.  Based on the results of the annual self-assessment, the Audit Committee believes that it satisfied the requirements of its charter.  The Audit Committee also reviewed and discussed with management and the independent registered public accounting firm this Annual Report on Form 10-K, including the audited financial statements.

Our independent registered public accounting firm, Ernst & Young LLP ("EY"), is responsible for expressing an opinion on the conformity of the audited financial statements with GAAP.  The Audit Committee reviewed with EY its judgment as to the quality, not just the acceptability, of our accounting principles and such other matters as are required to be discussed with the Audit Committee pursuant to the applicable requirements of the Public Company Accounting Oversight Board ("PCAOB") and the SEC.

The Audit Committee received written disclosures and the letter from EY required by applicable requirements of the PCAOB Rule 3526, "Communication with Audit Committees Concerning Independence," and has discussed with EY its independence from management and the ARLP Partnership.

Based on the reviews and discussions referred to above, the Audit Committee recommended to the Board of Directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2020 for filing with the SEC.

Members of the Audit Committee:

Wilson M. Torrence, Chairman

Nick Carter

Robert J. Druten

John H. Robinson

Code of Ethics

We have adopted a code of ethics with which the Chairman, President and CEO and the senior financial officers (including the principal financial officer and the principal accounting officer) are expected to comply.  The code of ethics is publicly available on our website under "Investor Relations" at www.arlp.com and is available in print without charge to any unitholder who requests it.  Such requests should be directed to Investor Relations at (918) 295-7674.  If any substantive amendments are made to the code of ethics or if there is a grant of a waiver, including any implicit waiver, from a provision of the code to the President and CEO, Chief Financial Officer, or Chief Accounting Officer, we will disclose the nature of such amendment or waiver on our website or in a report on Form 8-K.

Communications with the Board

Unitholders or other interested parties can contact any director or committee of the Board of Directors by writing to them c/o Senior Vice President, General Counsel and Secretary, P.O. Box 22027, Tulsa, Oklahoma 74121-2027.  Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee.  The Audit Committee has procedures for (a) receipt, retention and treatment of

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complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act, as amended, requires directors, executive officers and persons who beneficially own more than ten percent of a registered class of our equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such equity securities. Based upon a review of the copies of the forms furnished to us and written representations from certain reporting persons, we believe that during 2020 none of our directors or executive officers or persons who beneficially owned more than ten percent of a registered class of our equity securities were delinquent with respect to any of the filing requirements under Section 16(a).

Reimbursement of Expenses of our General Partner and its Affiliates

Our general partner does not receive any management fee or other compensation in connection with its management of us.  Our general partner is reimbursed by us for all expenses incurred on our behalf.  Please see "Item 13. Certain Relationships and Related Transactions, and Director Independence—Administrative Services."

ITEM 11.EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Introduction

The Compensation Committee oversees the compensation of our general partner's executive officers, including the Chairman, President and CEO, our principal executive officer, the Senior Vice President and Chief Financial Officer, our principal financial officer, and the three most highly compensated executive officers in 2020, each of whom is named in the Summary Compensation Table (collectively, our "Named Executive Officers").  Our Named Executive Officers are employees of our operating subsidiary, Alliance Coal.  

Compensation Objectives and Philosophy

The compensation of our Named Executive Officers is designed to achieve two key objectives: (i) provide a competitive compensation opportunity to allow us to recruit and retain key management talent, and (ii) motivate and reward the executive officers for creating sustainable, capital-efficient growth in available cash to maximize our distributions to our unitholders.  In making decisions regarding executive compensation, the Compensation Committee reviews current compensation levels of other companies in the coal industry and other peers, considers the Chairman, President and CEO's assessment of each of the other executives, and uses its discretion to determine an appropriate total compensation package of base salary and short-term and long-term incentives.  The Compensation Committee intends for each executive officer's total compensation to be competitive in the marketplace and to effectively motivate the officer.  Based upon its review of our overall executive compensation program, the Compensation Committee believes the program is appropriately applied to our general partner's executive officers and is necessary to attract and retain the executive officers who are essential to our continued development and success, to compensate those executive officers for their contributions and to enhance unitholder value.  Moreover, the Compensation Committee believes the total compensation opportunities provided to our general partner's executive officers create alignment with our long-term interests and those of our unitholders.  As a result, we do not maintain unit ownership requirements for our Named Executive Officers.

Setting Executive Compensation

We have not historically maintained employment agreements with any of our Named Executive Officers.  We provided an employment letter to our Senior Vice President and Chief Strategic Officer, Mr. Tholen (the "Tholen Employment Letter"), in connection with his hiring in December 2019 setting forth the terms of his employment, which we determined were necessary to successfully hire Mr. Tholen and in the best interests of the Company. The Tholen Employment Letter provides for, among other things, (i) an initial annual base salary of $500,000.00, (ii) an award in 2019 under the LTIP having value on the grant date of $1 million and (iii) a one-time signing bonus of $1.5 million, which was paid or is payable in three equal cash installments of $500,000 in December 2019, 2020 and 2021, subject to Mr. Tholen's continued employment through such dates. The Tholen Employment Letter also provides that if Mr. Tholen’s employment

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is involuntarily terminated on or before December 31, 2022, other than for Good Cause (as defined in the Tholen Employment Letter), Mr. Tholen will receive a severance payment in an amount equal to (a) two times Mr. Tholen's then-effective annual base salary, plus (b) two times the then-effective standard payout for Mr. Tholen under the short-term incentive plan ("STIP"), plus (c) any unpaid installment(s) of the one-time signing bonus described above, which amount shall be paid at the time of Mr. Tholen's termination of employment. The foregoing description of the Tholen Employment Letter does not purport to be complete and is qualified in its entirety by reference to the full and complete text of the Tholen Employment Letter, which is filed as an exhibit to this filing.

Role of the Compensation Committee

The compensation committee of our general partner ("Compensation Committee") discharges the Board of Directors' responsibilities relating to our general partner's executive compensation program.  The Compensation Committee oversees our compensation and benefit plans and policies, administers our incentive bonus and equity participation plans, and reviews and approves annually all compensation decisions relating to our Named Executive Officers.  The Compensation Committee is empowered by the Board of Directors and by the Compensation Committee's charter to make all decisions regarding compensation for our Named Executive Officers without ratification or other action by the Board of Directors.  The Compensation Committee has authority to secure services for executive compensation matters, legal advice, or other expert services, both from within and outside the company.  While the Compensation Committee is empowered to delegate all or a portion of its duties to a subcommittee, it has not done so.

The Compensation Committee comprises all of our directors who have been determined to be "independent" by the Board of Directors in accordance with applicable NASDAQ Stock Market, LLC and SEC regulations, presently Messrs. Robinson, Carter, Druten and Torrence.

Role of Executive Officers

Each year, the Chairman, President and CEO submits recommendations to the Compensation Committee for adjustments to the salary, bonuses and long-term equity incentive awards payable to our Named Executive Officers, excluding himself.  The Chairman, President and CEO bases his recommendations on his assessment of each executive's performance, experience, demonstrated leadership, job knowledge and management skills.  The Compensation Committee considers the recommendations of the Chairman, President and CEO as one factor in making compensation decisions regarding our Named Executive Officers.  Historically, and in 2020, the Compensation Committee and the Chairman, President and CEO have been substantially aligned on decisions regarding compensation of the Named Executive Officers.  As executive officers are promoted or hired during the year, the Chairman, President and CEO makes compensation recommendations to the Compensation Committee and works closely with the Compensation Committee to ensure that all compensation arrangements for executive officers are consistent with our compensation philosophy and are approved by the Compensation Committee.  At the direction of the Compensation Committee, the Chairman, President and CEO and the Senior Vice President, General Counsel and Secretary attend certain meetings of the Compensation Committee.

Use of Peer Group Comparisons

The Compensation Committee believes that it is important to review and compare our performance with that of peer companies in the coal industry, and reviews the composition of the peer group annually.  The peer group for 2020 included Arch Coal, Inc., Consol Energy, Inc., Contura Energy, Inc., Natural Resource Partners L.P., Warrior Met Coal, Inc., and Peabody Energy Corporation.  In assessing the competitiveness of our executive compensation program for 2020, the Compensation Committee, with the assistance of the Chairman, President and CEO, collected and analyzed peer group proxy information and developed a comparative analysis of base salaries, short-term incentives, total cash compensation, long-term incentives and total direct compensation.  The Compensation Committee uses the peer group data as a point of reference for comparative purposes, but it is not the determinative factor for the compensation of our Named Executive Officers.  The Compensation Committee exercises discretion in determining the nature and extent of the use of comparative pay data.

Consideration of Equity Ownership and CEO Compensation

Mr. Craft, the Chairman, President and CEO, is evaluated and treated differently with respect to compensation than our other Named Executive Officers.  Mr. Craft and related entities own significant equity positions in ARLP and Mr. Craft indirectly owns our general partner.  Because of these ownership positions, the interests of Mr. Craft are directly

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aligned with those of our unitholders.  Mr. Craft has not received an increase in base salary since 2002, has not received a bonus under our STIP since 2005 and did not receive any grants of LTIP awards from 2005 through 2015.  On January 22, 2016, the Compensation Committee approved an LTIP award for Mr. Craft that vested on January 1, 2019.  Mr. Craft has not received any subsequent LTIP awards.  Beginning in February 2016, at Mr. Craft's request, his annual base salary was reduced to $1.

Compensation Components

Overview

The principal components of compensation for our Named Executive Officers (other than Mr. Craft) include:

● base salary;

● annual cash incentive bonus awards under the STIP; and

● awards of restricted units under the LTIP.

The relative amount of each component is not based on any formula, but rather is based on the recommendation of the Chairman, President and CEO, subject to the discretion of the Compensation Committee to make any modifications it deems appropriate.

Each of our Named Executive Officers (including Mr. Craft) also receives supplemental retirement benefits through the Supplemental Executive Retirement Plan ("SERP").  In addition, all executive officers are entitled to customary benefits available to our employees generally, including group medical, dental, and life insurance and participation in our profit sharing and savings plan ("PSSP").  Our PSSP is a defined contribution plan and includes an employer matching contribution of 75% on the first 3% of eligible compensation contributed by the employee, an employer non-matching contribution of 0.75% of eligible compensation, and an employer supplemental contribution of 5% of eligible compensation.  The PSSP provides an additional means of attracting and retaining qualified employees by providing tax-advantaged opportunities for employees to save for retirement.

Base Salary

When reviewing base salaries, the Compensation Committee's policy is to consider the individual's experience, tenure and performance, the individual's level of responsibility, the position's complexity and its importance to us in relation to other executive positions, our financial performance, and competitive pay practices.  The Compensation Committee also considers comparative compensation data of companies in our peer group and the recommendation of the Chairman, President and CEO of our general partner.  Base salaries are reviewed annually to ensure continuing consistency with market levels, and adjustments to base salaries are made as needed to reflect movement in the competitive market as well as individual performance.  None of our Named Executive Officers received an increase in salary in 2020.

Annual Cash Incentive Bonus Awards

The STIP is designed to assist us in attracting, retaining and motivating qualified personnel by rewarding management, including our Named Executive Officers, and selected other salaried employees with cash awards for our achievement of an annual financial performance target.  The annual performance target is recommended by the Chairman, President and CEO and approved by the Compensation Committee, typically in January of each year.  The performance measure is subject to equitable adjustment in the sole discretion of the Compensation Committee to reflect the occurrence of any significant events during the year.

The performance target historically has been EBITDA-based, with items added or removed from the EBITDA calculation to ensure that the performance target reflects the operating results of our core business.  (EBITDA is defined as net income of ARLP before net interest expense, income taxes, depreciation, depletion and amortization and net income attributable to noncontrolling interest.)  The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target, and it increases in relationship to our EBITDA, as adjusted, exceeding the minimum threshold.  Our STIP Guidelines provide that achieving the minimum threshold is the minimum acceptable result for a performance pay-out to occur under the STIP, although the Compensation Committee may determine satisfactory results and adjust the size of the pay-out pool in its sole discretion.  In 2020, the

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Compensation Committee approved a minimum financial performance target of $482.3 million in EBITDA from current operations, normalized by excluding any charges for unit-based and directors' compensation.  For 2020, we did not achieve the minimum performance target and no performance pay-out was awarded.  

If a performance pay-out pool is approved by the Compensation Committee, individual awards to our Named Executive Officers each year are determined by and in the discretion of the Compensation Committee.  However, the Compensation Committee does not establish individual target payout amounts for the Named Executive Officers' STIP awards.  As it does when reviewing base salaries, in determining individual awards under the STIP, the Compensation Committee considers its assessment of the individual's performance, our financial performance, comparative compensation data of companies in our peer group and the recommendation of the Chairman, President and CEO, although EBITDA-based performance targets described above are given significant weight.  The compensation expense associated with STIP awards is recognized in the year earned, with the cash awards generally payable in the first quarter of the following calendar year.  Termination of employment of an executive officer for any reason prior to payment of a cash award will result in forfeiture of any right to the award, unless and to the extent waived by the Compensation Committee in its discretion.

The performance measure for the STIP in 2021 will be EBITDA for current operations, excluding charges for unit-based and directors' compensation.  As discussed above, the Compensation Committee may, in its discretion, make equitable adjustments to the performance criteria under the STIP and adjust the amount of the aggregate pay-out.  The Compensation Committee believes the STIP performance criteria for 2021 will be reasonably difficult to achieve and therefore support our key compensation objectives discussed above.

The Compensation Committee maintains discretion to grant cash bonus awards outside of the STIP to address special situations.  During 2020, certain Named Executive Officers received a discretionary cash bonus award.  These bonuses were determined following the Compensation Committee’s review and discussion of retention and incentive concerns amidst the unique impacts of the COVID-19 pandemic.

These actions were taken by the Compensation Committee in recognition of the difficulty of managing our business through the unprecedented impacts of the COVID-19 pandemic and based on its determination that such actions were prudent and necessary to help retain and motivate our management team.

Equity Awards under the LTIP

Equity compensation pursuant to the LTIP is a key component of our executive compensation program.  Our LTIP is sponsored by Alliance Coal.  Under the LTIP, grants may be made of either (a) restricted units, (b) options to purchase common units (although to date, no grants of options have been made) or c) following an amendment of the LTIP in 2020, cash awards.  The Compensation Committee has authority to determine the participants to whom restricted units are granted, the number of restricted units to be granted to each such participant, and the conditions under which the restricted units may become vested, including the duration of any vesting period.  Annual grant levels for designated participants (including our Named Executive Officers) are recommended by our general partner's Chairman, President and CEO, subject to review and approval by the Compensation Committee.  Grant levels are intended to support the objectives of the comprehensive compensation package described above.  The LTIP grants provide our Named Executive Officers with the opportunity to achieve a meaningful ownership stake in the Partnership, thereby assuring that their interests are aligned with our success.  Even though Mr. Craft was not granted an award under the LTIP from 2005 through 2020 with the exception of one grant in 2016, the Compensation Committee believes Mr. Craft's interests are directly aligned with the interests of our unitholders as a result of his ownership positions.  There is no formula for determining the size of awards to any individual recipient and, as it does when reviewing base salaries and individual STIP payments, the Compensation Committee considers its assessment of the individual's performance, our financial performance, compensation levels at peer companies in the coal industry and the recommendation of the Chairman, President and CEO.  Amounts realized from prior grants, including amounts realized due to changes in the value of our common units, are not considered in setting grant levels or other compensation for our Named Executive Officers.

Restricted Units.  Restricted units granted under the LTIP are "phantom" or notional units that upon vesting entitle the participant to receive an ARLP common unit.  Restricted units granted under the LTIP vest at the end of a stated period from the grant date, provided we achieve an aggregate performance target for that period.  However, if a grantee's employment is terminated for any reason prior to the vesting of any restricted units, those restricted units will be automatically forfeited, unless the Compensation Committee, in its sole discretion, determines otherwise.  The number of units actually distributed upon satisfaction of the applicable vesting requirements is reduced to cover the income tax

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withholding requirement for each individual participant based upon the fair market value of the common units as of the date of distribution.  At the Compensation Committee's discretion, grants of restricted units under the LTIP may include the contingent right to receive quarterly distributions in an amount equal to the cash distributions we make to unitholders during the vesting period ("DERs").  DERs are payable, in the discretion of the Compensation Committee, either in cash or in the form of additional Restricted Units credited to a book keeping account subject to the same vesting restrictions as the tandem award.

The performance target applicable to restricted unit awards under the LTIP is based on a normalized EBITDA measure, with that measure typically being similar to the STIP measure for the year of the grant.  The target, however, requires achieving an aggregate performance level for the vesting period.  We typically issue grants under the LTIP at the beginning of each year, with the exceptions of new employees who begin employment with us at some other time and job promotions that may occur at some other time.  However, no grants under the LTIP have yet been made in 2021.  The compensation expense associated with LTIP grants is recognized over the vesting period in accordance with FASB Accounting Standards Codification ("ASC") 718, Compensation — Stock Compensation.

Our general partner's policy is to grant restricted units pursuant to the LTIP to serve as a means of incentive compensation for performance.  Therefore, no consideration will be payable by the LTIP participants upon receipt of the common units.  Common units to be delivered upon the vesting of restricted units may be common units we already own, common units we acquire in the open market or from any other person, newly issued common units, or any combination of the foregoing.  If we issue new common units upon payment of the restricted units instead of purchasing them, the total number of common units outstanding will increase.

The LTIP provides the Compensation Committee with discretion to determine the conditions for vesting (as well as all other terms and conditions) associated with any award under the plan, and to amend any of those conditions so long as an amendment does not materially reduce the benefit to the participant.  The Compensation Committee believes the performance-related vesting conditions of all outstanding awards under the LTIP will be reasonably difficult to satisfy and therefore support our key compensation objectives discussed above.

2018 LTIP Grants.  On December 10, 2020 the Compensation Committee determined that the performance vesting requirement with respect to the restricted units granted under the LTIP on January 24, 2018 (the "2018 Grants") had been met, and approved amending the terms of the 2018 Grants to accelerate the date of vesting of the restricted units from January 1, 2021 to December 14, 2020 and to provide for settlement of the 2018 Grants in cash rather than units.  The 2018 Grants vested on December 14, 2020 at a price of $4.99 per unit and were settled in cash.    

2019 and 2020 LTIP Grants.  During the first quarter of 2020, it was determined the vesting performance requirement with respect to the restricted units granted under the LTIP on January 23, 2019 (the "2019 Grants") was not probable of being satisfied, and previously recognized expense for the 2019 Grants was reversed.  During the fourth quarter of 2020, it was determined the vesting performance requirement with respect to the restricted units granted under the LTIP on January 22, 2020 (the "2020 Grants") was not probable of being satisfied, and previously recognized expense for the 2020 Grants was reversed.  In December 2020, the 2019 Grants to all participants were canceled, the 2020 Grant to Mr. Tholen was canceled, and the Compensation Committee approved amending the terms of the 2020 Grants to participants other than Mr. Tholen.  The amendments to the 2020 Grants revised the vesting performance requirement and increased the number of restricted units granted under the amended 2020 Grants. The amended 2020 Grants will vest on January 1, 2023, subject to the satisfaction of the vesting requirements.

In addition, in 2020 the Compensation Committee approved new 2020 service-based vesting LTIP awards. These awards will be settled in cash provided that the participant remain employed at the time of payment, which will be paid 75% in February 2022 and 25% in February 2023 for all participants other than Mr. Tholen, and will be paid one-half in February 2022 and one-half in February 2023 for Mr. Tholen.  The restricted units granted to Mr. Tholen in February 2020 (as well as restricted units granted to him in 2019) were cancelled in December 2020 and replaced with a cash service award that is payable one-half in February 2022 and one-half in February 2023, subject to his continued service on such dates.

As with the bonus awards above, these LTIP actions were taken by the Compensation Committee in recognition of the difficulty of managing our business through the unprecedented impacts of the COVID-19 pandemic and based on its determination that such actions were prudent and necessary to help retain and motivate our management team.

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Unit Options.  We have not made any grants of unit options. The Compensation Committee, in the future, may decide to make unit option grants to employees and directors on terms determined by the Compensation Committee.

Grant Timing.  The Compensation Committee does not time, nor has the Compensation Committee in the past timed, the grant of LTIP awards in coordination with the release of material non-public information.  Instead, LTIP awards are granted only at the time or times dictated by our normal compensation process as developed by the Compensation Committee.

Effect of a Change in Control.  Upon a "change in control" as defined in the LTIP, all awards outstanding under the LTIP will automatically vest and become payable or exercisable, as the case may be, in full.  Please see "Item 11. Executive Compensation—Potential Payments Upon a Termination or Change of Control."

Amendments and Termination.  The Board of Directors or the Compensation Committee may, in its discretion, terminate the LTIP at any time with respect to any common units for which a grant has not previously been made.  Except as required by the rules of the exchange on which the common units may be listed at that time, the Board of Directors or the Compensation Committee may alter or amend the LTIP in any manner from time to time; provided, however, that no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the affected participant.  In addition, the Board of Directors or the Compensation Committee may, in its discretion, establish such additional compensation and incentive arrangements as it deems appropriate to motivate and reward our employees.

Supplemental Executive Retirement Plan

We maintain the SERP to help attract and motivate key employees, including our Named Executive Officers.  The SERP is sponsored by Alliance Coal.  Participation in the SERP aligns the interest of each Named Executive Officer with the interests of our unitholders because all allocations made to participants under the SERP are made in the form of notional common units of ARLP, defined in the SERP as "phantom units."  The Compensation Committee approves the SERP participants and their percentage allocations, and can amend or terminate the SERP at any time.  All of our Named Executive Officers currently participate in the SERP.

Under the terms of the SERP, a participant is entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to his or her percentage allocation multiplied by the sum of the participant's base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year.  A participant's cumulative notional phantom unit account balance earns the equivalent of common unit distributions, which are added to the notional account balance in the form of additional phantom units.  All amounts granted under the SERP vest immediately and are paid out upon the participant's termination from employment in ARLP common units equal to the number of phantom units then credited to the participant's account, less the number of units required to satisfy our tax withholding obligations.  A participant in the SERP is not entitled to an allocation for the year in which his termination from employment occurs, except as described below.

A participant in the SERP, including any of our Named Executive Officers, is entitled to receive an allocation under the SERP for the year in which his employment is terminated only if such termination results from one of the following events:

(1) the participant's employment is terminated other than for "cause";

(2) the participant terminates employment for "good reason";

(3) a change of control of us or our general partner occurs and, as a result, the participant's employment is terminated (whether voluntary or involuntary);

(4) death of the participant;

(5) the participant attains (or has attained)  retirement age of 65 years; or

(6) the participant incurs a total and permanent disability, which shall be deemed to occur if the participant is eligible to receive benefits under the terms of the long-term disability program we maintain.

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This allocation for the year in which a participant's termination occurs shall equal the participant's eligible compensation for such year (including any severance amount, if applicable) multiplied by his percentage allocation under the SERP, reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year.

Other Compensation-Related Matters

Securities Trading Policy; Prohibitions on Hedging and Trading in Derivatives

To ensure alignment of the interests of our unitholders with our directors and all officers, including Named Executive Officers, the general partner's Securities Trading Policy prohibits any employee, officer, or director of the Partnership or any of its subsidiaries from engaging in trading involving (1) options or other derivative securities relating to ARLP units; (2) debt securities of ARLP or its affiliates; (3) hedging transactions involving ARLP securities; or (4) purchases of ARLP units on margin.

Tax Deductibility of Compensation

The deduction limitations imposed under Section 162(m) of the Internal Revenue Code do not apply to compensation paid to our Named Executive Officers because we are a limited partnership and not a "corporation" within the meaning of Section 162(m).

Perquisites and Personal Benefits

The Partnership provides a limited amount of perquisites and personal benefits to the Named Executive Officers in keeping with the Compensation Committee's objectives to provide competitive compensation to motivate and reward executive officers for creating sustainable, capital-efficient growth in available cash.  These perquisites and personal benefits typically include amounts for items such as tax preparation fees and social club dues, and are reviewed annually by the Compensation Committee.

Compensation Committee Report

The Compensation Committee has submitted the following report for inclusion in this Annual Report on Form 10-K:

Our Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K with management. Based on our Compensation Committee's review of and the discussions with management with respect to the Compensation Discussion and Analysis, our Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

The foregoing report is provided by the following directors, who constitute all the members of the Compensation Committee:

Members of the Compensation Committee:

John H. Robinson, Chairman

Nick Carter

Robert J. Druten

Wilson M. Torrence

Notwithstanding anything to the contrary set forth in any of our previous filings under the Securities Act or the Exchange Act, that incorporate future filings, including this Annual Report on Form 10-K, in whole or in part, the foregoing Compensation Committee Report shall not be deemed to be filed with the SEC or incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.

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Summary Compensation Table

								Non-Equity
						Unit		Incentive Plan		All Other
Name and Principal		Salary		Bonus		Awards		Compensation		Compensation
Position	Year	(1)		(2)		(3)(4)		(5)		(6)		Total
Joseph W. Craft III	2020	$	1	$	—	$	—	$	—	$	—	$	1
President, Chief Executive	2019		1		—		—		—		12,962		12,963
Officer and Chairman	2018		1		—		—		—		12,462		12,463
Brian L. Cantrell,	2020		309,846		289,513		756,965		—		181,843		1,538,167
Senior Vice President and	2019		299,846		—		529,161		213,000		66,612		1,108,619
Chief Financial Officer	2018		284,000		—		486,438		385,000		56,190		1,211,628
R. Eberley Davis	2020		351,635		377,249		964,133		—		248,531		1,941,548
Senior Vice President,	2019		341,154		—		673,993		274,000		86,768		1,375,915
General Counsel and Secretary	2018		325,000		—		619,568		530,000		61,275		1,535,843
Kirk D. Tholen (7)	2020		500,000		500,000		862,779		500,000		421,764		2,784,543
Senior Vice President and	2019		—		500,000		1,016,237		83,000		69,978		1,669,215
Chief Strategic Officer
Thomas M. Wynne	2020		411,769		391,899		1,114,122		—		267,645		2,185,435
Senior Vice President and	2019		398,231		—		774,261		280,000		80,287		1,532,779
Chief Operating Officer	2018		374,000		—		711,756		500,000		62,506		1,648,262

(1) In recent years, certain of our Named Executive Officers devoted a portion of their time to the business of one or more related parties and, to the extent they did so, the base salary of those executive officers was reimbursed to Alliance Coal by those related parties pursuant to an administrative services agreement. Please see "Item 1. Business—Employees—Administrative Services Agreement." In 2020 and 2019, Alliance Coal was not reimbursed base salary for any of our Named Executive Officers. In 2018, prior to the Simplification Transactions on May 31, 2018, the percentage of base salary reimbursed to Alliance Coal was 5% for Mr. Craft, 5% for Mr. Cantrell and 8% for Mr. Davis. Please see "Item 1. Business—Partnership Simplification" for more information on the Simplification Transactions.

(2) The amounts for Messrs. Cantrell, Davis and Wynne represent cash bonuses paid in December 2020. The amounts for Mr. Tholen represent the first and second installments of his signing bonus.  Please see "Item 11. Compensation Discussion and Analysis—Setting Executive Compensation" for a description of the terms of Mr. Tholen's employment.

(3) Restricted units granted in February 2020 were determined to be improbable of vesting and amended during the fourth quarter of 2020 for all LTIP participants other than Mr. Tholen, including Messrs. Cantrell, Davis and Wynne.  The amendments modified the performance vesting requirement and granted additional restricted units.  The modified performance vesting requirement makes it probable the awards will vest.  As a result, the amounts for 2020 for Messrs. Cantrell, Davis, and Wynne include $409,822, $521,981 and $603,944, respectively, representing the grant date fair value of the restricted units when originally granted in February 2020, and $213,857, $272,385 and $315,156, respectively, representing the fair value of the same restricted units at the date of modification in December 2020.  The fair value of the modified awards was calculated by taking the fair value of the modified awards at the date of modification minus the fair value of the original awards immediately prior to modification.  Since the original awards granted in February 2020 were determined to be improbable of vesting, the fair value of the original awards immediately prior to modification was zero.  The 2020 amounts also include the grant date fair value of the additional restricted units granted in December 2020.  For Mr. Tholen, the 2020 amount represents the grant date fair value of the restricted units when originally granted in February 2020.  The restricted units granted to Mr. Tholen in February 2020 (as well as the restricted units granted to him in 2019) were canceled in December 2020 and replaced with a cash service award that is payable one-half in February 2022 and one-half in February 2023.  Mr. Craft did not receive any grants under the LTIP during 2020.  See the Grants of Plan-Based Awards Table below for additional detail.  

(4) Other than the restricted units which were modified in December 2020 and discussed in footnote (3) above, the Unit Awards represent the aggregate grant date fair value of restricted units granted pursuant to FASB ASC 718, using the same assumptions as used for financial reporting purposes and which are more fully described in "Item 8.  Financial Statements and Supplementary Data—Note 17 – Common Unit-Based Compensation Plans," to each Named

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Executive Officer under the LTIP in the respective year.  The restricted units that were granted in 2018 were settled in cash at $4.99 per unit in December 2020.  The cash settlement is included in "All Other Compensation" in 2020 as discussed in footnote (6).  The restricted units that were granted in 2019 were canceled in December 2020 since it was determined that the vesting requirements for these restricted units were not probable of being satisfied.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Program Components—Equity Awards under the LTIP" for a description of the terms of the awards.

(5) Amounts represent the STIP bonus earned for the respective year. STIP payments typically are made in the first quarter of the year following the year in which they are earned, however the STIP payment to Mr. Tholen was made in December 2020. Please see "Item 11. Compensation Discussion and Analysis—Compensation Program Components—Annual Cash Incentive Bonus Awards."

(6) For all Named Executive Officers, the amounts represent the sum of the (a) SERP phantom unit contributions valued at the market closing price of our common units on the date the phantom unit was granted, (b) profit sharing savings plan employer contribution, (c) perquisites in excess of $10,000 and (d) cash settlement in December 2020 of restricted units that were granted under the LTIP in 2018. A reconciliation of the 2020 amounts shown is as follows:

			Profit Sharing Plan
			Employer				Cash Settlement of
	SERP		Contribution		Perquisites (a)		LTIP grants (b)		Total
Joseph W. Craft III	$	—	$	—	$	—	$	—	$	—
Brian L. Cantrell		40,056		22,800		—		118,987		181,843
R. Eberley Davis		74,180		22,800		—		151,551		248,531
Kirk D. Tholen		139,960		22,800		259,004		—		421,764
Thomas M. Wynne		70,744		22,800		—		174,101		267,645

a) For Mr. Tholen, perquisites and other personal benefits comprised of relocation related expenses of $259,004.  

b) In December 2020, we accelerated the vesting requirements for restricted units that were granted under the LTIP in 2018 and settled these restricted units in cash rather than units at a price of $4.99 per unit.    

(7) Mr. Tholen began employment and became a Named Executive Officer on December 23, 2019, therefore compensation for 2018 is not presented in the table.

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Grants of Plan-Based Awards Table

									All Other
			Estimated Future Payouts Under			Estimated Future Payouts Under			Unit	Grant Date
			Non-Equity Incentive Plan Awards			Equity Incentive Plan Awards			Awards:	Fair Value
			Threshold	Target	Maximum	Threshold	Target	Maximum	Number of	of Unit
Name	Grant Date	Approved Date	(3)	(4)	(3)	(5)	(6)	(5)	Units (7)	Awards (8)
Joseph W. Craft III	February 5, 2020	February 5, 2020					—		—	$	—
	February 14, 2020	(1), (2)					—		12,575		101,103
	December 17, 2020	December 17, 2020					—		—		—
	December 31, 2020	(2)					—		—		—
							—		12,575		101,103
Brian L. Cantrell	February 5, 2020	February 5, 2020					42,601		—		409,822
	February 14, 2020	(1), (2)					—		1,407		11,312
	December 17, 2020	December 17, 2020					69,152		—		347,143
	December 31, 2020	(2)					—		8,941		40,056
							111,753		10,348		808,333
R. Eberley Davis	February 5, 2020	February 5, 2020					54,260		—		521,981
	February 14, 2020	(1), (2)					—		1,977		15,895
	December 17, 2020	December 17, 2020					88,078		—		442,152
	December 31, 2020	(2)					—		16,558		74,180
							142,338		18,535		1,054,208
Kirk D. Tholen	February 5, 2020	February 5, 2020					89,686		—		862,779
	February 14, 2020	(1), (2)					—		215		1,729
	December 17, 2020	December 17, 2020					—		—		—
	December 31, 2020	(2)					—		31,241		139,960
							89,686		31,456		1,004,468
Thomas M. Wynne	February 5, 2020	February 5, 2020					62,780		—		603,944
	February 14, 2020	(1), (2)					—		1,999		16,072
	December 17, 2020	December 17, 2020					101,629		—		510,178
	December 31, 2020	(2)					—		15,791		70,744
							164,409		17,790	$	1,200,938

(1) In accordance with the provisions of the SERP, a participant's cumulative notional phantom unit account balance earns the equivalent of common unit distributions when we pay a distribution to our common unitholders, which is added to the account balance in the form of phantom units.

(2) These contributions are made in accordance with the SERP plan document that has been approved by the Compensation Committee.  Therefore, these contributions are not separately approved by the Compensation Committee.

(3) Awards under our STIP are subject to a minimum financial performance target each year.  However, determination of individual awards under the STIP is based upon an assessment of the Named Executive Officer's performance, comparative compensation data of companies in our peer group and recommendation of the Chairman, President and CEO.  The STIP does not specify any threshold or maximum payout amounts.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Annual Cash Incentive Bonus Awards" for additional information regarding the STIP awards.

(4) Column not applicable for 2020 as no awards were earned by Named Executive Officers pursuant to our STIP in 2020.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Annual Cash Incentive Bonus Awards" for additional information regarding the STIP awards.

(5) Grants of restricted units under our LTIP are generally not subject to minimum thresholds, targets or maximum payout conditions.  However, the vesting of these grants is subject to the satisfaction of certain performance criteria.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."

(6) These awards are grants of restricted units pursuant to our LTIP.  As discussed in footnote (3) to the Summary Compensation Table, the restricted units granted to Named Executive Officers on February 5, 2020 were modified on December 17, 2020, with the exception of the restricted units that were granted to Mr. Tholen on February 5, 2020, which were canceled on December 17, 2020 and replaced with a cash service award that is expected to vest on January 1, 2023.  This column includes the original awards granted on February 5, 2020 that will not vest or be received by the Named Executive Officers because they were modified or canceled in December 2020.  The grants of restricted units on December 17, 2020 include the modified February 5, 2020 awards, which are equal to the number of original

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awards granted on February 5, 2020 for those Named Executive Officers that received a grant, as well as additional restricted units that were granted to each Named Executive Officer. Messrs. Craft and Tholen were not granted restricted units on December 17, 2020. Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."

(7) These awards are phantom units added to each Named Executive Officer's SERP notional account balance.  Please see "Item 11.  Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan."

(8) We calculated the fair value of LTIP awards granted on February 5, 2020 to our Named Executive Officers using a value of $9.62 per unit, the closing unit price on the grant date.  We calculated the fair value of the LTIP awards modified and granted on December 17, 2020 using a value of $5.02 per unit, the closing unit price on that date.  We calculated the fair value of SERP phantom unit awards using the market closing price on the date the phantom unit award was granted.  Phantom units granted under the SERP vest on the date granted.

Narrative Disclosure Relating to the Summary Compensation Table and Grants of Plan-Based Awards Table

Annual Cash Incentive Bonus Awards

Under the STIP, our Named Executive Officers are eligible for cash awards for our achieving an annual financial performance target.  The annual performance target is recommended by the Chairman, President and CEO of our general partner and approved by the Compensation Committee, typically in January of each year.  The performance target historically has been EBITDA-based, with items added or removed from the EBITDA calculation to ensure that the performance target reflects the pure operating results of our core business.  (EBITDA is calculated as net income attributable to ARLP before net interest expense, income taxes and depreciation, depletion and amortization.)  The aggregate cash available for awards under the STIP each year is dependent on our actual financial results for the year compared to the annual performance target. The cash available generally increases in relationship to our EBITDA, as adjusted, exceeding the minimum financial performance target and is subject to adjustment by the Compensation Committee in its discretion.  The Compensation Committee maintains discretion to grant cash bonus awards outside of the STIP to address special situations.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Annual Cash Incentive Bonus Awards."

Long-Term Incentive Plan

Under the LTIP, grants may be made of either (a) restricted units, (b) options to purchase common units, although to date, no grants of options have been made, and (c) cash awards.  Annual grant levels for designated participants (including our Named Executive Officers) are recommended by our general partner's Chairman, President and CEO, subject to the review and approval of the Compensation Committee.  Restricted units granted under the LTIP are "phantom" or notional units that upon vesting entitle the participant to receive an ARLP unit.  Restricted units granted under the LTIP vest at the end of a stated period from the grant date (which is currently approximately three years for all outstanding restricted units), provided we achieve an aggregate performance target for that period.  The performance target is based on a normalized EBITDA measure, with that measure typically being similar to the STIP measure for the year of the grant.  The target, however, requires achieving an aggregate performance level for the three-year period.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to his or her percentage allocation multiplied by the sum of base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year.  A participant's cumulative notional phantom unit account balance earns the equivalent of common unit distributions.  The calculated distributions are added to the notional account balance in the form of additional phantom units.  All amounts granted under the SERP vest immediately and are paid out upon the participant's termination or death in ARLP common units equal to the number of phantom units then credited to the participant's account, subject to reduction of the number of units distributed to cover withholding obligations.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan."

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Salary and Bonus in Proportion to Total Compensation

The following table shows the total of salary and bonus in proportion to total compensation from the Summary Compensation Table:

						Salary and
						Bonus as a % of
		Salary and		Total		Total
Name	Year	Bonus ($) (1)		Compensation ($) (2)		Compensation (1)
Joseph W. Craft III	2020	$	1	$	1	100.0%
Brian L. Cantrell	2020		599,359		1,538,167	39.0%
R. Eberley Davis	2020		728,884		1,941,548	37.5%
Kirk D. Tholen	2020		1,000,000		2,784,543	35.9%
Thomas M. Wynne	2020		803,668		2,185,435	36.8%

(1) Percentages were calculated using the base salary and discretionary bonus of the Named Executive Officers.  The only discretionary bonus we provided in 2020 to our Named Executive Officers were to Mr. Tholen.  Incentive awards paid pursuant to our STIP are deemed to be performance-based non-equity incentive compensation awards and are not included within the discretionary bonus amounts.

(2) Total Compensation includes $409,822, $521,981, $862,779 and $603,944 for Messrs. Cantrell, Davis, Tholen and Wynne, respectively that reflect the grant date fair value of restricted units granted in February 2020 that were determined to be improbable of vesting under the original vesting requirements as discussed in footnote (3) to the Summary Compensation Table.

Outstanding Equity Awards at 2020 Fiscal Year End Table

		Equity
	Equity	Incentive Plan
	Incentive Plan	Awards:
	Awards:	Market or
	Number of	Payout Value
	Unearned	of Unearned
	Units or Other	Units or
	Rights That	Other Rights
	Have Not	That Have
Name	Vested (1)	Not Vested (2)
Joseph W. Craft III	—	$	—
Brian L. Cantrell	69,152		309,801
R. Eberley Davis	88,078		394,589
Kirk D. Tholen	—		—
Thomas M. Wynne	101,629		455,298

(1) Amounts represent restricted units awarded under the LTIP that were not vested as of December 31, 2020.  As a result of the cancellation of restricted units granted in 2019 and the cash settlement or cancellation of restricted units granted in 2018, the only restricted units that remain awarded under the LTIP at December 31, 2020 were the restricted units granted in 2020. Subject to our achieving financial performance targets, these units will vest on January 1, 2023.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."  All grants of restricted units under the LTIP include the contingent right to receive quarterly cash distributions in an amount equal to the cash distributions we make to unitholders during the vesting period.

(2) Stated values are based on $4.48 per unit, the closing price of our common units on December 31, 2020, the final market trading day of 2020.

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Units Vested Table for 2020

	Unit Awards
	Number of Units
	Acquired on Vesting	Value Realized on
Name	(1)	Vesting (1)
Joseph W. Craft III	—	$	—
Brian L. Cantrell	20,967		226,863
R. Eberley Davis	25,275		273,476
Kirk D. Tholen	—		—
Thomas M. Wynne	30,549		330,540

(1) Amounts represent the number and value of restricted units granted under the LTIP that vested in 2020 and entitled the participants to receive ARLP common units.  These units vested on January 1, 2020 and are valued at $10.82 per unit, the closing price on December 31, 2019, the final market trading day of 2019.  Amounts presented in this table do not reflect the cash settlement in December 2020 of restricted units that were granted in 2018.  The cash settlement of these units are included within the "All Other Compensation" column of the Summary Compensation Table for the 2020 year.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."

Nonqualified Deferred Compensation Table for 2020

	Executive		Registrant		Aggregate		Aggregate		Aggregate
	Contributions		Contributions		Earnings		Withdrawals		Balance
	in Last Fiscal		in Last Fiscal		in Last Fiscal		in Last Fiscal		at Last Fiscal
Name	Year ($) (1)		Year ($) (2)		Year ($) (3)		Year ($) (1)		Year End ($) (4)
Joseph W. Craft III	$	—	$	—	$	(1,647,672)	$	—	$	1,260,430
Brian L. Cantrell		—		40,056		(184,322)		—		181,059
R. Eberley Davis		—		74,180		(258,964)		—		272,285
Kirk D. Tholen		—		139,960		(28,144)		—		161,491
Thomas M. Wynne		—		70,744		(261,915)		—		271,103

(1) Column not applicable.

(2) Amounts represent awards of phantom units contributed to each Named Executive Officer's SERP notional account balance.  Please see "Item 11.  Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan." These amounts have also been included within the "All Other Compensation" column of the Summary Compensation Table for the 2020 year.

(3) Amounts represent earnings accrued during 2020 on each Named Executive Officer's SERP notional account balance for additional phantom units as a result of quarterly distributions on our common units and changes in the market value of the notional account balance. Earnings were not above-market or preferential.

(4) Amounts represent the Named Executive Officer's cumulative notional account balance of phantom units valued at $4.48, the closing price of our common units on December 31, 2020, the final market trading day of 2020.  The amounts include aggregate phantom unit quarterly distributions, changes in market value and the following aggregate amounts contributed since inception to each Named Executive Officer's SERP notional account balance including the amounts contributed in the last fiscal year shown in the table above: Mr. Craft, $670,927; Mr. Cantrell, $383,984; Mr. Davis, $608,198; Mr. Tholen; $189,635; and Mr. Wynne, $527,632.

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Narrative Discussion Relating to the Nonqualified Deferred Compensation Table for 2020

Supplemental Executive Retirement Plan

Under the terms of the SERP, participants are entitled to receive on December 31 of each year an allocation of phantom units having a fair market value equal to their percentage allocation multiplied by the sum of base salary and cash bonus received that year, then reduced by any supplemental contribution that was made to our defined contribution PSSP for the participant that year.  A participant's cumulative notional phantom unit account balance earns the equivalent of common unit distributions.  The calculated distributions are added to the notional account balance in the form of additional phantom units.  All amounts granted under the SERP vest immediately and are paid out upon the participant's termination or death in ARLP common units equal to the number of phantom units then credited to the participant's account, subject to reduction of the number of units distributed to cover withholding obligations.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan."

Potential Payments Upon a Termination or Change of Control

Each of our Named Executive Officers is eligible to receive accelerated vesting and payment under the LTIP and the SERP upon certain terminations of employment or upon our change in control.  Upon a "change of control," as defined in the LTIP, all awards outstanding under the LTIP will automatically vest and become payable or exercisable, as the case may be, in full.  In this regard, all restricted periods shall terminate and all performance criteria, if any, shall be deemed to have been achieved at the maximum level. The LTIP defines a "change in control" as one of the following events: (1) any sale, lease, exchange or other transfer of all or substantially all of our assets or Alliance Coal's assets to any person other than a person who is our affiliate; (2) the consolidation or merger of Alliance Coal with or into another person pursuant to a transaction in which the outstanding voting interests of Alliance Coal are changed into or exchanged for cash, securities or other property, other than any such transaction where (a) the outstanding voting interests of Alliance Coal are changed into or exchanged for voting stock or interests of the surviving corporation or its parent and (b) the holders of the voting interests of Alliance Coal immediately prior to such transaction own, directly or indirectly, not less than a majority of the voting stock or interests of the surviving corporation or its parent immediately after such transaction; or (3) a person or group being or becoming the beneficial owner of more than 50% of all voting interests of Alliance Coal then outstanding.

The amounts each of our Named Executive Officers could receive under the SERP have been previously disclosed in "Item 11. Nonqualified Deferred Compensation Table for 2020" and the amounts each of the Named Executive Officers could receive under the LTIP have been previously disclosed in "Item 11. Outstanding Equity Awards at 2020 Fiscal Year End Table", in each case assuming the triggering event occurred on December 31, 2020.  In addition, if a Named Executive Officer's employment were terminated as a result of one of certain enumerated events in the SERP, the Named Executive Officer would receive an amount based on an allocation for the year of termination.  Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Supplemental Executive Retirement Plan" for additional information regarding the enumerated events and allocation determination.  The exact amount that any Named Executive Officer would receive could only be determined with certainty upon an actual termination or change in control.

As noted above, the Tholen Employment Letter provides that if Mr. Tholen's employment is involuntarily terminated on or before December 31, 2022, other than for Good Cause (as defined in the Tholen Employment Letter), Mr. Tholen will receive a severance payment in an amount equal to two times Mr. Tholen's then-effective annual base salary plus his target STIP award, and any unpaid installment(s) of the one-time signing bonus described above, which as of December 31, 2020, would equal $3,000,000.

Director Compensation

The sole member of our general partner has the right to set the compensation of the directors of our general partner.  Typically, such compensation has been set by the Board of Directors upon recommendation of the Compensation Committee, and with the concurrence of Mr. Craft, who indirectly owns our general partner.  Mr. Craft and Mr. Wesley, our only employee directors, received no director compensation for 2020, and all compensation that Mr. Craft received in his capacity as an employee is set forth above within the Summary Compensation Table.  The directors of MGP devote 100% of their time as directors of MGP to the business of the ARLP Partnership.

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Director Compensation Table for 2020

									Change in Pension
							Non-Equity		Value and
	Fees earned		Unit		Option		Incentive Plan		Nonqualified Deferred		All Other
	or Paid in		Awards		Awards		Compensation		Compensation		Compensation
Name	Cash ($)		($) (2)(3)		($)(1)		($)(1)		Earnings ($)(1)		($)(1)		Total ($)
Robert J. Druten	$	176,000	$	4,006	$	—	$	—	$	—	$	—	$	180,006
John H. Robinson		176,000		—		—		—		—		—		176,000
Wilson M. Torrence		196,000		3,290		—		—		—		—		199,290
Nick Carter		166,000		—		—		—		—		—		166,000

(1) Columns are not applicable.

(2) Amounts represent the grant date fair value of equity awards in 2020 related to deferrals of distributions earned on deferred units (computed pursuant to FASB ASC 718, using the same assumptions as used for financial reporting purposes and which are more fully described in "Item 8. Financial Statements and Supplementary Data—Note 17 – Common Unit-Based Compensation Plans").  Please see Narrative to Director Compensation Table, below.

(3) At December 31, 2020, each director had the following number of "phantom" ARLP common units credited to his notional account under MGP's Amended and Restated Deferred Compensation Plan for Directors ("Directors' Deferred Compensation Plan"):

	Directors
	Deferred
	Compensation
Name	Plan (in Units)
Robert J. Druten	11,384
John H. Robinson	—
Wilson M. Torrence	9,344
Nick Carter	—

Narrative to Director Compensation Table

Compensation for our non-employee directors includes an annual cash retainer paid quarterly in advance on a pro rata basis.  The annual retainer for calendar year 2020 was $166,000. Mr. Torrence also was entitled to cash compensation of $30,000 for service as Chairman of the Audit Committee, and Mr. Robinson and Mr. Druten also were entitled to additional cash compensation of $10,000 each for service as Chairman of the Compensation Committee and the Conflicts Committee, respectively.  Directors have the option to defer all or part of their cash compensation pursuant to the Directors' Deferred Compensation Plan by completing an election form prior to the beginning of each calendar year.  No director elected to defer cash compensation in 2020.

Pursuant to the Directors' Deferred Compensation Plan, a notional account is established for deferred amounts of cash compensation and credited with notional common units of ARLP, described in the plan as "phantom" units.  The number of phantom units credited is determined by dividing the amount deferred by the average closing unit price for the ten trading days immediately preceding the deferral date.  When quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to the notional account as additional phantom units.  Payment of accounts under the Directors' Deferred Compensation Plan will be made in ARLP common units equal to the number of phantom units then credited to the director's account.

Directors may elect to receive payment of the account resulting from deferrals during a plan year either (a) on the January 1 on or next following their separation from service as a director or (b) on the earlier of a specified January 1 or the January 1 on or next following their separation from service.  The payment election must be made prior to each plan year; if no election is made, the account will be paid on the January 1 on or next following the director's separation from service.  The Directors' Deferred Compensation Plan is administered by the Compensation Committee, and the Board of Directors may change or terminate the plan at any time; provided, however, that accrued benefits under the plan cannot be impaired.

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Upon any recapitalization, reorganization, reclassification, split of common units, distribution or dividend of securities on ARLP common units, our consolidation or merger, or sale of all or substantially all of our assets or other similar transaction that is effected in such a way that holders of common units are entitled to receive (either directly or upon subsequent liquidation) cash, securities or assets with respect to or in exchange for ARLP common units, the Compensation Committee shall, in its sole discretion (and upon the advice of financial advisors as may be retained by the Compensation Committee), immediately adjust the notional balance of phantom units in each director's account under the Directors' Deferred Compensation Plan to equitably credit the fair value of the change in the ARLP common units and/or the distributions (of cash, securities or other assets) received or economic enhancement realized by the holders of the ARLP common units.

The Board of Directors has established a recommendation that each non-employee director should attain within five years following such person's election to the Board of Directors, and thereafter maintain during service on the Board of Directors, ownership of equity of ARLP (including phantom equity ownership under the Directors' Deferred Compensation Plan) with an aggregate value of $220,000.

CEO Pay Ratio Disclosures

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Joseph W. Craft III, our CEO.

For 2020, our last completed fiscal year:

● The median of the annual total compensation of all employees of our company (other than the CEO) was $72,549.

● The annual total compensation of our CEO, as reported in the Summary Compensation Table was $1.

● Based on this information, for 2020 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all employees was reasonably estimated to be 0.00001 to 1.

To determine the annual total compensation of our median employee and our CEO, we took the following steps:

● We determined that, as of December 31, 2020, our employee population consisted of approximately 2,924 individuals with the vast majority of these individuals located in the United States. This population consisted of our full-time and part-time employees, as we do not have seasonal workers.

● We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages reflected in our payroll records as reported to the Internal Revenue Service on Form W-2 for 2020.

● We identified our median employee by consistently applying this compensation measure to all of our employees included in our analysis.  Since the vast majority of our employees, including our CEO, are located in the United States, we did not make any cost of living adjustments in identifying the median employee.

● After we identified our median employee, we combined all of the elements of such employee's compensation for the 2020 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $72,549, comprised of such employee's W-2 compensation of $66,602 and contributions in the amount of $5,947 that we made on the employee's behalf to our 401(k) plan for the 2020 year.

● With respect to the annual total compensation of our CEO, we used the amount reported in the "Total" column of our 2020 Summary Compensation Table.

Compensation Committee Interlocks and Insider Participation

Mr. Craft, Chairman, President and CEO of our general partner, is also Chairman, President and CEO of AGP.  Otherwise, none of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of the Board of Directors or Compensation Committee of our general partner.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

The following table sets forth certain information as of February 10, 2021, regarding the beneficial ownership of common units held by (a) each director of our general partner, (b) each executive officer of our general partner identified in the Summary Compensation Table included in "Item 11. Executive Compensation" above, (c) all directors and executive officers as a group, and (d) each person known by our general partner to be the beneficial owner of 5% or more of our common units.  The address of our general partner and, unless otherwise indicated in the footnotes to the table below, each of the directors, executive officers and 5% unitholders reflected in the table below is 1717 South Boulder Avenue, Suite 400, Tulsa, Oklahoma 74119.  Unless otherwise indicated in the footnotes to the table below, the common units reflected as being beneficially owned by our general partner's directors and Named Executive Officers are held directly by such directors and officers.  The percentage of common units beneficially owned is based on 127,195,219 common units outstanding as of February 10, 2021.

		Percentage of Common
	Common Units	Units
Name of Beneficial Owner	Beneficially Owned	Beneficially Owned
Directors and Executive Officers
Joseph W. Craft III (1)	19,502,324	15.3%
Nick Carter	20,000	*
Robert J. Druten	25,628	*
John H. Robinson	18,462	*
Wilson M. Torrence	40,396	*
Charles R. Wesley III (2)	2,386,852	1.9%
Brian L. Cantrell	189,332	*
R. Eberley Davis	140,146	*
Robert J. Fouch	46,318	*
Robert G. Sachse	203,736	*
Kirk D. Tholen	—	*
Timothy J. Whelan	65,601	*
Thomas M. Wynne (3)	1,146,709	*
All directors and executive officers as a group (13 persons)	23,785,504	18.7%
5% Common Unit Holder
Kathleen S. Craft (4)	16,237,609	12.8%

* Less than one percent.

(1) The common units attributable to Mr. Craft consist of (i) 19,305,581 common units held directly by him, (ii) 168,602 common units attributable to Mr. Craft's spouse and (iii) 28,141 common units held by SGP (indirectly jointly owned by Mr. Craft and Kathleen S. Craft).  

(2) The common units attributable to Mr. Wesley consist of (i) 1,035,728 common units held directly by him and (ii) 1,351,124 common units held through trusts and other entities controlled by him.

(3) The common units attributable to Mr. Wynne consist of (i) 795,673 common units held directly by him and (ii) 351,036 common units held through a trust and another entity controlled by him.

(4) The common units attributable to Kathleen S. Craft consist of (i) 16,209,468 common units held directly by her and (ii) 28,141 common units held by SGP (indirectly jointly owned by Mr. Craft and Kathleen S. Craft).

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Equity Compensation Plan Information

	Number of units to be issued upon		Number of units remaining
	exercise/vesting of outstanding	Weighted-average exercise	available for future issuance
	options, warrants and rights	price of outstanding options,	under equity compensation
Plan Category	as of December 31, 2020	warrants and rights	plans as of December 31, 2020
Equity compensation plans approved by unitholders:
Long-Term Incentive Plan	1,430,489	N/A	1,726,471
Equity compensation plans not approved by unitholders:
Supplemental Executive Retirement Plan	739,902	N/A	N/A
Directors' Deferred Compensation	20,728	N/A	N/A

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In addition to the related-party transactions discussed in "Item 8. Financial Statements and Supplementary Data— Note 11 — Partners' Capital and Note 21 — Related-Party Transactions," ARLP has the following additional related-party transactions:

Certain Relationships

We are managed by MGP, which holds a non-economic general partner interest in us.  Prior to the Simplification Transactions discussed in "Item 8. Financial Statements and Supplementary Data—Note 1 — Organization and Presentation – Partnership Simplification," AHGP directly and indirectly through its wholly owned subsidiary, MGP II, LLC ("MGP II") owned approximately 66.7% of our total outstanding common units, and MGP was a wholly owned subsidiary of MGP II.  As a result of the Simplification Transactions, AHGP and MGP II became wholly owned subsidiaries of ARLP and MGP remained our sole general partner and became a wholly owned subsidiary of AGP, which is indirectly wholly owned by Mr. Craft.  MGP's ability, as general partner, to control us effectively gives MGP the ability to veto our actions and to control our management.  

Prior to the Simplification Transactions, certain of our officers and directors were also officers and/or directors of AHGP's general partner, AGP, including Mr. Craft, the Chairman, President and CEO of our general partner, Mr. Torrence, a Director, member of the Compensation Committee and Chairman of the Audit Committee of the MGP Board of Directors, Mr. Cantrell, the Senior Vice President and Chief Financial Officer of our general partner, Mr. Davis, the Senior Vice President, General Counsel and Secretary of our general partner, and Mr. Fouch, Vice President, Controller and Chief Accounting Officer of our general partner.  Following the Simplification Transactions, Messrs. Craft, Cantrell, Davis and Fouch continue to be officers of AGP, which is no longer the general partner of AHGP as a result of the Simplification Transactions.

Related-Party Transactions

The Board of Directors and its Conflicts Committee review our related-party transactions that involve a potential conflict of interest between MGP or any of its affiliates and ARLP or its subsidiaries or any other partner of ARLP to determine that such transactions reflect market-clearing terms and customary conditions.  As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below that had such potential conflict of interest as fair and reasonable to us and our limited partners.

Administrative Services

On April 1, 2010, effective January 1, 2010, ARLP entered into an Administrative Services Agreement with our general partner, our Intermediate Partnership, AGP, and Alliance Resource Holdings II, Inc. ("ARH II").  Under the Administrative Services Agreement, certain employees, including some executive officers, provided administrative services for AGP and ARH II and their respective affiliates.

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Our partnership agreement provides that MGP and its affiliates be reimbursed for all direct and indirect expenses incurred or payments made on behalf of us, including, but not limited to, director fees and expenses, management's salaries and related benefits (including incentive compensation), and accounting, budgeting, planning, treasury, public relations, land administration, environmental, permitting, payroll, benefits, disability, workers' compensation management, legal and information technology services.  MGP may determine in its sole discretion the expenses that are allocable to us.  Total costs billed to us by our general partner and its affiliates were approximately $0.7 million for the year ended December 31, 2020.  The executive officers of our general partner are employees of and paid by Alliance Coal, and the reimbursement we pay to our general partner pursuant to the partnership agreement does not include any compensation expenses associated with them.

JC Land

Our subsidiary, ASI, has a time-sharing agreement with Mr. Craft and Mr. Craft's affiliate, JC Land, LLC ("JC Land"), concerning their use of aircraft owned by Alliance Service, Inc. ("ASI") for purposes other than our business.  In accordance with the provisions of that agreement, Mr. Craft and JC Land paid ASI $0.04 million for the year ended December 31, 2020 for use of the aircraft.  In addition, Alliance Coal has a time-sharing agreement with JC Land concerning Alliance Coal's use of an airplane owned by JC Land.  In accordance with the provisions of that agreement, Alliance Coal paid JC Land $0.1 million for the year ended December 31, 2020 for use of the aircraft.

Effective August 1, 2013, Alliance Coal entered into an expense reimbursement agreement with JC Land regarding pilots hired by Alliance Coal to operate aircraft owned by ASI and JC Land.  In accordance with the expense reimbursement agreement, JC Land reimburses Alliance Coal for a portion of the compensation expense for its pilots.  JC Land paid us $0.3 million in 2020 pursuant to this agreement.  Separately, we billed JC Land $0.3 million during 2020 for fuel, maintenance, pilot travel, etc. paid by us on their behalf.

JC Resources

Effective March 2020, Alliance Royalty, LLC ("Alliance Royalty")  entered into an expense reimbursement agreement with Mr. Craft's affiliate, JC Resources LP ("JC Resources") regarding the salaries of the oil & gas technical personnel hired by Alliance Coal in 2020.  During 2020, Alliance Royalty was reimbursed $0.5 million by JC Resources.  We do not expect further reimbursement from JC Resources as the agreement was not extended into 2021.  

SGP Land/Craft Foundations

In 2001, SGP Land, LLC as successor in interest to an unaffiliated third party, entered into an amended mineral lease with MC Mining.  Under the terms of the lease, MC Mining was required to pay an annual minimum royalty of $0.3 million until $6.0 million of cumulative annual minimum and/or earned royalty payments had been paid. The cumulative annual minimum lease requirement of $6.0 million was met in 2015.  MC Mining paid no earned royalties in 2020 and paid $0.3 million and $0.1 million in 2019 and 2018 respectively.  As of January 1, 2019 the property subject to this lease is owned by the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation, an undivided one-half interest each (the "Craft Foundations").

SGP/Craft Foundations

Tunnel Ridge has a surface land lease with SGP with an annual payment of $0.2 million, payable in January of each year. As of January 1, 2019 the property subject to this lease is owned by the Craft Foundations, an undivided one-half interest each.

Omnibus Agreement

We are party to an omnibus agreement with Alliance Resource Holdings, Inc. ("ARH"), MGP and AGP, which govern potential competition among us and the other parties to this agreement.  Pursuant to the terms of the omnibus agreement, ARH and AGP agreed, and caused their controlled affiliates to agree, for so long as management controls MGP, not to engage in the business of mining, marketing or transporting coal in the United States, unless it first offers us the opportunity to engage in a potential activity or acquire a potential business, and the Board of Directors, with the concurrence of its Conflicts Committee, elects to cause us not to pursue such opportunity or acquisition. In addition, ARH has the ability to purchase businesses, the majority value of which is not mining, marketing or transporting coal, provided ARH offers us

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the opportunity to purchase the coal assets following their acquisition.  The restriction does not apply to the assets retained and business conducted by ARH at the closing of our initial public offering.  Except as provided above, ARH and AGP and their controlled affiliates are prohibited from engaging in activities wherein they compete directly with us.  In addition to its non-competition provisions, the agreement also provides for indemnification of us against liabilities associated with certain assets and businesses of ARH that were disposed of or liquidated prior to consummating our initial public offering.  

Director Independence

As a publicly traded limited partnership listed on the NASDAQ Global Select Market, we are required to maintain a sufficient number of independent directors on the board of our general partner to satisfy the audit committee requirement set forth in NASDAQ Rule 4350(d)(2).  Rule 4350(d)(2) requires us to maintain an audit committee of at least three members, each of whom must, among other requirements, be independent as defined under NASDAQ Rule 4200(a)(15) and meet the criteria for independence set forth in Rule 10A-3(b)(1) under the Exchange Act (subject to the exemptions provided in Rule 10A-3(c)).

All members and former members of the Audit Committee—Messrs. Torrence, Carter, Druten and Robinson—and all members and former members of the Compensation Committee—Messrs. Robinson, Carter, Druten and Torrence—are independent directors as defined under applicable NASDAQ and Exchange Act rules.  Please see "Item 10.  Directors, Executive Officers and Corporate Governance of the General Partner—Audit Committee" and "Item 11.  Executive Compensation—Compensation Discussion and Analysis."

ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES

The firm of Ernst & Young LLP is our independent registered public accounting firm.  The following table sets forth fees paid to Ernst & Young LLP during the years ended December 31, 2020 and 2019:

	2020		2019
	(in thousands)
Audit Fees (1)	$	1,349	$	1,175
Audit-related fees (2)		—		—
Tax fees (3)		339		398
All other fees		—		—
Total	$	1,688	$	1,573

(1) Audit fees consist primarily of the audit and quarterly reviews of the consolidated financial statements, but can also be related to statutory audits of subsidiaries required by governmental or regulatory bodies, attestation services required by statute or regulation, comfort letters, consents, assistance with and review of documents filed with the SEC, work performed by tax professionals in connection with the audit and quarterly reviews, and accounting and financial reporting consultations and research work necessary to comply with GAAP.

(2) Audit-related fees include fees related to acquisition due diligence and accounting consultations.

(3) Tax fees consist primarily of services rendered for tax compliance, tax advice, and tax planning.

The charter of the Audit Committee provides that the committee is responsible for the pre-approval of all auditing services and permitted non-audit services to be performed for us by our independent registered public accounting firm, subject to the requirements of applicable law.  In accordance with such charter, the Audit Committee may delegate the authority to grant such pre-approvals to the Audit Committee chairman or a sub-committee of the Audit Committee, which pre-approvals are then reviewed by the full Audit Committee at its next regular meeting.  Typically, however, the Audit Committee itself reviews the matters to be approved.  The Audit Committee periodically monitors the services rendered by and actual fees paid to the independent registered public accounting firm to ensure that such services are within the parameters approved by the Audit Committee.

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PART IV

ITEM 15.            EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) (1) Financial Statements and Supplementary Data.

	Page
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

(a)(2)Financial Statement Schedule.

Schedule I – Condensed Financial Information of Registrant 135

All other schedules are omitted because they are not applicable or the information is shown in the financial statements or notes thereto.

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(a)(3) and (c)          The exhibits listed below are filed as part of this annual report.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
2.1	Simplification Agreement, dated as of February 22, 2018, by and among Alliance Holdings GP, L.P., Alliance GP, LLC, Wildcat GP Merger Sub, LLC, MGP II, LLC, ARM GP Holdings, Inc., New AHGP GP, LLC, Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC and Alliance Resource GP, LLC.	8-K	000-26823 18634680	2.1	02/23/2018
3.1	Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.	8-K	000-26823 17990766	3.2	07/28/2017
3.2	Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P.	10-K	000-26823 583595	3.2	03/29/2000
3.3	Amended and Restated Certificate of Limited Partnership of Alliance Resource Partners, L.P.	8-K	000-26823 17990766	3.6	07/28/2017
3.4	Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P.	S-1/A	333-78845 99669102	3.8	07/23/1999
3.5	Certificate of Formation of Alliance Resource Management GP, LLC	S-1/A	333-78845 99669102	3.7	07/23/1999
3.6	Amendment No. 1 to the Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.	10-K	000-26823 18634680	3.9	02/23/2018
3.7	Amendment No. 2 to Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., dated as of May 31, 2018.	8-K	000-26823 1883834	3.3	06/06/2018
3.8	Amendment No. 3 to Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., dated as of June 1, 2018.	8-K	000-26823 1883834	3.4	06/06/2018
3.9	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P., dated as of May 31, 2018.	8-K	000-26823 1883834	3.5	06/06/2018
3.10	Third Amended and Restated Operating Agreement of Alliance Resource Management GP, LLC, dated as of May 31, 2018.	8-K	000-26823 1883834	3.7	06/06/2018

167

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
4.1	Form of Common Unit Certificate (Included as Exhibit A to the Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P., included in this Exhibit Index as Exhibit 3.1).	8-K	000-26823 17990766	3.2	07/28/2017
4.2	Indenture, dated as of April 24, 2017, by and among Alliance Resource Operating Partners, L.P. and Alliance Resource Finance Corporation, as issuers, Alliance Resource Partners, L.P., as parent, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee.	8-K	000-26823 17798539	4.1	04/24/2017
4.3	Form of 7.500% Senior Note due 2025 (included in Exhibit 4.2).	8-K	000-26823 17778550	4.1	04/24/2017
4.4	Description of the Registrant’s Securities registered under Section 12 of the Securities Exchange Act of 1934.					þ
10.1	Note Purchase Agreement, dated as of August 16, 1999, among Alliance Resource GP, LLC and the purchasers named therein.	10-K	000-26823 583595	10.2	03/29/2000
10.2	Amendment and Restatement of Letter of Credit Facility Agreement dated October 2, 2010.	10-Q	000-26823 11823116	10.1	05/09/2011
10.3	Letter of Credit Facility Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association.	10-Q	000-26823 1782487	10.25	11/13/2001
10.4	First Amendment to the Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association.	10-Q	000-26823 02827517	10.32	11/14/2002
10.5	Promissory Note Agreement dated as of October 2, 2001, between Alliance Resource Partners, L.P. and Bank of the Lakes, N.A.	10-Q	000-26823 1782487	10.26	11/13/2001
10.6	Guarantee Agreement, dated as of October 2, 2001, between Alliance Resource GP, LLC and Bank of the Lakes, N.A.	10-Q	000-26823 1782487	10.27	11/13/2001
10.7	Contribution and Assumption Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource Operating Partners, L.P. and the other parties named therein	10-K	000-26823 583595	10.3	03/29/2000

168

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
10.8	Omnibus Agreement, dated August 16, 1999, among Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC and Alliance Resource Partners, L.P.	10-K	000-26823 583595	10.4	03/29/2000
10.9(1)	Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan	10-K	000-26823 04667577	10.17	03/15/2004
10.10(1)	First Amendment to the Alliance Coal, LLC 2000 Long-Term Incentive Plan	10-K	000-26823 04667577	10.18	03/15/2004
10.11(1)	Alliance Coal, LLC Short-Term Incentive Plan	10-K	000-26823 583595	10.12	03/29/2000
10.12(1)	Alliance Coal, LLC Supplemental Executive Retirement Plan	S-8	333-85258 02595143	99.2	04/01/2002
10.13(1)	Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors	S-8	333-85258 02595143	99.3	04/01/2002
10.14	Guaranty by Alliance Resource Partners, L.P. dated March 16, 2012	10-Q	000-26823 12825281	10.3	05/09/2012
10.15(2)	Base Contract for Purchase and Sale of Coal, dated March 16, 2012, between Seminole Electric Cooperative, Inc. and Alliance Coal, LLC	10-Q	000-26823 12825281	10.1	05/09/2012
10.16(2)	Contract of Confirmation, effective March 16, 2012, between Seminole Electric Cooperative, Inc., Alliance Coal, LLC and Alliance Resource Partners, L.P.	10-Q/A	000-26823 12947715	10.2	07/05/2012
10.17	Amended and Restated Charter for the Audit Committee of the Board of Directors dated February 23, 2009	10-K	000-26823 09647063	10.35	03/02/2009
10.18	Second Amendment to the Omnibus Agreement dated May 15, 2006 by and among Alliance Resource Partners, L.P., Alliance Resource GP, LLC, Alliance Resource Management GP, LLC, Alliance Resource Holdings, Inc., Alliance Resource Holdings II, Inc., AMH-II, LLC, Alliance Holdings GP, L.P., Alliance GP, LLC and Alliance Management Holdings, LLC	10-Q	000-26823 061017824	10.1	08/09/2006
10.19	Administrative Services Agreement dated May 15, 2006 among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc., Alliance Holdings GP, L.P. and Alliance GP, LLC	10-Q	000-26823 061017824	10.2	08/09/2006

169

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
10.20(1)	First Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan	10-K	000-26823 07660999	10.50	03/01/2007
10.21(1)	Second Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan	10-K	000-26823 08654096	10.50	02/29/2008
10.22(1)	First Amendment to the Alliance Coal, LLC Short-Term Incentive Plan	10-K	000-26823 07660999	10.52	03/01/2007
10.23(1)	Second Amendment to the Alliance Coal, LLC Short-Term Incentive Plan	10-K	000-26823 08654096	10.53	02/29/2008
10.24	Note Purchase Agreement, 6.28% Senior Notes Due June 26, 2015, and 6.72% Senior Notes due June 26, 2018, dated as of June 26, 2008, by and among Alliance Resource Operating Partners, L.P. and various investors	8-K	000-26823 08928968	10.1	07/01/2008
10.25	First Amendment, dated as of June 26, 2008, to the Note Purchase Agreement, dated August 16, 1999, 8.31% Senior Notes due August 20, 2014, by and among Alliance Resource Operating Partners, L.P. (as successor to Alliance Resource GP, LLC) and various investors	8-K	000-26823 08928968	10.2	07/01/2008
10.26(1)	Third Amendment to the Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan	10-K	000-26823 09647063	10.52	03/02/2009
10.27(1)	Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan dated as of January 1, 2011	10-K	000-26823 11645603	10.40	02/28/2011
10.28(1)	Amended and Restated Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors dated as of January 1, 2011	10-K	000-26823 11645603	10.42	02/28/2011
10.29	Amendment No. 2 to Letter of Credit Facility Agreement between Alliance Resource Partners, L.P. and Bank of the Lakes, National Association, dated April 13, 2009	10-Q	000-26823 09811514	10.1	05/08/2009
10.30(2)	Agreement for the Supply of Coal, dated August 20, 2009 between Tennessee Valley Authority and Alliance Coal, LLC	10-Q	000-26823 091164883	10.2	11/06/2009
10.31	Amended and Restated Charter for the Compensation Committee of the Board of Directors dated February 23, 2010.	10-K	000-26823 10638795	10.49	02/26/2010

170

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
10.32	Amended and Restated Administrative Services Agreement effective January 1, 2010, among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc., Alliance Resource Operating Partners, L.P., Alliance Holdings GP, L.P. and Alliance GP, LLC.	10-Q	000-26823 101000555	10.1	08/09/2010
10.33	Uncommitted Line of Credit and Reimbursement Agreement dated April 9, 2010 between Alliance Resource Partners, L.P. and Fifth Third Bank.	10-Q	000-26823 101000555	10.2	08/09/2010
10.34	Purchase and Sale Agreement, dated as of December 5, 2014, among Alliance Resource Operating Partners, L.P., as buyer and Alliance Coal, LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon Transfer Terminal, LLC, River View Coal, LLC, Sebree Mining, LLC, Tunnel Ridge, LLC and White County Coal, LLC, as originators	8-K	000-26823 141277053	10.1	12/10/2014
10.35	Sale and Contribution Agreement, dated as of December 5, 2014, among Alliance Resource Operating Partners, L.P., as seller and AROP Funding, LLC, as buyer	8-K	000-26823 141277053	10.2	12/10/2014
10.36	Receivables Financing Agreement, dated as of December 5, 2014, among Borrower, PNC Bank, National Association, as administrative agent as well as the letter of credit bank, the persons from time to time party thereto as lenders, the persons from time to time party thereto as letter of credit participants, and Alliance Coal, LLC, as initial servicer	8-K	000-26823 141277053	10.3	12/10/2014
10.37	Performance Guaranty, dated as of December 5, 2014, by AROP in favor of PNC Bank, National Association, as administrative agent	8-K	000-26823 141277053	10.4	12/10/2014
10.38	Master Lease Agreement, dated as of October 29, 2015, between Alliance Resource Operating Partners, L.P., Hamilton County Coal, LLC and White Oak Resources LLC, as lessees, and PNC Equipment Finance, LLC and the other lessors named therein.	8-K	000-26823 151198024	10.1	11/04/2015
10.39(1)	The Amended and Restated Alliance Coal, LLC Long-Term Incentive Plan as amended by the Third Amendment and Fourth Amendment	10-K	000-26823 161460619	10.46	02/26/2016
10.40	First Amendment to the Receivables Financing Agreement, dated as of December 4, 2015	10-Q	000-26823 161634229	10.1	05/10/2016

171

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
10.41	Second Amendment to the Receivables Financing Agreement, dated as of February 24, 2016	10-Q	000-26823 161634229	10.2	05/10/2016
10.42	Joinder Agreement, dated as of February 24, 2016, among Warrior Coal, LLC, Webster County Coal, LLC, White Oak Resources LLC and Hamilton County Coal, LLC, dated as of February 24, 2016	10-Q	000-26823 161634229	10.3	05/10/2016
10.43	Fourth Amended and Restated Credit Agreement, dated as of January 27, 2017, by and among Alliance Resource Operating Partners, L.P., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto.	8-K	000-26823 17567534	10.1	02/02/2017
10.44	First Amendment to Note Purchase Agreement, dated as of January 27, 2017, by and among Alliance Resource Operating Partners, L.P. and the subsidiary guarantors and various investors named therein.	8-K	000-26823 17567534	10.2	02/02/2017
10.45	Third Amendment to the Receivables Financing Agreement, dated as of December 2, 2016	10-K	000-26823 17636362	10.45	02/24/2017
10.46	Amendment No. 1 dated April 3, 2017 to the Fourth Amended and Restated Credit Agreement, dated as of January 27, 2017, by and among Alliance Resource Operating Partners, L.P., as borrower, the initial lenders, initial issuing banks and swingline bank named therein, JPMorgan Chase Bank, N.A., as administrative agent, JPMorgan Chase Bank, N.A., Wells Fargo Securities, LLC and Citigroup Global Markets Inc. as joint lead arrangers, JPMorgan Chase Bank, N.A., Wells Fargo Securities, LLC, Citigroup Global Markets Inc., and BOKF, NA DBA Bank of Oklahoma as joint bookrunners, Wells Fargo Bank, National Association, Citibank, N.A., and BOKF, NA DBA Bank of Oklahoma as syndication agents, and the other institutions named therein as documentation agents.	8-K	000-26823 17750742	10.1	04/07/2017
10.47	Fourth Amendment to the Receivables Financing Agreement, dated as of November 27, 2017	10-K	000-26823 18634680	10.47	02/23/2018
10.48	Fifth Amendment to the Receivables Financing Agreement, dated as of January 17, 2018	10-K	000-26823 18634680	10.48	02/23/2018

172

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date	Filed Herewith*
10.49	Contribution Agreement, dated as of July 28, 2017, by and among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC, ARM GP Holdings, Inc., MGP II, LLC and Alliance Holdings GP, L.P.	8-K	000-26823 17990766	10.1	07/28/2017
10.50	First Amendment to Contribution Agreement, dated as of May 31, 2018, by and among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC, ARM GP Holdings, Inc., MGP II, LLC and Alliance Holdings GP, L.P.	8-K	000-26823 18883834	10.1	06/06/2018
10.51	Sixth Amendment to the Receivables Financing Agreement, dated as of June 19, 2018	10-Q	000-26823 18994075	10.2	08/06/2018
10.52	Seventh Amendment to the Receivables Financing Agreement, dated as of January 16, 2019	10-K	000-26823 19624803	10.52	02/22/2019
10.53	Subscription Agreement for Partnership Interest - General Partner Interest dated December 14, 2018 by and among Alliance Resource Partners, L.P., AllDale Minerals, LP and AllDale Mineral Management, LLC.	10-K	000-26823 19624803	10.53	02/22/2019
10.54	Subscription Agreement for Partnership Interest - Limited Partner Interest dated December 14, 2018 by and among Alliance Resource Partners, L.P., AllDale Minerals, LP and AllDale Mineral Management, LLC.	10-K	000-26823 19624803	10.54	02/22/2019
10.55	Subscription Agreement for Partnership Interest - General Partner Interest dated December 14, 2018 by and among Alliance Resource Partners, L.P., AllDale Minerals II, LP and AllDale Mineral Management II, LLC.	10-K	000-26823 19624803	10.55	02/22/2019
10.56	Subscription Agreement for Partnership Interest - Limited Partner Interest dated December 14, 2018 by and among Alliance Resource Partners, L.P., AllDale Minerals II, LP and AllDale Mineral Management II, LLC.	10-K	000-26823 19624803	10.56	02/22/2019
10.57	AllDale Minerals, LP Joinder Agreements dated January 3, 2019 by and among Alliance Royalty, LLC, AllRoy GP, LLC and AllDale Minerals, LP.	10-K	000-26823 19624803	10.57	02/22/2019

173

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date		Filed Herewith*
10.58	AllDale Minerals II, LP Joinder Agreements dated January 3, 2019 by and among Alliance Royalty, LLC, AllRoy GP, LLC and AllDale Minerals II, LP.	10-K	000-26823 19624803	10.58	02/22/2019
10.59	Purchase and Sale Agreement by and between Wing Resources LLC, and Wing Resources II LLC, as sellers, and Alliance Resource Partners, L.P., as buyer, dated as of June 21, 2019.	10-Q	000-26823 19997858	10.1	08/05/2019
10.60	Eighth Amendment to the Receivables Financing Agreement, dated as of October 22, 2019.	10-Q	000-26823 191192460	10.2	11/05/2019
10.61	Employment letter to Kirk Tholen, dated October 21, 2019.	10-K	000-26823 20636450	10.61	02/20/2020
10.62	Fifth Amended and Restated Credit Agreement, dated as of March 9, 2020, by and among Alliance Resource Operating Partners, L.P., as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto.	8-K	000-26823 20711345	10.1	03/13/2020
10.63	Fifth Amendment to the Alliance Coal and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan.	8-K	000-26823 201385345	10.1	12/14/2020
10.64	Ninth Amendment to the Receivables Financing Agreement, dated as of January 15, 2021.					þ
14.1	Code of Ethics for Principal Executive Officer and Senior Financial Officers	10-K	000-26823 13656028	14.1	03/01/2013
21.1	List of Subsidiaries.					þ
23.1	Consent of Ernst & Young LLP.					þ
23.2	Consent of Netherland, Sewell & Associates, Inc.					þ
31.1	Certification of Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the general partner of Alliance Resource Partners, L.P., dated February 23, 2021, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					þ
31.2	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the general partner of Alliance Resource Partners, L.P., dated February 23, 2021, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					þ

174

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File No. and Film No.	Exhibit	Filing Date		Filed Herewith*
32.1	Certification of Joseph W. Craft III, President and Chief Executive Officer and Chairman of Alliance Resource Management GP, LLC, the general partner of Alliance Resource Partners, L.P., dated February 23, 2021, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					☑
32.2	Certification of Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the general partner of Alliance Resource Partners, L.P., dated February 23, 2021, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					☑
95.1	Federal Mine Safety and Health Act Information					☑
99.1	Report of Netherland, Sewell & Associates, Inc., dated January 14, 2021					☑
101	Interactive Data File (Form 10-K for the year ended December 31, 2020 filed in Inline XBRL).					☑
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).					☑

* Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).

(1) Denotes management contract or compensatory plan or arrangement.

(2) Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 of the Exchange Act, as amended, and the omitted material has been separately filed with the SEC.

175

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on February 23, 2021.

	ALLIANCE RESOURCE PARTNERS, L.P.
By:		Alliance Resource Management GP, LLC
		its general partner
	/s/ Joseph W. Craft III
	Joseph W. Craft III
	President, Chief Executive
	Officer and Chairman

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Joseph W. Craft III	President, Chief Executive Officer, and Chairman (Principal Executive Officer)	February 23, 2021
Joseph W. Craft III
/s/ Brian L. Cantrell	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 23, 2021
Brian L. Cantrell
/s/ Robert J. Fouch	Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)	February 23, 2021
Robert J. Fouch
/s/ Nick Carter	Director	February 23, 2021
Nick Carter
/s/ Robert J. Druten	Director	February 23, 2021
Robert J. Druten
/s/ John H. Robinson	Director	February 23, 2021
John H. Robinson
/s/ Wilson M. Torrence	Director	February 23, 2021
Wilson M. Torrence
/s/ Charles R. Wesley	Executive Vice President and Director	February 23, 2021
Charles R. Wesley

176

EX-4.4

Exhibit 4.4

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

For purposes of this Exhibit 4.4, references to “the Partnership,” “we,” “our” and “us” refer only to Alliance Resource Partners, L.P., a Delaware limited partnership (“ARLP”) and not to its subsidiaries or parent.  

Common Units

Our common units represent limited partner interests in ARLP. The holders of these common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under the Fourth Amended and Restated Agreement of Limited Partnership of ARLP, as amended (the “Partnership Agreement”). For a description of the rights of holders of common units in and to partnership distributions, please read “Cash Distribution Policy.” For a description of other rights and privileges of limited partners under our Partnership Agreement, including voting rights, please read “Description of Our Partnership Agreement.”

Exchange Listing

Our common units trade on the NASDAQ Global Select Market under the symbol “ARLP.”

Transfer Agent and Registrar Duties

American Stock Transfer & Trust Company serves as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:

● surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

● special charges for services requested by a holder of a common unit; and

● other similar fees or charges.

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities as transfer agent, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Transfer of Common Units

Any transfer of common units will not be recorded by the transfer agent or recognized by us until either (i) the certificates evidencing the common units being transferred are surrendered for registration of transfer or (ii) the receipt of proper instructions from the registered owner of uncertificated common units. Upon satisfaction of the requirements in our Partnership Agreement with respect to a transfer, the transferee of common units:

● becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

● automatically requests admission as a substituted limited partner in our partnership;

● agrees to be bound by the terms and conditions of, and executes, our Partnership Agreement;

● represents that the transferee has the capacity, power and authority to enter into the Partnership Agreement;

● grants powers of attorney to officers of our general partner and any liquidator of us as specified in the Partnership Agreement; and

● makes the consents and waivers contained in the Partnership Agreement.

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. The general partner may withhold its consent in its sole discretion.

A transferee’s broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon admission as a substituted limited partner in our partnership for the transferred common units, a purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:

● the right to assign the common unit to a purchaser or other transferee; and

● the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units. Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:

● will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

● may not receive some federal income tax information or reports furnished to record holders of common units.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

General. Available cash with respect to each quarter may, at the discretion of the general partner, be (i) distributed in respect of repurchases of the common units or (ii) distributed to the limited partners as of a record date selected by the general partner in accordance with each limited partner’s percentage interest. Any distribution pursuant to clause (ii) will be made within 45 days following the end of the applicable quarter.

Definition of Available Cash. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:

● provide for the proper conduct of our business;

● comply with applicable law or any partnership debt instrument or other agreement; or

● provide funds for distributions to unitholders in respect of any one or more of the next four quarters.

General Partner Interest

The general partner owns a non-economic general partner interest in ARLP.

Effect of Issuance of Additional Units

We can issue additional common units or other equity securities for consideration and under terms and conditions approved by our general partner in its sole discretion and without the approval of our unitholders. We may fund acquisitions through the issuance of additional common units or other equity securities.

Holders of any additional common units that we issue will be entitled to share equally with our then-existing unitholders in distributions of available cash. In addition, the issuance of additional interests may dilute the value of the interests of the then-existing unitholders.

Distribution of Cash Upon Liquidation

General. If we dissolve and liquidate, we will sell our assets or otherwise dispose of our assets and we will adjust the partners’ capital account balances to show any resulting gain or loss. We will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in our Partnership Agreement and by law and, thereafter, distribute to the unitholders in accordance with their adjusted capital account balances.

Manner of Adjustment. If we liquidate, we would allocate any loss to the general partner and each unitholder as follows:

● First, to the unitholders, in accordance with their percentage interests, until the capital accounts of the unitholders have been reduced to zero; and

● Thereafter, 100% to the general partner.

Interim Adjustments to Capital Accounts. If we issue additional security interests or make distributions of property, we will make interim adjustments to capital accounts. These adjustments would be based on the fair market value of the interests or the property distributed and any gain or loss would be allocated to the unitholders and the general partner in the same way that a gain or loss is allocated upon liquidation.

DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

The following is a summary of certain material provisions of our Partnership Agreement that relate to ownership of our common units.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the common unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of outstanding common units.

In voting their common units, the general partner and its affiliates have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners.

Issuance of additional units	No approval right.
Amendment of our Partnership Agreement	Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”
Merger of the Partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances. Please read “—Merger, Sale or Other Disposition of Assets.”
Dissolution of the Partnership	Unit majority. Please read “—Termination and Dissolution.”
Continuation of our business upon dissolution	Unit majority. Please read “—Termination and Dissolution.”
Withdrawal of the general partner	No approval right. Please read “—Withdrawal or Removal of the General Partner.”
Removal of the general partner	Not less than 66.7% of the outstanding units, voting as a single class, including units held by the general partner and its affiliates. Please read “—Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest	No approval right.
Transfer of ownership interests in the general partner	No approval right.

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

Applicable Law

Our Partnership Agreement is governed by Delaware law, without regard to its principles of conflicts of law.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and otherwise acts in conformity with the provisions of our Partnership Agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:

● to remove or replace the general partner;

● to approve some amendments to our Partnership Agreement; or

● to take other action under our Partnership Agreement  

constituted “participation in control” of our business for purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the Partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the Partnership, except the assignee is not obligated for liabilities unknown to it at the time it became a limited partner and which could not be ascertained from our Partnership Agreement.

Issuance of Additional Securities

Our Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other securities for the consideration and on the terms and conditions established by the general partner in its sole discretion without the approval of any limited partners.

It is possible that we will fund acquisitions through the issuance of additional common units or other securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. See “Cash Distribution Policy” above. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our Partnership Agreement, we may also issue additional securities that, in the sole discretion of the general partner, may have special voting rights to which the common units are not entitled.

Amendment of Our Partnership Agreement

General. Amendments to our Partnership Agreement may be proposed only by or with the consent of the general partner which consent may be given or withheld in its sole discretion. A proposed amendment shall be effective upon approval by the holders of a unit majority, unless a greater or different percentage is required under our Partnership Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of outstanding common units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the general partner shall seek the written approval of the requisite percentage of common units or call a meeting of the unitholders to consider and vote on such proposed amendment. The general partner shall notify all record holders upon final adoption of any such proposed amendments.

Prohibited Amendments. No amendment may be made that would:

● enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected

● enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by the Partnership to the general partner or any of its affiliates without its consent, which may be given or withheld in its sole discretion;

● change the term of the Partnership;

● provide that the Partnership is not dissolved upon the expiration of its term or upon an election to dissolve the Partnership by the general partner that is approved by the holders of a majority of the outstanding common units; or

● give any person the right to dissolve the Partnership other than the general partner’s right to dissolve the Partnership with the approval of the holders of a majority of the outstanding common units.

The provision of our Partnership Agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding common units.

No Unitholder Approval. The general partner may generally make amendments to our Partnership Agreement without the approval of any limited partner or assignee to reflect:

● a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent or the registered office of the Partnership;

● the admission, substitution, withdrawal or removal of partners in accordance with our Partnership Agreement;

● a change that, in the sole discretion of the general partner, is necessary or advisable to qualify or continue the qualification of the Partnership as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the Partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

● an amendment that is necessary, in the opinion of counsel, to prevent the Partnership or the general partner or their directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

● an amendment that in the discretion of the general partner is necessary or advisable for the authorization or issuance of any class or series of securities;

● any amendment expressly permitted in our Partnership Agreement to be made by the general partner acting alone;

● an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our Partnership Agreement;

● any amendment that, in the discretion of the general partner, is necessary or advisable for the formation by the Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our Partnership Agreement;

● a change in the fiscal year or taxable year of the Partnership and related changes; and

● any other amendments substantially similar to any of the matters described in above.

In addition, the general partner may make amendments to our Partnership Agreement without the approval of any limited partner or assignee if those amendments, in the discretion of the general partner:

● do not adversely affect the limited partners in any material respect;

● are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

● are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which the general partner deems to be in the best interests of the Partnership and the limited partners;

● are necessary or advisable for any action taken by the general partner relating to splits or combinations of units under the provisions of our Partnership Agreement; or

● are required to effect the intent of the provisions of our Partnership Agreement or are otherwise contemplated by our Partnership Agreement.

Opinion of Counsel. No amendments, except those under “­—No Unitholder Approval” shall become effective without the approval of the holders of at least 90% of the then outstanding common units, unless the Partnership obtains an opinion of counsel to the effect that such amendment will not affect the limited liability of any limited partner under applicable law.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require approval by the holders of a majority of the outstanding common units of the class affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of us requires the prior consent of our general partner. However, our general partner has no duty or obligation to consent to any merger or consolidation and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

The general partner is generally prohibited, without the prior approval of holders of a majority of the outstanding common units, from causing the Partnership to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination; provided that the general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without that approval. The general partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in our Partnership Agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The limited partners are not entitled to dissenters’ rights of appraisal under our Partnership Agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets, or any other transaction or event.

Termination and Dissolution

We will continue until close of Partnership business on December 31, 2098, unless terminated sooner under our Partnership Agreement. We will dissolve upon:

● the election of the general partner to dissolve us, if approved by the holders of a majority of the outstanding common units;

● the withdrawal or removal of the general partner or any other event that results in its ceasing to be the general partner other than by reason of a transfer of its general partner interest in accordance with our Partnership Agreement or withdrawal or removal following approval and admission of a successor;

● the entry of a decree of judicial dissolution of the Partnership; or

● the sale of all or substantially all of the assets and properties of the Partnership.

Upon a dissolution under the second bullet point above, the holders of a majority of the outstanding common units may also elect, within specific time limitations, to reconstitute the Partnership and continue its business on the same terms and conditions described in our Partnership Agreement by forming a new limited partnership on terms identical to those in our Partnership Agreement and having as a successor general partner an entity approved by the holders of units representing a unit majority, subject to receipt by the Partnership of an opinion of counsel to the effect that:

● the action would not result in the loss of limited liability of any limited partner; and

● neither the Partnership, the reconstituted limited partnership, Alliance Resource Operating Partners, L.P., nor Alliance Coal, LLC would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of the general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets and apply the proceeds of the liquidation as provided in “Cash Distribution Policy—Distribution of Cash Upon Liquidation.” The liquidator may, in its absolute discretion, defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

Withdrawal or Removal of the General Partner

The general partner may withdraw as the general partner without first obtaining approval from any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our Partnership Agreement. In addition, our Partnership Agreement permits the general partner in some instances to sell or otherwise transfer all of its general partner interests in the Partnership without the approval of the unitholders.

Upon the withdrawal of the general partner under any circumstances, other than as a result of a transfer by the general partner of all or a part of its general partner interests in the Partnership, the holders of a majority of the outstanding common units may, prior to the effective date, select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, the Partnership will be dissolved, wound up and liquidated, unless within 180 days after that withdrawal the holders of a majority of the outstanding common units agree in writing to continue the business of the Partnership and to appoint a successor general partner. See “—Termination and Dissolution” above.

The general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66.7% of the outstanding units, including units held by the general partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units.

Withdrawal of Limited Partners

No limited partner has any right to withdraw from the Partnership, except that when a transferee of a limited partner’s limited partner interest becomes a record holder of the limited partner interest so transferred, such transferring limited partner will cease to be a limited partner with respect to the limited partner interest so transferred

Change of Management Provisions

Our Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Alliance Resource Management GP, LLC as our general partner or otherwise change management. If any person or group other than the general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner. Please read “—Voting Rights.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ notice. The purchase price in the event of this purchase is the greater of:

● the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

● the average of the daily closing prices of the Partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a common unitholder may anticipate the market price to be in the future.  

Status as Limited Partner or Assignee

By transfer of common units in accordance with our Partnership Agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “—Limited Liability”, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of the general partner, creates a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner or assignee, we may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, the general partner may require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about this nationality, citizenship or other related status within 30 days after a request for the information or the general partner determines after receipt of the information that the limited partner or assignee is not an eligible citizen, the limited partner or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted limited partner, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

EX-10.64

Exhibit 10.64

EXECUTION VERSION

NINTH AMENDMENT TO THE

RECEIVABLES FINANCING AGREEMENT

This NINTH AMENDMENT TO THE RECEIVABLES FINANCING AGREEMENT (this “Amendment”), dated as of January 15, 2021, is entered into by and among the following parties:

(i) AROP FUNDING, LLC, as Borrower;

(ii) ALLIANCE COAL, LLC, as initial Servicer; and

(iii) PNC BANK, NATIONAL ASSOCIATION (“PNC”), as LC Bank, LC Participant, Lender and Administrative Agent.

Capitalized terms used but not otherwise defined herein (including such terms used above) have the respective meanings assigned thereto in the Receivables Financing Agreement described below.

BACKGROUND

A.The parties hereto have entered into a Receivables Financing Agreement, dated as of December 5, 2014 (as amended, restated, supplemented or otherwise modified through to the date hereof, the “Receivables Financing Agreement”).

B.Concurrently herewith, the parties hereto are entering into an Amended and Restated Fee Letter (the “Fee Letter”) dated as of the date hereof.

C.The parties hereto desire to amend the Receivables Financing Agreement as set forth herein.

NOW, THEREFORE, with the intention of being legally bound hereby, and in consideration of the mutual undertakings expressed herein, each party to this Amendment hereby agrees as follows:

SECTION 1.Amendments to the Receivables Financing Agreement.  The Receivables Financing Agreement is hereby amended as shown on the marked pages set forth on Exhibit A attached hereto.

SECTION 2.Representations and Warranties of the Borrower and Servicer.  The Borrower and the Servicer hereby represent and warrant to each of the parties hereto as of the date hereof as follows:

(a)Representations and Warranties.  The representations and warranties made by it in the Receivables Financing Agreement and each of the other Transaction Documents to which it is a party are true and correct as of the date hereof.

(b)Enforceability.  The execution and delivery by it of this Amendment, and the performance of its obligations under this Amendment, the Receivables Financing

Agreement (as amended hereby) and the other Transaction Documents to which it is a party are within its organizational powers and have been duly authorized by all necessary action on its part, and this Amendment, the Receivables Financing Agreement (as amended hereby) and the other Transaction Documents to which it is a party are (assuming due authorization and execution by the other parties thereto) its valid and legally binding obligations, enforceable in accordance with its terms, except (x) the enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws from time to time in effect relating to creditors’ rights, and (y) the remedy of specific performance and injunctive and other forms of equitable relief may be subject to equitable defenses and to the discretion of the court before which any proceeding therefor may be brought.

(c)No Event of Default.  No Event of Default or Unmatured Event of Default has occurred and is continuing, or would occur as a result of this Amendment or the transactions contemplated hereby.

SECTION 3.Effect of Amendment; Ratification.  All provisions of the Receivables Financing Agreement and the other Transaction Documents, as expressly amended and modified by this Amendment, shall remain in full force and effect.  After this Amendment becomes effective, all references in the Receivables Financing Agreement (or in any other Transaction Document) to “this Receivables Financing Agreement”, “this Agreement”, “hereof”, “herein” or words of similar effect referring to the Receivables Financing Agreement shall be deemed to be references to the Receivables Financing Agreement as amended by this Amendment. This Amendment shall not be deemed, either expressly or impliedly, to waive, amend or supplement any provision of the Receivables Financing Agreement other than as set forth herein.  The Receivables Financing Agreement, as amended by this Amendment, is hereby ratified and confirmed in all respects.

SECTION 4.Conditions to Effectiveness.  This Amendment shall become effective as of the date hereof upon the Administrative Agent’s receipt of (a) counterparts of this Amendment and the Fee Letter executed by each of the parties hereto and thereto and (b) the renewal fee owing under the Fee Letter.

SECTION 5.Severability.  Any provisions of this Amendment which are prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

SECTION 6.Transaction Document.  This Amendment shall be a Transaction Document for purposes of the Receivables Financing Agreement.

SECTION 7.Counterparts.  This Amendment may be executed in any number of counterparts and by different parties on separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute but one and the same instrument.  Delivery of an executed counterpart of a signature page to this

2

Amendment by facsimile or e-mail transmission shall be effective as delivery of a manually executed counterpart hereof.

SECTION 8.GOVERNING LAW AND JURISDICTION.

THIS AMENDMENT, INCLUDING THE RIGHTS AND DUTIES OF THE PARTIES HERETO, SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK (INCLUDING SECTIONS 5-1401 AND 5-1402 OF THE GENERAL OBLIGATIONS LAW OF THE STATE OF NEW YORK, BUT WITHOUT REGARD TO ANY OTHER CONFLICTS OF LAW PROVISIONS THEREOF, EXCEPT TO THE EXTENT THAT THE PERFECTION, THE EFFECT OF PERFECTION OR PRIORITY OF THE INTERESTS OF ADMINISTRATIVE AGENT OR ANY LENDER IN THE COLLATERAL IS GOVERNED BY THE LAWS OF A JURISDICTION OTHER THAN THE STATE OF NEW YORK).

EACH PARTY HERETO HEREBY IRREVOCABLY SUBMITS TO (I) WITH RESPECT TO THE BORROWER AND THE SERVICER, THE EXCLUSIVE JURISDICTION, AND (II) WITH RESPECT TO EACH OF THE OTHER PARTIES HERETO, THE NON-EXCLUSIVE JURISDICTION, IN EACH CASE, OF ANY NEW YORK STATE OR FEDERAL COURT SITTING IN NEW YORK CITY, NEW YORK IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AMENDMENT, AND EACH PARTY HERETO HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING (I) IF BROUGHT BY THE BORROWER, THE SERVICER OR ANY AFFILIATE THEREOF, SHALL BE HEARD AND DETERMINED, AND (II) IF BROUGHT BY ANY OTHER PARTY TO THIS AMENDMENT, MAY BE HEARD AND DETERMINED, IN EACH CASE, IN SUCH NEW YORK STATE COURT OR, TO THE EXTENT PERMITTED BY LAW, IN SUCH FEDERAL COURT.  NOTHING IN THIS SECTION SHALL AFFECT THE RIGHT OF THE ADMINISTRATIVE AGENT OR ANY OTHER CREDIT PARTY TO BRING ANY ACTION OR PROCEEDING AGAINST THE BORROWER OR THE SERVICER OR ANY OF THEIR RESPECTIVE PROPERTY IN THE COURTS OF OTHER JURISDICTIONS.  EACH OF THE BORROWER AND THE SERVICER HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT IT MAY EFFECTIVELY DO SO, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING.  THE PARTIES HERETO AGREE THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW.

SECTION 9.Section Headings.  The various headings of this Amendment are included for convenience only and shall not affect the meaning or interpretation of this Amendment, the Receivables Financing Agreement or any provision hereof or thereof.

[SIGNATURE PAGES FOLLOW]

3

IN WITNESS WHEREOF, the parties hereto have executed this Amendment by their duly authorized officers as of the date first above written.

AROP FUNDING, LLC
By:	/s/ CARY P. MARSHALL
Name:	Cary P. Marshall
Title:	Vice President – Corporate Finance and Treasurer
ALLIANCE COAL, LLC,
as the Servicer
By:	/s/ CARY P. MARSHALL
Name:	Cary P. Marshall
Title:	Vice President – Corporate Finance and Treasurer

S-1 Ninth Amendment to Receivables Financing Agreement

PNC BANK, NATIONAL ASSOCIATION,
as Administrative Agent
By:	/s/ MICHAEL BROWN
Name:	Michael Brown
Title:	Senior Vice President
PNC BANK, NATIONAL ASSOCIATION,
as LC Bank and as an LC Participant
By:	/s/ MICHAEL BROWN
Name:	Michael Brown
Title:	Senior Vice President
PNC BANK, NATIONAL ASSOCIATION,
as a Lender
By:	/s/ MICHAEL BROWN
Name:	Michael Brown
Title:	Senior Vice President

S-2 Ninth Amendment to Receivables Financing Agreement

EXHIBIT A

(Attached)

EXECUTION COPYVERSION

EXHIBIT A to EighthNinth Amendment dated October 22, 2019January 15, 2021

RECEIVABLES FINANCING AGREEMENT

Dated as of December 5, 2014

by and among

AROP FUNDING, LLC,

as Borrower,

THE PERSONS FROM TIME TO TIME PARTY HERETO,

as Lenders and LC Participants,

PNC BANK, NATIONAL ASSOCIATION,

as LC Bank,

PNC BANK, NATIONAL ASSOCIATION,

as Administrative Agent,

and

ALLIANCE COAL, LLC,

as initial Servicer

Table of Contents
	Page
ARTICLE I        DEFINITIONS	1
SECTION 1.01.        Certain Defined Terms	1
SECTION 1.02.        Other Interpretative Matters	28
ARTICLE II        TERMS OF THE LOANS	29
SECTION 2.01.        Loan Facility	29
SECTION 2.02.        Making Loans; Repayment of Loans	29
SECTION 2.03.        Interest and Fees	31
SECTION 2.04.        Records of Loans and Participation Advances	32
ARTICLE III        LETTER OF CREDIT FACILITY	32
SECTION 3.01.        Letters of Credit	32
SECTION 3.02.        Issuance of Letters of Credit; Participations	33
SECTION 3.03.        Requirements For Issuance of Letters of Credit	34
SECTION 3.04.        Disbursements, Reimbursement	34
SECTION 3.05.        Repayment of Participation Advances	34
SECTION 3.06.        Documentation	35
SECTION 3.07.        Determination to Honor Drawing Request	35
SECTION 3.08.        Nature of Participation and Reimbursement Obligations	35
SECTION 3.09.        Indemnity	37
SECTION 3.10.        Liability for Acts and Omissions	37
ARTICLE IV        SETTLEMENT PROCEDURES AND PAYMENT PROVISIONS	39
SECTION 4.01.        Settlement Procedures	39
SECTION 4.02.        Payments and Computations, Etc	41
ARTICLE V        INCREASED COSTS; FUNDING LOSSES; TAXES; ILLEGALITY AND SECURITY INTEREST	42
SECTION 5.01.        Increased Costs	42
SECTION 5.02.        Funding Losses	44
SECTION 5.03.        Taxes	44
SECTION 5.04.        Inability to Determine Euro-Rate; Change in Legality	48
SECTION 5.05.        Security Interest	49
SECTION 5.06        Successor Adjusted LIBOR or LMIR Index	55
ARTICLE VI        CONDITIONS TO EFFECTIVENESS AND CREDIT EXTENSIONS	50

Table of Contents
EXHIBITS
EXHIBIT A	–	Form of [Loan Request] [LC Request]
EXHIBIT B	–	Form of Assignment and Acceptance Agreement
EXHIBIT C	–	Form of Assumption Agreement
EXHIBIT D	–	Form of Letter of Credit Application
EXHIBIT E	–	Credit and Collection Policy
EXHIBIT F	–	Form of Information Package
EXHIBIT G	–	Form of Compliance Certificate
EXHIBIT H	–	Closing Memorandum
EXHIBIT I-1	–	Form of Weekly Report
EXHIBIT I-2	–	Form of Daily Report
SCHEDULES
SCHEDULE I	–	Commitments
SCHEDULE II	–	Lock-Boxes, Lock-Box Accounts and Lock-Box Banks
SCHEDULE III	–	Notice Addresses
SCHEDULE IV	–	Excluded Receivables
SCHEDULE V		Mining Locations

This RECEIVABLES FINANCING AGREEMENT (as amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into as of December 5, 2014 by and among the following parties:

(i)AROP FUNDING, LLC, a Delaware limited liability company, as Borrower (together with its successors and assigns, the “Borrower”);

(ii)the Persons from time to time party hereto as Lenders and LC Participants;

(iii)PNC BANK, NATIONAL ASSOCIATION, as LC Bank (in such capacity, together with its successors and assigns in such capacity, the “LC Bank”);

(iv)PNC BANK, NATIONAL ASSOCIATION (“PNC”), as Administrative Agent; and

(v)ALLIANCE COAL, LLC, a Delaware limited liability company (“Alliance”), as initial Servicer (in such capacity, together with its successors and assigns in such capacity, the “Servicer”).

PRELIMINARY STATEMENTS

The Borrower has acquired, and will acquire from time to time, Receivables from the Transferor pursuant to the Sale and Contribution Agreement.  The Transferor has acquired, and will acquire from time to time, Receivables from the Originator(s) pursuant to the Purchase and Sale Agreement.  The Borrower has requested (a) that the Lenders make Loans from time to time to the Borrower and (b) the LC Bank to issue Letters of Credit for the account of the Borrower from time to time, in each case, on the terms, and subject to the conditions set forth herein, secured by, among other things, the Receivables.

In consideration of the mutual agreements, provisions and covenants contained herein, the sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

SECTION 1.01. Certain Defined Terms.  As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Adjusted LC Participation Amount” means, at any time of determination, the greater of (i) the LC Participation Amount less the amount of cash collateral held in the LC Collateral Account at such time and (ii) zero ($0).

“Adjusted LIBOR”  means with respect to any Interest Period, the greater of (a) 0.000.50% and (b) the interest rate per annum determined by the Administrative Agent by dividing (the resulting quotient rounded upwards, if necessary, to the nearest 1/100th of 1% per annum) (i) the rate of interest determined by the Administrative Agent in accordance with its

provided, that, for purposes of determining the “Excess Concentration” pursuant to clause (a) above, with respect to any Eligible Receivable supported by an Eligible Supporting Letter of Credit, the “Obligor” thereof shall be deemed to be the related Eligible Supporting Letter of Credit Provider, provided, further that, for purposes of determining the “Excess Concentration” pursuant to clause (b) above, with respect to any Eligible Receivable supported by an Eligible Supporting Letter of Credit, the “Obligor” thereof shall be deemed to be the related Eligible Supporting Letter of Credit Provider (and, with respect to any Eligible Receivable supported by an Eligible Supporting Letter of Credit, such Obligor shall be deemed to be organized under the laws of the country in which the office from which it is obligated to make payment with respect to such Eligible Supporting Letter of Credit is located) and provided, further that if any Pool Receivable is partially supported by an Eligible Supporting Letter of Credit, then the “Obligor” thereof shall be deemed to be (i) with respect to the Unsupported Outstanding Balance of such Pool Receivable, the Obligor of such Pool Receivable and (ii) with respect to the Supported Outstanding Balance of such Pool Receivable, the related Eligible Supporting Letter of Credit Provider.

“Exchange Act” means the Securities Exchange Act of 1934, as amended or otherwise modified from time to time.

“Excluded Receivable” means any Receivable (without giving effect to the exclusion of “Excluded Receivables” from the definition of “Receivable”) which arose from the sale of minerals that were extracted from one or more of the mineheads set forth on Schedule IV hereto or the sale or leasing of equipment (provided, that coal shall not constitute equipment for purposes of this definition).

“Excluded Taxes” means any of the following Taxes imposed on or with respect to an Affected Person or required to be withheld or deducted from a payment to an Affected Person: (a) Taxes imposed on or measured by net income (however denominated), franchise Taxes and branch profits Taxes, in each case, (i) imposed as a result of such Affected Person being organized under the laws of, or having its principal office or, in the case of any Lender, its applicable lending office located in, the jurisdiction imposing such Tax (or any political subdivision thereof) or (ii) that are Other Connection Taxes, (b) in the case of a Lender, U.S. federal withholding Taxes imposed on amounts payable to or for the account of such Lender with respect to an applicable interest in the Loans or Commitment pursuant to a law in effect on the date on which (i) such Lender makes a Loan or its Commitment or (ii) such Lender changes its lending office, except in each case to the extent that amounts with respect to such Taxes were payable either to such Lender’s assignor immediately before such Lender became a party hereto or to such Lender immediately before it changed its lending office and (c) any U.S. federal withholding Taxes imposed pursuant to FATCA.

“Exiting Lender” has the meaning set forth in Section 2.02(g).

“Facility Limit” means $100,000,00060,000,000 as reduced or increased from time to time pursuant to Section 2.02(e) or 2.02(h), as applicable.  References to the unused portion of the Facility Limit shall mean, at any time of determination, an amount equal to (x) the Facility Limit at such time, minus (y) the sum of the Aggregate Capital plus the LC Participation Amount.

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(a) the applicable Euro-Rate with respect to such Lender for such Interest Period (or portion thereof) (provided that for such purpose, if such Euro-Rate is being determined by reference to LMIR for such Lender, the Euro-Rate for such day shall be LMIR in effect on such day); or

(b) if the Base Rate is applicable to such Lender pursuant to Section 5.04, the Base Rate in effect on such day;

provided, however, that the “Interest Rate” for any day while an Event of Default has occurred and is continuing shall be an interest rate per annum equal to the sum of 2.00% per annum plus the greater of (i) the Base Rate in effect on such day and (ii) the Adjusted LIBOR with respect to such Lender for such Interest Period; provided, further, that no provision of this Agreement shall require the payment or permit the collection of Interest in excess of the maximum permitted by Applicable Law; and provided, further, however,  that Interest for any Loan shall not be considered paid by any distribution to the extent that at any time all or a portion of such distribution is rescinded or must otherwise be returned for any reason.

“Interim Report” means each Daily Report and Weekly Report.

“In-Transit Receivable” means, at any time of determination, any Receivable arising in connection with the sale of any goods or merchandise that as of such time, have been shipped but not delivered to the related Obligor.

“Investment Company Act” means the Investment Company Act of 1940, as amended or otherwise modified from time to time.

“LC Bank” has the meaning set forth in the preamble to this Agreement.

“LC Collateral Account” means the account at any time designated as the LC Collateral Account established and maintained by the Administrative Agent (for the benefit of the LC Bank and the LC Participants), or such other account as may be so designated as such by the Administrative Agent.

“LC Fee Expectation” has the meaning set forth in Section 3.05(c).

“LC Limit” means $100,000,00060,000,000.  References to the unused portion of the LC Limit shall mean, at any time of determination, an amount equal to (x) the LC Limit at such time, minus (y) the LC Participation Amount.

“LC Participant” means each Lender.

“LC Participation Amount” means at any time of determination, the sum of the amounts then available to be drawn under all outstanding Letters of Credit.

“LC Request” means a letter in substantially the form of Exhibit A hereto executed and delivered by the Borrower to the Administrative Agent, the LC Bank and the Lenders pursuant to Section 3.02(a).

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“LCR Security” means any commercial paper or security (other than equity securities issued to Parent or any Originator that is a consolidated subsidiary of Parent under generally accepted accounting principles) within the meaning of Paragraph __.32(e)(1)(viii) of the final rules titled Liquidity Coverage Ratio: Liquidity Risk Measurement Standards, 79 Fed. Reg. 197, 61440 et seq. (October 10, 2014).

“Lenders” means PNC and each other Person that becomes a party to this Agreement in the capacity of a “Lender”.

“Letter of Credit” means any stand-by letter of credit issued by the LC Bank at the request of the Borrower pursuant to this Agreement.

“Letter of Credit Application” has the meaning set forth in Section 3.02(a).

“LMIR” means for any day during any Interest Period, the greater of (a) 0.000.50% and (b) the interest rate per annum determined by the Administrative Agent (which determination shall be conclusive absent manifest error) by dividing (i) the one-month Eurodollar rate for U.S. dollar deposits as reported by Bloomberg Finance L.P. and shown on US0001M Screen or any other service or page that may replace such page from time to time for the purpose of displaying offered rates of leading banks for London interbank deposits in United States dollars, as of 11:00 a.m. (London time) on such day, or if such day is not a Business Day, then the immediately preceding Business Day (or if not so reported, then as determined by the Administrative Agent from another recognized source for interbank quotation), in each case, changing when and as such rate changes, by (ii) a number equal to 1.00 minus the Euro-Rate Reserve Percentage on such day.  The calculation of LMIR may also be expressed by the following formula:

	One-month Eurodollar rate for U.S. Dollars
	shown on Bloomberg US0001M Screen
	or appropriate successor
LMIR =
	1.00 - Euro-Rate Reserve Percentage

LMIR shall be adjusted on the effective date of any change in the Euro-Rate Reserve Percentage as of such effective date.

“Loan” means any loan made by a Lender pursuant to Section 2.02.

“Loan Request” means a letter in substantially the form of Exhibit A hereto executed and delivered by the Borrower to the Administrative Agent and each Lender pursuant to Section 2.02(a).

“Lock-Box” means each locked postal box with respect to which a Lock-Box Bank who has executed a Lock-Box Agreement pursuant to which it has been granted exclusive access for the purpose of retrieving and processing payments made on the Receivables and which is listed on Schedule II (as such schedule may be modified from time to time in connection with the addition or removal of any Lock-Box in accordance with the terms hereof).

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“S&P” means Standard & Poor’s Rating Services, a Standard & Poor’s Financial Services LLC business, and any successor thereto that is a nationally recognized statistical rating organization.

“Sale Agreements” means the Purchase and Sale Agreement and the Sale and Contribution Agreement.

“Sale and Contribution Agreement” means the Sale and Contribution Agreement, dated as of the Closing Date, among the Servicer, the Transferor and the Borrower, as such agreement may be amended, amended and restated, supplemented or otherwise modified from time to time.

“Sanctioned Country” means a country subject to a sanctions program maintained under any Anti-Terrorism Law.

“Sanctioned Person”  means any individual person, group, regime, entity or thing listed or otherwise recognized as a specially designated, prohibited, sanctioned or debarred person, group, regime, entity or thing, or subject to any limitations or prohibitions (including but not limited to the blocking of property or rejection of transactions), under any Anti-Terrorism Law.

“Scheduled Termination Date” means January 15, 2021,14, 2022, as such date may be extended from time to time pursuant to Section 2.02(g).

“SEC” shall mean the U.S. Securities and Exchange Commission or any governmental agencies substituted therefor.

“Secured Parties” means each Credit Party and each Borrower Indemnified Party.

“Securities Act” means the Securities Act of 1933, as amended or otherwise modified from time to time.

“Servicer” has the meaning set forth in the preamble to this Agreement.

“Servicer Indemnified Amount” has the meaning set forth in Section 13.02(a).

“Servicer Indemnified Party” has the meaning set forth in Section 13.02(a).

“Servicing Fee” shall mean the fee referred to in Section 9.06(a) of this Agreement.

“Servicing Fee Rate” shall mean the rate referred to in Section 9.06(a) of this Agreement.

“Settlement Date” means with respect to any Portion of Capital for any Interest Period or any Fees, (i) prior to the Termination Date, the Monthly Settlement Date and (ii) on and after the Termination Date, each day selected from time to time by the Administrative Agent (with the consent or at the direction of the Majority Lenders) (it being understood that the Administrative Agent (with the consent or at the direction of the Majority Lenders) may select such Settlement Date to occur as frequently as daily), or, in the absence of such selection, the Monthly Settlement Date.

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such Loans are requested (it being understood, that no Lender shall be responsible for the failure of any other Lender to make funds available to the Borrower in connection with any Loan hereunder).

(d)The Borrower shall repay in full the outstanding Capital of each Lender on the Final Maturity Date.  Prior thereto, the Borrower shall, on each Settlement Date, make a prepayment of the outstanding Capital of the Lenders to the extent required under Section 4.01 and otherwise in accordance therewith.  Notwithstanding the foregoing, the Borrower, in its discretion, shall have the right to make a prepayment, in whole or in part, of the outstanding Capital of the Lenders (together with any associated Breakage Fees and any accrued Interest and Fees in respect of such prepaid Capital) on any Business Day upon two (2) Business Days’ prior written notice thereof to the Administrative Agent and each Lender; provided, however, that each such prepayment shall be in a minimum aggregate amount of $100,000 and shall be an integral multiple of $100,000 (or, if less, the outstanding Capital, plus accrued but unpaid Interest and Fees together with any associated Breakage Fees).

(e)The Borrower may, at any time upon at least fifteen (15) days’ prior written notice to the Administrative Agent and each Lender, terminate the Facility Limit in whole or ratably reduce the Facility Limit in part.  Each partial reduction in the Facility Limit shall be in a minimum aggregate amount of $5,000,000 and shall be an integral multiple of $1,000,000, and no such partial reduction shall reduce the Facility Limit to an amount less than $50,000,0001,000,000.  In connection with any partial reduction in the Facility Limit, the Commitment of each Lender and LC Participant, as well as the LC Limit, shall be ratably reduced.

(f)In connection with any reduction of the Commitments, the Borrower shall remit to the Administrative Agent (i) instructions regarding such reduction and (ii) for payment to the Lenders, cash in an amount sufficient to pay (A) Capital of each Lender in excess of its Commitment and (B) all other outstanding Borrower Obligations with respect to such reduction (determined based on the ratio of the reduction of the Commitments being effected to the amount of the Commitments prior to such reduction or, if the Administrative Agent reasonably determines that any portion of the outstanding Borrower Obligations is allocable solely to that portion of the Commitments being reduced or has arisen solely as a result of such reduction, all of such portion) including, without duplication, any associated Breakage Fees.  Upon receipt of any such amounts, the Administrative Agent shall apply such amounts first to the reduction of the outstanding Capital, and second to the payment of the remaining outstanding Borrower Obligations with respect to such reduction, including any Breakage Fees, by paying such amounts to the Lenders.

(g)Provided that no Event of Default or Unmatured Event of Default has occurred and is continuing, the Borrower may from time to time advise the Administrative Agent, the LC Bank and each Lender in writing of its desire to extend the Scheduled Termination Date for an additional 364 day period, provided that such request is made not more than one hundred twenty (120) days prior to, and not less than sixty (60) days prior to, the then current Scheduled Termination Date.  The Administrative Agent, the LC Bank and each Lender shall notify the Borrower and the Administrative Agent in writing whether or not such Person is agreeable to such extension (it being understood that the Administrative Agent, the LC Bank and

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file UCC-3 termination statements and such other documents as the Borrower shall reasonably request to evidence such termination.

SECTION 5.06    Sucessor Adjusted LIBOR or LMIR IndexBenchmark Replacement Setting

(a)If the Administrative Agent determines in its reasonable discretion that either (i) (A) the circumstances set forth in Section 5.04 have arisen and are unlikely to be temporary, or (B) the circumstances set forth in Section 5.04 have not arisen but the applicable supervisor or administrator (if any) of the Euro Rate or a Governmental Authority having jurisdiction over the Administrative Agent has made a public statement identifying the specific date after which the Euro Rate shall no longer be used for determining interest rates for loans (such date, a “LIBOR Termination Date”), or (ii) a rate other than the Euro Rate has become a widely recognized benchmark rate for newly originated loans in Dollars in the U.S. market, then the Administrative Agent shall notify the Borrower, and the Administrative Agent and the Borrower shall endeavor to promptly choose a replacement index for the Euro Rate and make adjustments to applicable margins and related amendments to this Agreement as referred to in clauses (b) and (c) below such that, to the extent practicable, the all in Interest Rate based on the replacement index will be substantially equivalent to the all in Interest Rate based on the Euro Rate in effect prior to its replacement (or, if applicable, as in effect immediately prior to the conditions that gave rise to the need for its replacement).Benchmark Replacement. Notwithstanding anything to the contrary herein or in any other Transaction Document, if a Benchmark Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (x) if a Benchmark Replacement is determined in accordance with clause (1) or (2) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Transaction Document in respect of such Benchmark setting and subsequent Benchmark settings without any amendment to, or further action or consent of any other party to, this Agreement or any other Transaction Document and (y) if a Benchmark Replacement is determined in accordance with clause (3) of the definition of “Benchmark Replacement” for such Benchmark Replacement Date, such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Transaction Document in respect of any Benchmark setting at or after 5:00 p.m. New York City time on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Transaction Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Majority Lenders.

(b)The Administrative Agent and the Borrower shall enter into an amendment to this Agreement to reflect the replacement index, the adjusted margins and such other related amendments as may be appropriate, in the commercially reasonable discretion of the Administrative Agent, for the implementation and administration of the replacement index based rate. NotwithstandingBenchmark Replacement Conforming Changes. In connection with the implementation of a Benchmark Replacement, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding

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anything to the contrary in this Agreement or the other Transaction Documents (including, without limitation, Section 14.01), such amendment shallherein or in any other Transaction Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement at 5:00 p.m. New York City time on the tenth (10th) Business Day after the date a draft of the amendment is provided to the Lenders, unless the Administrative Agent receives, on or before such tenth (10th) Business Day, a written notice from the Majority Lenders stating that such Majority Lenders object to such amendment. or any other Transaction Document.

(c)Selection of the replacement index, adjustments to the applicable margins, and amendments to this Agreement (i) will be determined with due consideration to the then current market practices for determining and implementing a rate of interest for newly-originated loans in the United States and loans converted from a rate based on the Euro Rate to a replacement index based rate, and (ii) may also reflect adjustments to account for (A) the effects of the transition from the Euro Rate to the replacement index and (B) yield or risk based differences between the Euro Rate and the replacement index.Notices; Standards for Decisions and Determinations. The Administrative Agent will promptly notify the Borrower and the Lenders of (i) any occurrence of a Benchmark Transition Event , a Term SOFR Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date, (ii) the implementation of any Benchmark Replacement, (iii) the effectiveness of any Benchmark Replacement Conforming Changes, (iv) the removal or reinstatement of any tenor of a Benchmark pursuant to paragraph (d) and (v) the commencement or conclusion of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 5.06, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party to this Agreement or any other Transaction Document, except, in each case, as expressly required pursuant to this Section 5.06.

(d)Until an amendment reflecting a new replacement index in accordance with this Section 5.06 is effective, any Portion of Capital for which Interest is determined by reference to the Euro-Rate will continue to accrue Interest with reference to the Euro-Rate; provided however, that if the Administrative Agent determines in its commercially reasonable discretion that a LIBOR Termination Date has occurred, then following the LIBOR Termination Date, all Portions of Capital for which Interest would otherwise be determined with reference to the Euro-Rate shall automatically begin accruing Interest with reference to the Base Rate until such time a s an amendment reflecting a replacement index and related matters as described above is implemented.Unavailability of Tenor of Benchmark. Notwithstanding anything to the contrary herein or in any other Transaction Document, at any time (including in connection with the implementation of a Benchmark Replacement), (i) if the then-current Benchmark is a term rate (including Term SOFR or USD LIBOR) and either (A) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (B) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative,

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then the Administrative Agent may modify the definition of“Interest Period” for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor and (ii) if a tenor that was removed pursuant to clause (i) above either (A) is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) or (B) is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate such previously removed tenor.

(e)Notwithstanding anything to the contrary contained herein, if at any time the replacement index is less than zero, at such times, such index shall be deemed to be zero for purposes of this Agreement.Benchmark Unavailability Period. Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a Loan bearing interest based on USD LIBOR, conversion to or continuation of Loans bearing interest based on USD LIBOR to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any such request into a request for a Loan of or conversion to Loans bearing interest under the Base Rate. During any Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of the Base Rate based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of the Base Rate.

(f)This Section 5.06 of the Agreement provides a mechanism for determining an alternative rate of interest in the event that the London interbank offered rate is no longer available or in certain other circumstances. The Administrative Agent does not warrant or accept any responsibility for and shall not have any liability with respect to, the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of the Euro-Rate or with respect to any alternative or successor rate thereto, or replacement rate therefor.Secondary Term SOFR Conversion. Notwithstanding anything to the contrary herein or in any other Transaction Document and subject to the proviso below in this paragraph, if a Term SOFR Transition Event and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then (i) the applicable Benchmark Replacement will replace the then-current Benchmark for all purposes hereunder or under any Transaction Document in respect of such Benchmark setting (the “Secondary Term SOFR Conversion Date”) and subsequent Benchmark settings, without any amendment to, or further action or consent of any other party to, this Agreement or any other Transaction Document; and (ii) Loans outstanding on the Secondary Term SOFR Conversion Date bearing interest based on the then-current Benchmark shall be deemed to have been converted to Loans bearing interest at the Benchmark Replacement with a tenor approximately the same length as the interest payment period of the then-current Benchmark; provided that, this paragraph (f) shall not be effective unless the Administrative Agent has delivered to the Lenders and the Borrower a Term SOFR Notice.

(g)​ ​Certain Defined Terms. As used in this Section titled “Benchmark Replacement Setting”;

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“Available Tenor” means, as of any date of determination and with respect to the then-current Benchmark, as applicable, (x) if the then current Benchmark is a term rate or is based on a term rate, any tenor for such Benchmark that is or may be used for determining the length of an Interest Period pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant t o paragraph (d) of this Section 5.06, or (y) if the then current Benchmark is not a term rate nor based on a term rate, any payment period for interest calculated with reference to such Benchmark pursuant to this Agreement as of such date. For the avoidance of doubt, the Available Tenor for LMIR is one month.

“Benchmark” means, initially, USD LIBOR; provided that if a Benchmark Transition Event a Term SOFR Transition Event or an Early Opt-in Election, as applicable, and its related Benchmark Replacement Date have occurred with respect to USD LIBOR or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to paragraph (a) of this Section 5.06.

“Benchmark Replacement” means, for any Available Tenor, the first alternative set forth in the order below that can be determined by the Administrative Agent for the applicable Benchmark Replacement Date:

(1) the sum of: (a) Term SOFR and (b) the related Benchmark Replacement Adjustment;

(2) the sum of: (a) Daily Simple SOFR and (b) the related Benchmark Replacement Adjustment;

(3) the sum of: (a) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower as the replacement for the then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving o r then-prevailing market convention for determining a benchmark rate as a replacement for the then-current Benchmark for U.S. dollar-denominated syndicated credit facilities a t such time and (b) the related Benchmark Replacement Adjustment;

provided that, in the case of clause (1), such Unadjusted Benchmark Replacement is displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion; provided, further, that, with respect to a Term SOFR Transition Event, on the applicable Benchmark Replacement Date, the “Benchmark Replacement” shall revert to and shall be determined as set forth in clause (1) of this definition. If the Benchmark Replacement as determined pursuant to clause (1), (2) or (3) above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Transaction Documents.

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“Benchmark Replacement Adjustment” means, with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Available Tenor for any setting of such Unadjusted Benchmark Replacement:

(1) for purposes of clauses (1) and (2) of the definition of “Benchmark Replacement,” the first alternative set forth in the order below that can be determined by the Administrative Agent:

(a) the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Available Tenor that has been selected or recommended by the Relevant Governmental Body for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for the applicable Corresponding Tenor;

(b) the spread adjustment (which may be a positive or negative value or zero) as of the Reference Time such Benchmark Replacement is first set for such Available Tenor that would apply to the fallback rate for a derivative transaction referencing the ISDA Definitions to be effective upon an index cessation event with respect to such Benchmark for the applicable Corresponding Tenor; and

(2) for purposes of clause (3) of the definition of “Benchmark Replacement,” the spread adjustment, or method for calculating or determining such spread adjustment, (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body on the applicable Benchmark Replacement Date or (ii) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for U.S. dollar-denominated syndicated credit facilities;

provided that, (x) in the case of clause (1) above, such adjustment is displayed on a screen or other information service that publishes such Benchmark Replacement Adjustment from time to time as selected by the Administrative Agent in its reasonable discretion and (y) if the then-current Benchmark is a term rate, more than one tenor of such Benchmark is available as of the applicable Benchmark Replacement Date and the applicable Unadjusted Benchmark Replacement will not be a term rate, the Available Tenor of such Benchmark for purposes of this definition of “Benchmark Replacement Adjustment” shall be deemed to be the Available Tenor that has approximately the same length (disregarding business day adjustments) as the payment period for interest calculated with reference to such Unadjusted Benchmark Replacement.

“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement, any technical, administrative or operational changes (including changes to the definition of “Base Rate,” the definition of “Business Day,” the definition of “Interest Period,”

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timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, length of lookback periods, the applicability of breakage provisions, and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark Replacement and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark Replacement exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Transaction Documents).

“Benchmark Replacement Date” means the earliest to occur of the following events with respect to the then-current Benchmark:

(1) in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof);

(2) in the case of clause (3) of the definition of “Benchmark Transition Event,” the date determined by the Administrative Agent, which date shall promptly follow the date of the public statement or publication of information referenced therein;

(3) in the case of a Term SOFR Transition Event, the date that is set forth in the Term SOFR Notice provided to the Lenders and the Borrower pursuant to this Section 5.06, which date shall be at least 30 days from the date of the Term SOFR Notice; or

(4) in the case of an Early Opt-in Election, the sixth (6th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, so long as the Administrative Agent has not received, by 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Early Opt-in Election is provided to the Lenders, written notice of objection to such Early Opt-in Election from Lenders comprising the Majority Lenders.

For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Transition Event” means the occurrence of one or more of the following events with respect to the then-current Benchmark:

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(1) a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(2) a public statement or publication of information by a Governmental Authority having jurisdiction over the Administrative Agent, the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Federal Reserve Board, the Federal Reserve Bank of New York, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof) permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(3) a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof) or a Governmental Authority having jurisdiction over the Administrative Agent announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period” means the period (if any) (x) beginning at the time that a Benchmark Replacement Date pursuant to clauses (1) or (2) of that definition has occurred if, at such time, no Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Loan Document in accordance with this Section 5.06 and (y) ending at the time that a Benchmark Replacement has replaced the then-current Benchmark for all purposes hereunder and under any Transaction Document in accordance with this Section 5.06.

“Corresponding Tenor” with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding business day adjustment) as such Available Tenor.

“Daily Simple SOFR” means, for any day, SOFR, with the conventions for this rate (which will include a lookback) being established by the Administrative Agent in accordance

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with the conventions for this rate selected or recommended by the Relevant Governmental Body for determining “Daily Simple SOFR” for business loans; provided, that if the Administrative Agent decides that any such convention is not administratively feasible for the Administrative Agent, then the Administrative Agent may establish another convention in its reasonable discretion.

“Early Opt-in Election” means, if the then-current Benchmark is USD LIBOR, the occurrence of:

(1) a notification by the Administrative Agent to (or the request by the Borrower to the Administrative Agent to notify) each of the other parties hereto that at least five currently outstanding U.S. dollar-denominated syndicated credit facilities at such time contain (as a result of amendment or as originally executed) a SOFR-based rate (including SOFR, a term SOFR or any other rate based upon SOFR) as a benchmark rate (and such syndicated credit facilities are identified in such notice and are publicly available for review), and

(2) the joint election by the Administrative Agent and the Borrower to trigger a fallback from USD LIBOR and the provision by the Administrative Agent of written notice of such election to the Lenders.

“Floor” means the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to USD LIBOR or, if no floor is specified, zero.

“ISDA Definitions” means the 2006 ISDA Definitions published by the International Swaps and Derivatives Association, Inc. or any successor thereto, as amended or supplemented from time to time, or any successor definitional booklet for interest rate derivatives published from time to time by the International Swaps and Derivatives Association, Inc. or such successor thereto.

“Reference Time” with respect to any setting of the then-current Benchmark means (1) if such Benchmark is USD LIBOR, 11:00 a.m. (London time) on the day that is two London banking days preceding the date of such setting, and (2) if such Benchmark is not USD LIBOR, the time determined by the Administrative Agent in its reasonable discretion.

“Relevant Governmental Body” means the Federal Reserve Board or the Federal Reserve Bank of New York, or a committee officially endorsed or convened by the Federal Reserve Board or the Federal Reserve Bank of New York, or any successor thereto.

“SOFR” means, with respect to any Business Day, a rate per annum equal to the secured overnight financing rate for such Business Day published by the SOFR Administrator on the SOFR Administrator’s Website on the immediately succeeding Business Day.

“SOFR Administrator” means the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).

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“SOFR Administrator’s Website” means the website of the Federal Reserve Bank of New York, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the SOFR Administrator from time to time.

“Term SOFR” means, for the applicable Corresponding Tenor as of the applicable Reference Time, the forward-looking term rate based on SOFR that has been selected or recommended by the Relevant Governmental Body.

“Term SOFR Notice” means a notification by the Administrative Agent to the Lenders and the Borrower of the occurrence of a Term SOFR Transition Event.

“Term SOFR Transition Event” means the determination by the Administrative Agent that (a) Term SOFR has been recommended for use by the Relevant Governmental Body, and is determinable for each Available Tenor, (b) the administration of Term SOFR is administratively feasible for the Administrative Agent and (c) a Benchmark Transition Event has previously occurred resulting in a Benchmark Replacement in accordance with Section 5.06 that is not Term SOFR.

“Unadjusted Benchmark Replacement” means the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“USD LIBOR” means the London interbank offered rate for U.S. dollars.

ARTICLE VI

CONDITIONS TO EFFECTIVENESS AND CREDIT EXTENSIONS

SECTION 6.01.  Conditions Precedent to Effectiveness and the Initial Credit Extension.  This Agreement shall become effective as of the Closing Date when (a) the Administrative Agent shall have received each of the documents, agreements (in fully executed form), opinions of counsel, lien search results, UCC filings, certificates and other deliverables listed on the closing memorandum attached as Exhibit H hereto, in each case, in form and substance acceptable to the Administrative Agent and (b) all fees and expenses payable by the Borrower on the Closing Date to the Credit Parties have been paid in full in accordance with the terms of the Transaction Documents.

SECTION 6.02.  Conditions Precedent to All Credit Extensions.  Each Credit Extension hereunder on or after the Closing Date shall be subject to the conditions precedent that:

(a)in the case of a Loan, the Borrower shall have delivered to the Administrative Agent and each Lender a Loan Request for such Loan, and in the case of a Letter of Credit, the Borrower shall have delivered to the Administrative Agent, each Lender and the LC Bank, a Letter of Credit Application and an LC Request, in each case, in accordance with Section 2.02(a) or Section 3.02(a), as applicable;

(b)the Servicer shall have delivered to the Administrative Agent and each Lender all Information Packages required to be delivered hereunder;

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ARTICLE VIII

COVENANTS

SECTION 8.01.  Covenants of the Borrower.  At all times from the Closing Date until the Final Payout Date:

(a)Payment of Principal and Interest.  The Borrower shall duly and punctually pay Capital, Interest, Fees and all other amounts payable by the Borrower hereunder in accordance with the terms of this Agreement.

(b)Existence.  The Borrower shall keep in full force and effect its existence and rights as a limited liability company under the laws of the State of Delaware, and shall obtain and preserve its qualification to do business in each jurisdiction in which such qualification is or shall be necessary to protect the validity and enforceability of this Agreement, the other Transaction Documents and the Collateral.

(c)Financial Reporting.  The Borrower will maintain a system of accounting established and administered in accordance with GAAP, and the Borrower (or the Servicer on its behalf) shall furnish to the Administrative Agent, the LC Bank and each Lender:

(i)Annual Financial Statements of the Borrower.  Promptly upon completion and in no event later than 120 days after the close of each fiscal year of the Borrower, annual unaudited financial statements of the Borrower certified by a Financial Officer of the Borrower that they fairly present in all material respects, in accordance with GAAP, the financial condition of the Borrower as of the date indicated and the results of its operations for the periods indicated.

(ii)Quarterly Financial Statements of the Borrower.  Promptly upon completion and in no event later than 60 days following the end of each of the first three fiscal quarters in each of the Borrower’s fiscal years, quarterly unaudited financial statements of the Borrower certified by a Financial Officer of the Borrower that they fairly present in all material respects, in accordance with GAAP, the financial condition of the Borrower as of the date indicated and the results of its operations for the periods indicated.

(iii)Information Packages and Interim Reports.  (A) As soon as available and in any event not later than two (2) Business Days prior to each Settlement Date, an Information Package as of the most recently completed Fiscal Month; (B) at any time during the continuance of a Minimum Fixed Charge Ratio Period or an Event of Default, upon twoupon five (25) Business Days’ prior written notice from the Administrative Agent, a Weekly Report on the second Business Day of each calendar week as of the most recently completed calendar week and (C) at any time during the continuance of a Minimum Fixed Charge Ratio Period or an Event of Default, upon twoupon five (25) Business Days’ prior written notice from the Administrative Agent or during the continuance of an Event of Default, a Daily Report on each Business Day as of date that is one (1) Business Day prior to such date.

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(w)Borrower’s Net Worth.  The Borrower shall not permit the Borrower’s Net Worth to be less than the Required Capital Amount.

(x)Borrower’s Tax Status.  The Borrower will remain a wholly-owned subsidiary of a United States person (within the meaning of Section 7701(a)(30) of the Code) and not be subject to withholding under Section 1446 of the Code. No action will be taken that would cause the Borrower to be treated as an association taxable as a corporation or a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes.

(y)Liquid Coverage Ratio. The Borrower shall not issue any LCR Security.

(z)Beneficial Ownership Rule.   Promptly following any change that would result in a change to the status as an excluded “Legal Entity Customer” under (and as defined in) the Beneficial Ownership Rule, the Borrower shall execute and deliver to the Administrative Agent a Certification of Beneficial Owner(s) complying with the Beneficial Ownership Rule, in form and substance reasonably acceptable to the Administrative Agent.

SECTION 8.02   Covenants of the Servicer.  At all times from the Closing Date until the Final Payout Date:

(a)Financial Reporting.  The Servicer will maintain a system of accounting established and administered in accordance with GAAP, and the Servicer shall furnish to the Administrative Agent, the LC Bank and each Lender:

(i)Compliance Certificates.  (a) A compliance certificate promptly upon completion of the annual report of the Parent and in no event later than 120 days after the close of the Servicer’s fiscal year, in form and substance substantially similar to Exhibit G signed by a Financial Officer of the Servicer stating that no Event of Default or Unmatured Event of Default has occurred and is continuing, or if any Event of Default or Unmatured Event of Default has occurred and is continuing, stating the nature and status thereof and, (b) within 60 days after the close of each fiscal quarter of the Servicer, a compliance certificate in form and substance substantially similar to Exhibit G signed by a Financial Officer of the Servicer stating that no Event of Default or Unmatured Event of Default has occurred and is continuing, or if any Event of Default or Unmatured Event of Default has occurred and is continuing, stating the nature and status thereof and (c) within 45 days after the close of each fiscal quarter of the Parent, a certificate signed by a Financial Officer of the Servicer certifying that the location of any Originator’s Mined Properties or mineheads is accurately set forth on Schedule V to this Agreement, as amended prior to the date thereof.

(ii)Information Packages and Interim Reports.  (A) As soon as available and in any event not later than two (2) Business Days prior to each Settlement Date, an Information Package as of the most recently completed Fiscal Month; (B) at any time during the continuance of a Minimum Fixed Charge Ratio Period or an Event of Default, upon two upon five (25) Business Days’ prior written notice from the Administrative Agent, a Weekly Report on the second Business Day of each calendar week as of the most recently completed calendar week and (C) at any time during the

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continuance of a Minimum Fixed Charge Ratio Period or an Event of Default, upon twoupon five (25) Business Days’ prior written notice from the Administrative Agent or during the continuance of an Event of Default, a Daily Report on each Business Day as of date that is one (1) Business Day prior to such date.

(iii)Other Information.  Such other information (including non-financial information) as the Administrative Agent, the LC Bank or any Lender may from time to time reasonably request, including any information available to the Borrower, the Servicer, the Transferor or any Originator; provided, however, that at any time that no Minimum Fixed Charge Coverage Ratio Period or Event of Default has occurred and is continuing, the Administrative Agent will not request an Interim Report be furnished with respect to the Pool Receivables.

(b)Notices.  The Servicer will notify the Administrative Agent, the LC Bank and each Lender in writing of any of the following events promptly upon (but in no event later than five (5) Business Days after) a Financial Officer or other Responsible Officer learning of the occurrence thereof, with such notice describing the same, and if applicable, the steps being taken by the Person(s) affected with respect thereto:

(i)Notice of Events of Default or Unmatured Events of Default.  A statement of a Financial Officer of the Servicer setting forth details of any Event of Default or Unmatured Event of Default that has occurred and is continuing and the action which the Servicer proposes to take with respect thereto.

(ii)Representations and Warranties.  The failure of any representation or warranty made or deemed made by the Servicer under this Agreement or any other Transaction Document to be true and correct in any material respect when made.

(iii)Litigation.  The institution of any litigation, arbitration proceeding or governmental proceeding which could reasonably be expected to have a Material Adverse Effect.

(iv)Adverse Claim.  (A) Any Person shall obtain an Adverse Claim upon the Collateral or any portion thereof, (B) any Person other than the Borrower, the Servicer or the Administrative Agent shall obtain any rights or direct any action with respect to any Lock-Box Account (or related Lock-Box) or (C) any Obligor shall receive any change in payment instructions with respect to Pool Receivable(s) from a Person other than the Servicer or the Administrative Agent.

(v)Name Changes.  At least thirty (30) days before any change in any Originator’s, the Transferor’s or the Borrower’s name or any other change requiring the amendment of UCC financing statements, a notice setting forth such changes and the effective date thereof.

(vi)Change in Accountants or Accounting Policy.  Any change in (i) the external accountants of the Borrower, the Servicer, any Originator, the Transferor or the Parent, (ii) any accounting policy of the Borrower or (iii) any material accounting

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termination, release, partial release, or any amendment that deletes the name of a debtor or excludes collateral of any such financing statements filed in connection with the Transaction Documents, without the prior written consent of the Administrative Agent.

(m)Anti-Money Laundering/International Trade Law Compliance.  The Servicer will not become a Sanctioned Person.  No Covered Entity, either in its own right or through any third party, will (a) have any of its assets in a Sanctioned Country or in the possession, custody or control of a Sanctioned Person in violation of any Anti-Terrorism Law; (b) do business in or with, or derive any of its income from investments in or transactions with, any Sanctioned Country or Sanctioned Person in violation of any Anti-Terrorism Law; (c) engage in any dealings or transactions prohibited by any Anti-Terrorism Law or (d) use the proceeds of any Credit Extension to fund any operations in, finance any investments or activities in, or, make any payments to, a Sanctioned Country or Sanctioned Person in violation of any Anti-Terrorism Law.  The Servicer shall comply with all Anti-Terrorism Laws.  The Servicer shall promptly notify the Administrative Agent and each Lender in writing upon the occurrence of a Reportable Compliance Event.

(n)Mining Operations and Mineheads.  The Servicer shall (and shall cause each applicable Originator to) promptly, and in any event not later than the later of (x) February 15, 2021 and (y) 5 days after any addition to the location of any Originator’s Mined Properties or mineheads set forth on Schedule V to this Agreement, (i) notify the Administrative Agent of such addition, (ii) cause the filing or recording of such financing statements and amendments and/or releases to financing statements, mortgages or other instruments, if any, necessary to preserve and maintain the perfection and priority of the ownership and security interests of the Borrower and the Administrative Agent in the Collateral pursuant to the Purchase and Sale Agreement and this Agreement, in each case in form and substance satisfactory to the Administrative Agent, (iii) deliver to the Administrative Agent an updated Schedule V to this Agreement reflecting such change, deletion or addition and (iv) if requested by the Administrative Agent, cause to be delivered to the Administrative Agent, an opinion, in form and substance satisfactory to the Administrative Agent as to such UCC perfection matters as the Administrative Agent may request at such time.

SECTION 8.02.      Separate Existence of the Borrower.  Each of the Borrower and the Servicer hereby acknowledges that the Secured Parties and the Administrative Agent are entering into the transactions contemplated by this Agreement and the other Transaction Documents in reliance upon the Borrower’s identity as a legal entity separate from any Originator, the Transferor, the Servicer, the Performance Guarantor and their Affiliates.  Therefore, each of the Borrower and Servicer shall take all steps specifically required by this Agreement or reasonably required by the Administrative Agent or any Lender to continue the Borrower’s identity as a separate legal entity and to make it apparent to third Persons that the Borrower is an entity with assets and liabilities distinct from those of the Performance Guarantor, the Originators, the Transferor, the Servicer and any other Person, and is not a division of the Performance Guarantor, the Originators, the Transferor, the Servicer, its Affiliates or any other Person. Without limiting the generality of the foregoing and in addition to and consistent with the other covenants set forth herein, each of the Borrower and the Servicer shall take such actions as shall be required in order that:

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possession of the Administrative Agent or any of its directors, officers, agents, employees, attorneys-in-fact or Affiliates.

SECTION 11.09.  Successor Administrative Agent.

(a)The Administrative Agent may, upon at least thirty (30) days’ notice to the Borrower, the Servicer and each Credit Party, resign as Administrative Agent.  Except as provided below, such resignation shall not become effective until a successor Administrative Agent is appointed by the Majority Lenders as a successor Administrative Agent and has accepted such appointment.  If no successor Administrative Agent shall have been so appointed by the Majority Lenders, within thirty (30) days after the departing Administrative Agent’s giving of notice of resignation, the departing Administrative Agent may, on behalf of the Secured Parties, appoint a successor Administrative Agent as successor Administrative Agent.  If no successor Administrative Agent shall have been so appointed by the Majority Lenders within sixty (60) days after the departing Administrative Agent’s giving of notice of resignation, the departing Administrative Agent may, on behalf of the Secured Parties, petition a court of competent jurisdiction to appoint a successor Administrative Agent.

(b)Upon such acceptance of its appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall succeed to and become vested with all the rights and duties of the resigning Administrative Agent, and the resigning Administrative Agent shall be discharged from its duties and obligations under the Transaction Documents.  After any resigning Administrative Agent’s resignation hereunder, the provisions of this Article XI and Article XIII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was the Administrative Agent.

SECTION 11.10.  LIBOR Notification.  Section 5.06 of this Agreement provides a mechanism for determining an alternative rate of interest in the event that the London interbank offered rate is no longer available or in certain other circumstances. The Administrative Agent does not warrant or accept any responsibility for and shall not have any liability with respect to, the administration, submission or any other matter related to the London interbank offered rate or other rates in the definition of “Adjusted LIBOR” or “LMIR” or with respect to any alternative or successor rate thereto, or replacement rate therefor.

ARTICLE XII

[RESERVED]

ARTICLE XIII

INDEMNIFICATION

SECTION 13.01.    Indemnities by the Borrower.

(a)Without limiting any other rights that the Administrative Agent, the Credit Parties, the Affected Persons and their respective assigns, officers, directors, agents and

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IN WITNESS WHEREOF, the parties have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

AROP FUNDING, LLC
By:
Name:	R. Eberley Davis
Title:	Senior Vice President, General Counsel and Secretary
ALLIANCE COAL, LLC,
as the Servicer
By:
Name:	R. Eberley Davis
Title:	Senior Vice President, General Counsel and Secretary

S- 1 Receivables Financing Agreement

EXHIBIT A

Form of [Loan Request] [LC Request]

[Letterhead of Borrower]

[Date]

[Administrative Agent]

Re:[Loan Request] [LC Request]

Ladies and Gentlemen:

Reference is hereby made to that certain Receivables Financing Agreement, dated as of December 5, 2014 among AROP Funding, LLC (the “Borrower”), Alliance Coal, LLC, as Servicer (the “Servicer”), the Lenders party thereto, the LC Participants party thereto and PNC Bank, National Association, as Administrative Agent (in such capacity, the “Administrative Agent”) and as the LC Bank (as amended, supplemented or otherwise modified from time to time, the “Agreement”).  Capitalized terms used in this [Loan Request] [LC Request] and not otherwise defined herein shall have the meanings assigned thereto in the Agreement.

[This letter constitutes a Loan Request pursuant to Section 2.02(a) of the Agreement.  The Borrower hereby request a Loan in the amount of [$_______] to be made on [_____, 20__] (of which $[___] will be funded by PNC and $[___] will be funded by the [___].  The proceeds of such Loan should be deposited to [Account number], at [Name, Address and ABA Number of Bank].  After giving effect to such Loan, the Aggregate Capital will be [$_______].]

[This letter constitutes an LC Request pursuant to Section 3.02(a) of the Agreement.  The Borrower hereby request that the LC Bank issue a Letter of Credit with a face amount of [$_______] on [_____, 20__].  After giving effect to such issuance, the LC Participation Amount will be [$_______].

The Borrower hereby represents and warrants as of the date hereof, and after giving effect to such Credit Extension, as follows:

(i)the representations and warranties of the Borrower and the Servicer contained in Sections 7.01 and 7.02 of the Agreement are true and correct in all material respects on and as of the date of such Credit Extension as though made on and as of such date unless such representations and warranties by their terms refer to an earlier date, in which case they shall be true and correct in all material respects on and as of such earlier date;

(ii)no Event of Default or Unmatured Event of Default has occurred and is continuing, and no Event of Default or Unmatured Event of Default would result from such Credit Extension;

Exhibit A- 1

EXHIBIT B

Form of Assignment and Acceptance Agreement

Dated as of ___________, 20__

Section 1.

Commitment assigned:	$[_____]
Assignor’s remaining Commitment:	$[_____]
Capital allocable to Commitment assigned:	$[_____]
Assignor’s remaining Capital:	$[_____]
Interest (if any) allocable to Capital assigned:	$[_____]
Interest (if any) allocable to Assignor’s remaining Capital:	$[_____]

Section 2.

Effective Date of this Assignment and Acceptance Agreement: [__________]

Upon execution and delivery of this Assignment and Acceptance Agreement by the assignee and the assignor and the satisfaction of the other conditions to assignment specified in Section 14.03(b) of the Agreement (as defined below), from and after the effective date specified above, the assignee shall become a party to, and, to the extent of the rights and obligations thereunder being assigned to it pursuant to this Assignment and Acceptance Agreement, shall have the rights and obligations of a Lender under that certain Receivables Financing Agreement, dated as of December 5, 2014 among AROP Funding, LLC, Alliance Coal, LLC, as Servicer, the Lenders party thereto, the LC Participants party thereto and PNC Bank, National Association, as Administrative Agent and as the LC Bank (as amended, supplemented or otherwise modified from time to time, the “Agreement”).

(Signature Pages Follow)

Exhibit B- 1

EXHIBIT C

Form of Assumption Agreement

THIS ASSUMPTION AGREEMENT (this “Agreement”), dated as of [______ __, ____], is between AROP FUNDING, LLC (the “Borrower”) and [________], as lender (the “Lender”).

BACKGROUND

The Borrower and various others are parties to a certain Receivables Financing Agreement, dated as of December 5, 2014 (as amended through the date hereof and as the same may be amended, amended and restated, supplemented or otherwise modified from time to time, the “Receivables Financing Agreement”).  Capitalized terms used and not otherwise defined herein have the respective meaning assigned to such terms in the Receivables Financing Agreement.

NOW, THEREFORE, the parties hereto hereby agree as follows:

SECTION 1.This letter constitutes an Assumption Agreement pursuant to Section 14.03(h) of the Receivables Financing Agreement.  The Borrower desires the Lender to [become a party to] [increase its existing Commitment under] the Receivables Financing Agreement, and upon the terms and subject to the conditions set forth in the Receivables Financing Agreement, the [[________] Lenders] agree[s] to [become Lenders thereunder] [increase its Commitment to the amount set forth as its “Commitment” under the signature of such [______] Lender hereto].

The Borrower hereby represents and warrants to the [________] Lenders and the [_________] Administrative Agent as of the date hereof, as follows:

(i)the representations and warranties of the Borrower contained in Section 7.01 of the Receivables Financing Agreement are true and correct in all material respects on and as of such date as though made on and as of such date;

(ii)no Event of Default or Unmatured Event of Default has occurred and is continuing, or would result from the assumption contemplated hereby; and

(iii)the Termination Date shall not have occurred.

SECTION 2.Upon execution and delivery of this Agreement by the Borrower and [______] (including the written consent of the Administrative Agent and the LC Bank) and receipt by the Administrative Agent of counterparts of this Agreement (whether by facsimile or otherwise) executed by each of the parties hereto, [the [_____] Lender shall become a party to, and have the rights and obligations of a Lender under, the Receivables Financing Agreement and a “Commitment” as shall be as set forth under the signature of each such Lender hereto].

SECTION 3.THIS AGREEMENT, INCLUDING THE RIGHTS AND DUTIES OF THE PARTIES HERETO, SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK (INCLUDING SECTIONS 5-1401 AND 5-1402 OF THE GENERAL OBLIGATIONS LAW OF THE STATE

Exhibit C- 1

EXHIBIT D

Form of Letter of Credit Application

(Attached)

Exhibit D- 1

EXHIBIT E

Credit and Collection Policy

(Attached)

Exhibit E- 1

EXHIBIT F

Form of Information Package

(Attached)

Exhibit F

EXHIBIT G

Form of Compliance Certificate

To: PNC Bank, National Association, as Administrative Agent

This Compliance Certificate is furnished pursuant to Section 8.02(a)(i) of that certain Receivables Financing Agreement, dated as of December 5, 2014 among AROP Funding, LLC (the “Borrower”), Alliance Coal, LLC, as Servicer (the “Servicer”), the Lenders party thereto, the LC Participants party thereto and PNC Bank, National Association, as Administrative Agent (in such capacity, the “Administrative Agent”) and as the LC Bank (as amended, supplemented or otherwise modified from time to time, the “Agreement”).  Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to them in the Agreement.

THE UNDERSIGNED HEREBY CERTIFIES THAT:

1.I am the duly elected ________________of the Servicer.

2.I have reviewed the terms of the Agreement and each of the other Transaction Documents and I have made, or have caused to be made under my supervision, a detailed review of the transactions and condition of the Borrower during the accounting period covered by the attached financial statements.

3.The examinations described in paragraph 2 above did not disclose, and I have no knowledge of, the existence of any condition or event which constitutes an Event of Default or an Unmatured Event of Default, as each such term is defined under the Agreement, during or at the end of the accounting period covered by the attached financial statements or as of the date of this Certificate[, except as set forth in paragraph 5 below].

4.Schedule I attached hereto sets forth financial statements of the Parent and its Subsidiaries for the period referenced on such Schedule I.

[5.Described below are the exceptions, if any, to paragraph 3 above by listing, in detail, the nature of the condition or event, the period during which it has existed and the action which Borrower has taken, is taking, or proposes to take with respect to each such condition or event:]

Exhibit G-1

SCHEDULE I TO COMPLIANCE CERTIFICATE

A.Schedule of Compliance as of ___________________, 20__ with Section 8.02(a) of the Agreement.  Unless otherwise defined herein, the terms used in this Compliance Certificate have the meanings ascribed thereto in the Agreement.

This schedule relates to the month ended: __________________.

B.The following financial statements of the Parent and its Subsidiaries for the period ending on ______________, 20__, are attached hereto:

Exhibit G-3

EXHIBIT H

Closing Memorandum

(Attached)

Exhibit H

EXHIBIT I-1

Weekly Report

Exhibit I-1

EXHIBIT I-2

Daily Report

Schedule I-2

SCHEDULE I

Commitments

Party	Capacity	Commitment
PNC	Lender	$100,000,00060,000,000
PNC	LC Participant	$100,000,00060,000,000
PNC	LC Bank	$100,000,00060,000,000

Schedule I-2

SCHEDULE II

Lock-Boxes, Lock-Box Accounts and Lock-Box Banks

Lock-Box Bank	Lock-Box	Lock-Box Account
Fifth Third Bank	633905	07021290650

Schedule II- 1

SCHEDULE III

Notice Addresses

(A)in the case of the Borrower, at the following address:

1717 South Boulder Avenue

Tulsa, Oklahoma 74119

Facsimile: 918-295-7361

Attn: Cary P. Marshall

with a copy to:

1146 Monarch St.

Lexington, Kentucky 40513

Facsimile: 859-223-3057

Attn: R. Eberley Davis

(B)in the case of the Servicer, at the following address:

1717 South Boulder Avenue

Tulsa, Oklahoma 74119

Facsimile: 918-295-7361

Attn:  Cary P. Marshall

with a copy to:

1146 Monarch St.

Lexington, Kentucky 40513

Facsimile: 859-223-3057

Attn:  R. Eberley Davis

(C)in the case of the Administrative Agent, at the following address:

PNC Bank, National Association

ThreeThe Tower at PNC Plaza

225300 Fifth Avenue, 11^th Floor

Pittsburgh, PA 15222

Attention: Brian Stanley

Telephone: (412)-768-30902001

Facsimile: (412)-7629184-803-7142

Attention: Robyn Reeher

Email: brian.stanley@pnc.com

ABFAdmin@pnc.com

(D)in the case of the LC Bank, at the following address:

Schedule III- 1

PNC Bank, National Association

ThreeThe Tower at PNC Plaza

225300 Fifth Avenue, 11^th Floor

Pittsburgh, PA 15222

Attention: Brian Stanley

Telephone: (412)-768-30902001

Facsimile: (412)-7629184-803-7142

Attention: Robyn Reeher

Email: brian.stanley@pnc.com

ABFAdmin@pnc.com

(E)in the case of any other Person, at the address for such Person specified in the other Transaction Documents; in each case, or at such other address as shall be designated by such Person in a written notice to the other parties to this Agreement.

Schedule III- 2

SCHEDULE IV

Excluded Receivables

LOCATION OF MINING OPERATIONS

MINEHEAD	STATE	COUNTY
MC Mining	KY	Pike

Schedule IV- 1

SCHEDULE V

Mining Location

[UCC-1 property descriptions to be appended on or prior to February 15, 2021]

Schedule V- 1

EX-21.1

EXHIBIT 21.1

LIST OF SUBSIDIARIES

First Tier Subsidiary:

Alliance Holdings GP, L.P. ("AHGP") (100% limited partnership interest)

Alliance Resource Operating Partners, L.P. ("AROP") (98.9899% limited partner interest)

AllRoy GP, LLC ("AllRoy") (100% membership interest)

New AHGP GP, LLC (100% membership interest)

Second Tier Subsidiaries:

AD Minerals III, LP (AllRoy holds a 100% general partner interest)

AllDale Minerals, LP (AllRoy holds a 0.01% general partner interest; Alliance Royalty holds a 28.33% limited partner interest; Cavalier holds a 71.66% limited partner interest)

AllDale Minerals II, LP (AllRoy holds a 0.01% general partner interest; Alliance Royalty holds a 27.18% limited partner interest; Cavalier holds a 72.81% limited partner interest)

Alliance Coal, LLC ("Alliance Coal") (AROP holds a 99.999% non-managing membership interest)

Alliance Minerals, LLC ("Alliance Minerals") (AROP holds a 100% membership interest)

Alliance Resource Finance Corporation ("Alliance Finance") (AROP holds a 100% membership interest)

Alliance Resource Properties, LLC ("Alliance Resource Properties") (AROP holds a 100% membership interest)

AR Midland, LP (AllRoy holds a 0.01% general partner interest; Alliance Royalty holds a 99.99% limited partner interest)

ARM GP Holdings, Inc. (AHGP holds 100% of the outstanding capital stock)

AROP Funding, LLC (AROP holds a 100% membership interest)

CavMM, LLC (AllRoy holds a 100% membership interest)

MGP II, LLC (AHGP holds 99.999% interest; ARM GP Holdings, Inc. holds 0.001% interest)

UC Coal, LLC ("UC Coal") (AROP holds a 100% membership interest)

Wildcat Insurance, LLC (AROP holds a 100% membership interest)

Third Tier Subsidiaries: (Alliance Coal holds a 100% membership interest in (or holds 100% of the outstanding capital stock of) each of the following third-tier subsidiaries)

Alliance Design Group, LLC

Alliance Land, LLC

Alliance Service, Inc.

Backbone Mountain, LLC

CR Services, LLC

Excel Mining, LLC

Gibson County Coal, LLC

Hamilton County Coal, LLC

Hopkins County Coal, LLC

MC Mining, LLC

Mettiki Coal, LLC

Mettiki Coal (WV), LLC

Mid-America Carbonates, LLC

Mt. Vernon Transfer Terminal, LLC

Penn Ridge Coal, LLC

Pontiki Coal, LLC

River View Coal, LLC

Rough Creek Mining, LLC

Sebree Mining, LLC

Steamport, LLC

Tunnel Ridge, LLC

Warrior Coal, LLC

Webster County Coal, LLC

White County Coal, LLC

Cavalier Minerals JV, LLC (CavMM holds a 0% managing interest; Alliance Minerals holds a 96% non-managing interest)

Alliance Royalty, LLC ("Alliance Royalty") (Alliance Minerals holds a 100% membership interest)

(Alliance Resource Properties holds a 100% membership interest in each of the following third-tier subsidiaries)

ARP Sebree, LLC

ARP Sebree South, LLC

Alliance WOR Properties, LLC

(UC Coal holds a 100% membership interest in each of the following third-tier subsidiaries)

UC Mining, LLC

UC Processing, LLC

Fourth Tier Subsidiaries:

CR Machine Shop, LLC (CR Services, LLC holds a 100% interest)

Matrix Design Group, LLC (Alliance Service, Inc. holds a 100% interest)

WOR Land 6, LLC (Alliance WOR Properties, LLC holds a 100% interest)

Fifth Tier Subsidiary:

Matrix Design International, LLC (Matrix Design Group, LLC holds a 100% interest)

Sixth Tier Subsidiary:

Matrix Design Africa (PTY) LTD (Matrix Design International, LLC holds a 100% interest)

All of the above entities are formed or incorporated, as the case may be, under the laws of the State of Delaware except for the following which are formed or incorporated in the following jurisdictions:

Wildcat Insurance, LLC – Oklahoma

Steamport, LLC – Kentucky

Matrix Design Africa (PTY) LTD – South Africa

AllDale Minerals, LP – Texas

AllDale Minerals II, LP – Texas

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-223171) of Alliance Resource Partners, L.P.,

(2) Registration Statement (Form S-8 No. 333-165168) pertaining to the 2000 Long-Term Incentive Plan of Alliance Coal, LLC, and

(3) Registration Statement (Form S-8 No. 333-85258) pertaining to the Alliance Resource Management GP, LLC Long-Term Incentive Plan, the Supplemental Executive Retirement Plan and the Deferred Compensation Plan for Directors;

of our reports dated February 23, 2021 with respect to the consolidated financial statements and schedule of Alliance Resource Partners, L.P. and the effectiveness of internal control over financial reporting of Alliance Resource Partners, L.P. included in this Annual Report (Form 10-K) of Alliance Resource Partners, L.P. for the year ended December 31, 2020.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 23, 2021

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

Netherland, Sewell & Associates, Inc. has issued an audit letter, as of December 31, 2020, of the Alliance Royalty, LLC estimates of reserves and future revenue in certain oil and gas properties located in the United States.  Netherland, Sewell & Associates, Inc. consents to the reference in Form 10-K to Netherland, Sewell & Associates, Inc.'s audit letter dated January 14, 2021, and to the incorporation by reference of our Firm's name and letter into Alliance's previously filed Registration Statements on Form S-3 (No. 333-223171) and Form S-8 (File No. 333-165168 and 333-85258).

NETHERLAND, SEWELL & ASSOCIATES, INC.
	/s/ C.H. (Scott) Rees III
By:	C.H. (Scott) Rees III, P.E.
	Chairman and Chief Executive Officer

Dallas, Texas

February 23, 2021

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Joseph W. Craft III certify that:

1. I have reviewed this Annual Report on Form 10-K of Alliance Resource Partners, L.P.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d. disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the quarterly period ended December 31, 2020, that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 23, 2021

/s/ Joseph W. Craft III

Joseph W. Craft III

President, Chief Executive

Officer and Chairman

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Brian L. Cantrell, certify that:

1. I have reviewed this Annual Report on Form 10-K of Alliance Resource Partners, L.P.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusion about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this annual report based on such evaluation; and

d. disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the quarterly period ended December 31, 2020, that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting;

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 23, 2021

/s/ Brian L. Cantrell

Brian L. Cantrell

Senior Vice President and

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Alliance Resource Partners, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph W. Craft III, President and Chief Executive Officer of Alliance Resource Management GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

By:	/s/ Joseph W. Craft III
Joseph W. Craft III
President, Chief Executive Officer and Chairman
of Alliance Resource Management GP, LLC
(the general partner of Alliance Resource Partners, L.P.)
Date: February 23, 2021

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate document.  A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Alliance Resource Partners, L.P. (the “Partnership”) on Form 10-K for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian L. Cantrell, Senior Vice President and Chief Financial Officer of Alliance Resource Management GP, LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

By:	/s/ Brian L. Cantrell
Brian L. Cantrell
Senior Vice President and
Chief Financial Officer
of Alliance Resource Management GP, LLC
(the general partner of Alliance Resource Partners, L.P.)
Date: February 23, 2021

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate document.  A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-95.1

EXHIBIT 95.1

Federal Mine Safety and Health Act Information

Our mining operations are subject to extensive and stringent compliance standards established pursuant to the Federal Mine Safety and Health Act of 1977, as amended by the Federal Mine Improvement and New Emergency Response Act of 2006 (as amended, the "Mine Act").  MSHA monitors and rigorously enforces compliance with these standards, and our mining operations are inspected frequently.  Citations and orders are issued by MSHA under Section 104 of the Mine Act for violations of the Mine Act or any mandatory health or safety standard, rule, order or regulation promulgated under the Mine Act.  A Section 104(a) "Significant and Substantial" or "S&S" citation is generally issued in a situation where the conditions created by the violation do not cause imminent danger, but in the opinion of the MSHA inspector could significantly and substantially contribute to the cause and effect of a mine safety or health hazard.  During 2020, our mines were subject to 4,758 MSHA inspection days with an average of only 0.05 S&S citations written per inspection day.

The Mine Act has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without regard to fault.  If, in the opinion of an MSHA inspector, a condition exists that violates the Mine Act or regulations promulgated thereunder, then a citation or order will be issued regardless of whether we had any knowledge of, or fault in, the existence of that condition.  Many of the Mine Act standards include one or more subjective elements, so that issuance of a citation often depends on the opinions or experience of the MSHA inspector involved and the frequency of citations will vary from inspector to inspector.

If we disagree with the assertions of an MSHA inspector, we may exercise our right to challenge those findings by "contesting" the citation or order pursuant to the procedures established by the Mine Act and its regulations.  During 2020, our operating subsidiaries contested approximately 5.7% of all citations and 23.7% of S&S citations issued by MSHA inspectors.  These contest proceedings frequently result in the dismissal or modification of previously issued citations, substantial reductions in the penalty amounts originally assessed by MSHA, or both.

The Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Act") requires issuers to include in periodic reports filed with the SEC certain information relating to citations or orders for violations of standards under the Mine Act.  The following tables include information required by the Dodd-Frank Act for the twelve months ended December 31, 2020.  The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein.  Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors.

						Total Dollar Value of
	Section 104(a)	Section	Section 104(d)	Section	Section	MSHA Assessments
Subsidiary Name / MSHA	S&S	104(b)	Citations and	110(b)(2)	107(a)	Proposed
Identification Number (1)	Citations(2)	Orders (3)	Orders (4)	Violations (5)	Orders (6)	(in thousands) (7)
Illinois Basin Operations
Webster County Coal, LLC (KY)
1502132	-	-	-	-	-	$	0.2
1511935	-	-	-	-	-	$	-
Warrior Coal, LLC (KY)
1505230	-	-	-	-	-	$	-
1512083	-	-	-	-	-	$	-
1513514	-	-	-	-	-	$	-
1516460	-	-	-	-	-	$	-
1517216	80	-	-	-	-	$	151.3
1517232	-	-	-	-	-	$	-
1517678	-	-	-	-	-	$	-
1517740	-	-	-	-	-	$	-
1517758	-	-	-	-	-	$	-
1514335	-	-	-	-	-	$	0.8
Hopkins County Coal, LLC (KY)
1502013	-	-	-	-	-	$	-
1517377	-	-	-	-	-	$	-
1517515	-	-	-	-	-	$	-
1518826	-	-	-	-	-	$	-
1517378	-	-	-	-	-	$	-
River View Coal, LLC (KY)
1503178	8	-	-	-	-	$	13.7
1519374	99	-	-	-	-	$	189.7
White County Coal, LLC (IL)
1102662	-	-	-	-	-	$	-
1103058	-	-	-	-	-	$	-
Hamilton County Coal, LLC (IL)
1103242	2	-	-	-	-	$	1.5
1103203	10	-	-	-	-	$	19.1
Gibson County Coal, LLC (IN)
1202388	3	-	-	-	-	$	17.3
1202215	-	-	-	-	-	$	0.1
1202494	1	-	-	-	-	$	0.7
Sebree Mining, LLC (KY)
1519264	-	-	-	-	-	$	-
1518547	-	-	-	-	-	$	-
1517044	-	-	-	-	-	$	-
Appalachia Operations
MC Mining, LLC (KY)
1508079	-	-	-	-	-	$	-
1517733	2	-	-	-	-	$	1.2
1519515	1	-	-	-	-	$	8.5
1519838	16	-	-	-	-	$	11.8
Mettiki Coal, LLC (MD)
1800621	-	-	-	-	-	$	-
1800671	1	-	-	-	-	$	0.4
1800761	-	-	-	-	-	$	-
Mettiki Coal (WV), LLC
4609028	13	-	-	-	-	$	46.2
Tunnel Ridge, LLC (PA/WV)
4608864	9	-	-	-	-	$	20.9
Other
4403236	-	-	-	-	-	$	-
4403255	-	-	-	-	-	$	-
4406630	-	-	-	-	-	$	-
4406867	-	-	-	-	-	$	-
1502709	-	-	-	-	-	$	-
Mid-America Carbonates, LLC (IL)
1103176	-	-	-	-	-	$	1.8

	Total	Received Notice	Legal	Legal	Legal
	Number of	of Pattern of	Actions	Actions	Actions
	Mining	Violations Under	Pending as of	Initiated	Resolved
Subsidiary Name / MSHA	Related	Section 104(e)	Last Day of	During	During
Identification Number (1)	Fatalities	(yes/no) (8)	Period	Period	Period
Illinois Basin Operations
Webster County Coal, LLC (KY)
1502132	-	No	-	3	4
1511935	-	No	-	-	-
Warrior Coal, LLC (KY)
1505230	-	No	-	-	-
1512083	-	No	-	-	-
1513514	-	No	-	-	-
1516460	-	No	-	-	-
1517216	1	No	3	12	11
1517232	-	No	-	-	-
1517678	-	No	-	-	-
1517740	-	No	-	-	-
1517758	-	No	-	-	-
1514335	-	No	-	1	1
Hopkins County Coal, LLC (KY)
1502013	-	No	-	-	-
1517377	-	No	-	-	-
1517515	-	No	-	-	-
1518826	-	No	-	-	-
1517378	-	No	-	-	-
River View Coal, LLC (KY)
1503178	-	No	-	1	2
1519374	-	No	3	9	9
White County Coal, LLC (IL)
1102662	-	No	-	-	-
1103058	-	No	-	-	-
Hamilton County Coal, LLC (IL)
1103242	-	No	-	-	-
1103203	-	No	-	1	9
Gibson County Coal, LLC (IN)
1202388	-	No	-	3	6
1202215	-	No	-	-	2
1202494	-	No	-	-	-
Sebree Mining, LLC (KY)
1519264	-	No	-	-	-
1518547	-	No	-	-	-
1517044	-	No	-	-	-
Appalachia Operations
MC Mining, LLC (KY)
1508079	-	No	-	-	-
1517733	-	No	-	-	-
1519515	-	No	-	-	1
1519838	-	No	-	-	-
Mettiki Coal, LLC (MD)
1800621	-	No	-	-	-
1800671	-	No	-	-	-
1800761	-	No	-	-	-
Mettiki Coal (WV), LLC
4609028	-	No	2	5	4
Tunnel Ridge, LLC (PA/WV)
4608864	-	No	-	2	2
Other
4403236	-	No	-	-	-
4403255	-	No	-	-	-
4406630	-	No	-	-	-
4406867	-	No	-	-	-
Mid-America Carbonates, LLC (IL)
1103176	-	No	1	1	-

The number of legal actions pending before the Federal Mine Safety and Health Review Commission as of December 31, 2019 that fall into each of the following categories is as follows:

				Complaints of	Applications
	Contests of	Contests of	Complaints	Discharge/	for	Appeals of
Subsidiary Name / MSHA	Citations	Proposed	for	Discrimination	Temporary	Judges
Identification Number (1)	and Orders	Penalties (9)	Compensation	/Interference	Relief	Rulings
Illinois Basin Operations
Webster County Coal, LLC (KY)
1502132	-	-	-	-	-	-
1511935	-	-	-	-	-	-
Warrior Coal, LLC (KY)
1505230	-	-	-	-	-	-
1512083	-	-	-	-	-	-
1513514	-	-	-	-	-	-
1516460	-	-	-	-	-	-
1517216	-	3	-	-	-	-
1517232	-	-	-	-	-	-
1517678	-	-	-	-	-	-
1517740	-	-	-	-	-	-
1517758	-	-	-	-	-	-
1514335	-	-	-	-	-	-
Hopkins County Coal, LLC (KY)
1502013	-	-	-	-	-	-
1517377	-	-	-	-	-	-
1517515	-	-	-	-	-	-
1518826	-	-	-	-	-	-
1517378	-	-	-	-	-	-
River View Coal, LLC (KY)
1503178	-	-	-	-	-	-
1519374	-	3	-	-	-	-
White County Coal, LLC (IL)
1102662	-	-	-	-	-	-
1103058	-	-	-	-	-	-
Hamilton County Coal, LLC (IL)
1103242	-	-	-	-	-	-
1103203	-	-	-	-	-	-
Gibson County Coal, LLC (IN)
1202388	-	-	-	-	-	-
1202215	-	-	-	-	-	-
1202494	-	-	-	-	-	-
Sebree Mining, LLC (KY)
1519264	-	-	-	-	-	-
1518547	-	-	-	-	-	-
1517044	-	-	-	-	-	-
Appalachia Operations
MC Mining, LLC (KY)
1508079	-	-	-	-	-	-
1517733	-	-	-	-	-	-
1519515	-	-	-	-	-	-
1519838	-	-	-	-	-	-
Mettiki Coal, LLC (MD)
1800621	-	-	-	-	-	-
1800671	-	-	-	-	-	-
1800761	-	-	-	-	-	-
Mettiki Coal (WV), LLC
4609028	-	2	-	-	-	-
Tunnel Ridge, LLC (PA/WV)
4608864	-	-	-	-	-	-
Other
4403236	-	-	-	-	-	-
4403255	-	-	-	-	-	-
4406630	-	-	-	-	-	-
4406867	-	-	-	-	-	-
Mid-America Carbonates, LLC (IL)
1103176	-	1	-	-	-	-

(1) The statistics reported for each of our subsidiaries listed above are segregated into specific MSHA identification numbers.  

(2) Mine Act section 104(a) S&S citations shown above are for alleged violations of mandatory health or safety standards that could significantly and substantially contribute to a coal mine health and safety hazard.  It should be noted that, for purposes of this table, S&S citations that are included in another column, such as Section 104(d) citations, are not also included as Section 104(a) S&S citations in this column.  

(3) Mine Act section 104(b) orders are for alleged failures to totally abate a citation within the time period specified in the citation.

(4) Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with mandatory health or safety standards.

(5) Mine Act section 110(b)(2) violations are for an alleged "flagrant" failure (i.e., reckless or repeated) to make reasonable efforts to eliminate a known violation of a mandatory safety or health standard that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury.

(6) Mine Act section 107(a) orders are for alleged conditions or practices which could reasonably be expected to cause death or serious physical harm before such condition or practice can be abated and result in orders of immediate withdrawal from the area of the mine affected by the condition.

(7) Amounts shown include assessments proposed by MSHA during the twelve months ended December 31, 2020 on all citations and orders, including those citations and orders that are not required to be included within the above chart.

(8) Mine Act section 104(e) written notices are for an alleged pattern of violations of mandatory health or safety standards that could significantly and substantially contribute to a coal mine safety or health hazard.

(9) Pursuant to the Procedural Rules of the Federal Mine Safety and Health Review Commission, mine operators may contest the underlying validity and fact of an alleged citation or order, as well as any special findings of an alleged citation or order, including a significant and substantial or unwarrantable failure designation, as part of any proceeding contesting a proposed penalty assessment.

EX-99.1

Exhibit 99.1

	EXECUTIVE COMMITTEE ROBERT C. BARG P. SCOTT FROST JOHN G. HATTNER JOSEPH J. SPELLMAN RICHARD B. TALLEY, JR.	CHAIRMAN & CEO C.H. (SCOTT) REES III PRESIDENT & COO DANNY D. SIMMONS
WORLDWIDE PETROLEUM CONSULTANTS ENGINEERING GEOLOGY GEOPHYSICS PETROPHYSICS

January 14, 2021

Mr. Kirk D. Tholen

Alliance Royalty, LLC

1717 South Boulder Avenue, Suite 400

Tulsa, Oklahoma 74119

Dear Mr. Tholen:

In accordance with your request, we have audited the estimates prepared by Alliance Royalty, LLC (Alliance), as of December 31, 2020, of the proved reserves and future revenue to the Alliance royalty interest in certain oil and gas properties located in the United States.  It is our understanding that the proved reserves estimates shown herein constitute approximately 95 percent of all proved reserves owned by Alliance.  We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a).  The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  We completed our audit on or about the date of this letter.  This report has been prepared for Alliance's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Alliance's estimates of the net reserves and future net revenue, as of December 31, 2020, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	4,054.5	1,814.3	19,450.6	167,657.7	86,628.7
Proved Developed Non-Producing	799.8	300.3	2,435.3	30,358.7	18,165.4
Proved Undeveloped	1,947.5	817.5	9,131.2	82,541.2	45,422.6
Total Proved	6,801.8	2,932.0	31,017.0	280,557.6	150,216.6

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate.  Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on an area-by-area basis, some of the estimates of Alliance are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI).  However, in our opinion the estimates shown herein of Alliance's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards.  We are satisfied with the methods and procedures used by Alliance in preparing the December 31, 2020, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Alliance.

2100 ROSS AVENUE, SUITE 2200 DALLAS, TEXAS 75201 PH: 214-969-5401 FAX: 214-969-5411	info@nsai-petro.com
1301 MCKINNEY STREET, SUITE 3200 HOUSTON, TEXAS 77010 PH: 713-654-4950 FAX: 713-654-4951	netherlandsewell.com

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.  Alliance's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Prices used by Alliance are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2020.  For oil and NGL volumes, the average West Texas Intermediate spot price of $39.54 per barrel is adjusted by area for quality, transportation fees, and market differentials.  For gas volumes, the average Henry Hub spot price of $1.985 per MMBTU is adjusted by area for energy content, transportation fees, and market differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $36.95 per barrel of oil, $7.99 per barrel of NGL, and $0.88 per MCF of gas.

Because Alliance owns no working interest in these properties, no operating costs or capital costs would be incurred.  However, estimated operating costs and capital costs have been used to confirm economic producibility and determine economic limits for the properties.  These cost estimates are based on our knowledge of similar wells in the area.  Operating costs and capital costs are not escalated for inflation.  Alliance would not incur any costs due to abandonment, nor would it realize any salvage value for the lease and well equipment.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, estimates of Alliance and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Alliance, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties.  Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up 95 percent of the present worth for the total proved reserves.  In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Alliance with respect to ownership interests, oil and gas production, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production.  However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.  Our audit did not include a review of Alliance's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy that we considered to be appropriate and necessary to establish the conclusions set forth herein.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Alliance, are on file in our office.  The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  Michael F. Krehel, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1998 and has over 15 years of prior industry experience.  William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
			/s/ C.H. (Scott) Rees III
		By:
			C.H. (Scott) Rees III, P.E.
			Chairman and Chief Executive Officer
	/s/ Michael F. Krehel, Jr.		/s/ William J. Knights
By:		By:
	Michael F. Krehel, Jr., P.E. 97142		William J. Knights, P.G. 1532
	Vice President		Vice President
Date Signed: January 14, 2021		Date Signed: January 14, 2021

MFK:LMS

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Feb. 23, 2021	Jun. 30, 2020
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2020
Entity File Number	0-26823
Entity Registrant Name	ALLIANCE RESOURCE PARTNERS LP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-1564280
Entity Address, Address Line One	1717 South Boulder Avenue, Suite 400
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74119
City Area Code	918
Local Phone Number	295-7600
Title of 12(b) Security	Common Units
Trading Symbol	ARLP
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Common Units Outstanding		127,195,219
Entity Public Float			$ 343,214,355
Entity Central Index Key	0001086600
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

XML

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
CURRENT ASSETS:
Cash and cash equivalents	$ 55,574	$ 36,482
Trade receivables	104,579	161,679
Other receivables	3,481	256
Inventories, net	56,407	101,305
Advance royalties	4,168	1,844
Prepaid expenses and other assets	21,565	18,019
Total current assets	245,774	319,585
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost	3,554,090	3,684,008
Less accumulated depreciation, depletion and amortization	(1,753,845)	(1,675,022)
Total property, plant and equipment, net	1,800,245	2,008,986
OTHER ASSETS:
Advance royalties	56,791	52,057
Equity method investments	27,268	28,529
Goodwill	4,373	136,399
Operating lease right-of-use assets	15,004	17,660
Other long-term assets	16,561	23,478
Total other assets	119,997	258,123
TOTAL ASSETS	2,166,016	2,586,694
CURRENT LIABILITIES:
Accounts payable	47,511	80,566
Accrued taxes other than income taxes	25,054	15,768
Accrued payroll and related expenses	28,524	36,575
Accrued interest	5,132	5,664
Workers' compensation and pneumoconiosis benefits	10,646	11,175
Current finance lease obligations	766	8,368
Current operating lease obligations	1,854	3,251
Other current liabilities	21,919	21,062
Current maturities, long-term debt, net	73,199	13,157
Total current liabilities	214,605	195,586
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities, net	519,421	768,194
Pneumoconiosis benefits	105,068	94,389
Accrued pension benefit	46,965	44,858
Workers' compensation	47,521	45,503
Non-current asset retirement obligations	121,487	133,018
Long-term finance lease obligations	1,458	2,224
Long-term operating lease obligations	13,078	14,316
Other liabilities	24,146	23,182
Total long-term liabilities	879,144	1,125,684
Total liabilities	1,093,749	1,321,270
ARLP Partners' Capital:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively	1,148,565	1,331,482
Accumulated other comprehensive loss	(87,674)	(77,993)
Total ARLP Partners' Capital	1,060,891	1,253,489
Noncontrolling interest	11,376	11,935
Total Partners' Capital	1,072,267	1,265,424
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 2,166,016	$ 2,586,694

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2020	Dec. 31, 2019
CONDENSED CONSOLIDATED BALANCE SHEETS
Common units outstanding	127,195,219	126,915,597

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
SALES AND OPERATING REVENUES:
Revenues	$ 1,328,129	$ 1,961,720	$ 2,002,857
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)	859,656	1,182,100	1,207,713
Outside coal purchases		23,357	1,466
General and administrative	59,806	72,997	68,298
Depreciation, depletion and amortization	313,387	309,075	280,225
Settlement gain			(80,000)
Asset impairments	24,977	15,190	40,483
Goodwill impairment	132,026	0	0
Total operating expenses	1,410,981	1,702,222	1,630,570
INCOME (LOSS) FROM OPERATIONS	(82,852)	259,498	372,287
Interest expense (net of interest capitalized of $1,325, $1,211 and $1,306, respectively)	(45,613)	(45,875)	(40,218)
Interest income	135	379	159
Equity method investment income	907	2,203	22,189
Equity securities income		12,906	15,696
Acquisition gain		177,043
Other income (expense)	(1,593)	561	(2,621)
INCOME (LOSS) BEFORE INCOME TAXES	(129,016)	406,715	367,492
INCOME TAX EXPENSE (BENEFIT)	35	(211)	22
NET INCOME (LOSS)	(129,051)	406,926	367,470
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST	(169)	(7,512)	(866)
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	(129,220)	399,414	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER			1,560
LIMITED PARTNERS	$ (129,220)	$ 399,414	$ 365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$ (1.02)	$ 3.07	$ 2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC AND DILUTED	127,164,659	128,116,670	130,758,169
Coal sales
SALES AND OPERATING REVENUES:
Revenues	$ 1,232,272	$ 1,762,442	$ 1,844,808
Oil & gas royalties
SALES AND OPERATING REVENUES:
Revenues	42,912	51,735
Transportation revenues
SALES AND OPERATING REVENUES:
Revenues	21,129	99,503	112,385
EXPENSES:
Transportation expenses	21,129	99,503	112,385
Other revenues
SALES AND OPERATING REVENUES:
Revenues	$ 31,816	$ 48,040	$ 45,664

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Interest expense, interest capitalized	$ 1,325	$ 1,211	$ 1,306

XML

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
NET INCOME (LOSS)	$ (129,051)	$ 406,926	$ 367,470
OTHER COMPREHENSIVE INCOME (LOSS):
Total defined benefit pension plan adjustments	(9,681)	(31,122)	5,069
OTHER COMPREHENSIVE INCOME (LOSS)	(9,681)	(31,122)	5,069
COMPREHENSIVE INCOME (LOSS)	(138,732)	375,804	372,539
Less: Comprehensive income attributable to noncontrolling interest	(169)	(7,512)	(866)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO ARLP	(138,901)	368,292	371,673
Defined benefit pension plan
OTHER COMPREHENSIVE INCOME (LOSS):
Amortization of prior service cost	186	186	186
Net actuarial loss	(5,522)	(7,350)	(3,326)
Amortization of net actuarial gain loss	4,128	3,922	3,608
Total defined benefit pension plan adjustments	(1,208)	(3,242)	468
Pneumoconiosis benefits
OTHER COMPREHENSIVE INCOME (LOSS):
Net actuarial loss	(7,787)	(23,298)	4,599
Amortization of net actuarial gain loss	(686)	(4,582)	2
Total defined benefit pension plan adjustments	$ (8,473)	$ (27,880)	$ 4,601

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (129,051)	$ 406,926	$ 367,470
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	313,387	309,075	280,225
Non-cash compensation expense	3,345	11,934	12,114
Asset retirement obligations	4,033	4,087	3,926
Coal inventory adjustment to market	3,245	4,895	1,455
Equity investment income	(907)	(2,203)	(22,189)
Distributions from equity method investments	907	2,203	21,971
Income from equity securities paid-in-kind		(712)	(15,696)
Net loss (gain) on sale of property, plant and equipment	(5,850)	109	(1,285)
Asset impairment	24,977	15,190	40,483
Goodwill impairment	132,026	0	0
Acquisition gain, net		(177,043)
Cash received on redemption of equity securities in excess of investment		(11,482)
Valuation allowance of deferred tax assets	1,151	(413)	(1,560)
Other	6,631	5,677	3,171
Changes in operating assets and liabilities:
Trade receivables	56,172	20,841	6,757
Other receivables	(3,225)	3,726	(249)
Inventories, net	30,522	(35,082)	(747)
Prepaid expenses and other assets	(2,514)	6,136	7,387
Advance royalties	(7,690)	(9,876)	(8,782)
Accounts payable	(24,282)	(17,671)	(813)
Accrued taxes other than income taxes	9,286	(994)	(3,614)
Accrued payroll and related benefits	(8,051)	(6,538)	7,362
Pneumoconiosis benefits	2,340	(2,292)	1,837
Workers' compensation	1,355	3,845	(4,900)
Other	(7,162)	(15,443)	22
Total net adjustments	529,696	107,969	326,875
Net cash provided by operating activities	400,645	514,895	694,345
Property, plant and equipment:
Capital expenditures	(121,101)	(305,858)	(233,480)
Decrease in accounts payable and accrued liabilities	(8,773)	(81)	(1,051)
Proceeds from sale of property, plant and equipment	3,762	1,266	2,409
Contributions to equity method investments			(15,600)
Distributions received from investments in excess of cumulative earnings	988	2,501	2,473
Payments for acquisitions of businesses, net of cash acquired		(320,232)
Cash received from redemption of equity securities		134,288
Net cash used in investing activities	(125,124)	(488,116)	(245,249)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under securitization facility	46,100	184,500	304,600
Payments under securitization facility	(64,000)	(202,700)	(285,000)
Proceeds from equipment financings	14,705	63,086
Payments on equipment financings	(14,805)	(2,607)
Borrowings under revolving credit facilities	70,000	400,000	245,000
Payments under revolving credit facilities	(237,500)	(320,000)	(100,000)
Payments on finance lease obligations	(8,368)	(46,725)	(29,353)
Payment of debt issuance costs	(6,280)
Payments for purchases of units under unit repurchase program		(22,892)	(70,604)
Payments for taxes related to net settlement of issuance of units in deferred compensation plans	(1,310)	(7,817)	(2,081)
cs under deferred compensation plan	(2,490)
Cash contributions by General Partner			41
Cash contribution by affiliated entity			2,142
Cash obtained in Simplification Transactions			1,139
Distributions paid to Partners	(51,753)	(278,425)	(275,902)
Other	(728)	(867)	(1,684)
Net cash used in financing activities	(256,429)	(234,447)	(211,702)
NET CHANGE IN CASH AND CASH EQUIVALENTS	19,092	(207,668)	237,394
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	36,482	244,150	6,756
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 55,574	$ 36,482	$ 244,150

XML

CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL - USD ($) $ in Thousands	Limited Partners' Capital	General Partner's Capital (Deficit)	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest	Total
Balance at beginning of period at Dec. 31, 2017	$ 1,183,219	$ 14,859	$ (51,940)	$ 5,348	$ 1,151,486
Balance at beginning of period (in units) at Dec. 31, 2017	130,704,217
Comprehensive income:
Net income (loss)	$ 365,044	1,560		866	367,470
Actuarially determined long-term liability adjustments			5,069		5,069
COMPREHENSIVE INCOME (LOSS)					372,539
Settlement of deferred compensation plans	$ (2,745)				(2,745)
Settlement of deferred compensation plans (in units)	199,039
Issuance of units to SGP in Exchange Transaction (in units)	20,960
Issuance of units to Owners of SGP in Simplification Transactions	$ 14,742	(15,106)			(364)
Issuance of units to Owners of SGP in Simplification Transactions (in units)	1,322,388
Simplification Transactions fees	$ (96)				(96)
Contribution of units and cash by affiliated entity	$ 2,142				2,142
Contribution of units by affiliated entity (in units)	(467,018)
Purchase of units under unit repurchase program	$ (70,604)				(70,604)
Purchase of units under unit repurchase program (in units)	(3,684,075)
Common unit-based compensation	$ 12,114				12,114
Distributions on deferred common unit-based compensation	(3,855)				(3,855)
General Partners contributions		41			41
Distributions from consolidated company to affiliate noncontrolling interest				(924)	(924)
Distributions to Partners	(270,693)	$ (1,354)			(272,047)
Balance at end of period at Dec. 31, 2018	$ 1,229,268		(46,871)	5,290	1,187,687
Balance at end of period (in units) at Dec. 31, 2018	128,095,511
Comprehensive income:
Net income (loss)	$ 399,414			7,512	406,926
Actuarially determined long-term liability adjustments			(31,122)		(31,122)
COMPREHENSIVE INCOME (LOSS)					375,804
Settlement of deferred compensation plans	$ (7,817)				(7,817)
Settlement of deferred compensation plans (in units)	596,650
Purchase of units under unit repurchase program	$ (22,892)				(22,892)
Purchase of units under unit repurchase program (in units)	(1,776,564)
Common unit-based compensation	$ 11,934				11,934
Distributions on deferred common unit-based compensation	(3,670)				(3,670)
Distributions from consolidated company to affiliate noncontrolling interest				(867)	(867)
Distributions to Partners	(274,755)				(274,755)
Balance at end of period at Dec. 31, 2019	$ 1,331,482		(77,993)	11,935	$ 1,265,424
Balance at end of period (in units) at Dec. 31, 2019	126,915,597				126,915,597
Comprehensive income:
Net income (loss)	$ (129,220)			169	$ (129,051)
Actuarially determined long-term liability adjustments			(9,681)		(9,681)
COMPREHENSIVE INCOME (LOSS)					(138,732)
Settlement of deferred compensation plans	$ (3,800)				(3,800)
Settlement of deferred compensation plans (in units)	279,622
Common unit-based compensation	$ 3,345				3,345
Distributions on deferred common unit-based compensation	(986)				(986)
Distributions from consolidated company to affiliate noncontrolling interest				(728)	(728)
Distributions to Partners	(50,767)				(50,767)
Other	(1,489)				(1,489)
Balance at end of period at Dec. 31, 2020	$ 1,148,565		$ (87,674)	$ 11,376	$ 1,072,267
Balance at end of period (in units) at Dec. 31, 2020	127,195,219				127,195,219

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ORGANIZATION AND PRESENTATION

12 Months Ended

Dec. 31, 2020

ORGANIZATION AND PRESENTATION

ORGANIZATION AND PRESENTATION

1.ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Consolidated Financial Statements

● 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.

Organization

ARLP is a Delaware limited partnership listed on the NASDAQ Global Select Market under the ticker symbol "ARLP."  ARLP was formed in May 1999 and completed its initial public offering on August 19, 1999 when it acquired substantially all of the coal production and marketing assets of Alliance Resource Holdings, Inc., a Delaware corporation ("ARH"), and its subsidiaries. We are managed by our general partner, MGP, a Delaware limited liability company which holds a non-economic general partner interest in ARLP.  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 the transactions.  See discussions under Partnership Simplification regarding changes in ownership of ARLP and MGP as a result of the Simplification Transactions in 2018.

Partnership Simplification

On February 22, 2018, the board of directors ("Board of Directors") of MGP and the board of directors of AGP 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 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.

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 "AllDale Acquisition Date"), we acquired 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") and the general partner interests in AllDale I & II (the "AllDale Acquisition").  As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres in premier oil & gas resource plays.  The AllDale Acquisition provides us with diversified exposure to industry leading operators and is consistent with our general business strategy to grow our Minerals segment. See Note 3 – Acquisitions for more information.

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 enhances our ownership position in the Permian Basin, expands our exposure to industry leading operators and furthers our business strategy to grow our Minerals segment.  Following the Wing Acquisition, we hold approximately 55,700 net royalty acres in premier oil & gas basins including our investment in AllDale Minerals III, LP ("AllDale III").  See Note 3 – Acquisitions for more information.

Presentation

The consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2020 and 2019, and results of our operations, comprehensive income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2020.  All of our intercompany transactions and accounts have been eliminated.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2020

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation—The consolidated financial statements present the consolidated financial position, results of operations and cash flows of ARLP, the Intermediate Partnership, Alliance Coal and other directly and indirectly wholly- and majority-owned subsidiaries of ARLP.  For the periods presented prior to the Simplification Transactions, MGP's interests in both Alliance Coal and the Intermediate Partnership are reported as part of the general partner's interest in the ARLP Partnership's consolidated financial statements.  All intercompany transactions and accounts have been eliminated.  See Note 1 – Organization and Presentation for more information regarding the Simplification Transactions.

Variable Interest Entity ("VIE")—VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. A VIE must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE's primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by other parties. See Note 12 – Variable Interest Entities for further information.

Estimates—The preparation of consolidated financial statements in conformity with generally accepted accounting principles of the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates. Significant estimates and assumptions include:

● Impairment assessments of investments, property, plant and equipment, and goodwill;

● Asset retirement obligations;

● Pension valuation variables;

● Workers' compensation and pneumoconiosis valuation variables;

● Acquisition related purchase price allocations;

● Life of mine assumptions;

● Oil & gas reserve quantities and carrying amounts; and

● Determination of oil & gas revenue accruals

These significant estimates and assumptions are discussed throughout these notes to the consolidated financial statements.

Fair Value Measurements—We apply fair value measurements to certain assets and liabilities.  Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations.  Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid).  Valuation techniques used in our fair value measurements are based upon observable and unobservable inputs.  Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

● Level 1 – Quoted prices for identical assets and liabilities in active markets that we have the ability to access at the measurement date.

● Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

● Level 3 – Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. Significant fair value measurements are used in our significant estimates and are discussed throughout these notes.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less.

Cash Management—The cash flows from operating activities section of our consolidated statements of cash flows reflects immaterial adjustments representing book overdrafts.  We did not have material book overdrafts at December 31, 2020, 2019 and 2018.

Inventories—Coal inventories are stated at the lower of cost or net realizable value on a first-in, first-out basis.  Supply inventories are stated at an average cost basis, less a reserve for obsolete and surplus items.

Business Combinations—For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.

Goodwill—Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead is evaluated for impairment periodically. We evaluate goodwill for impairment annually on November 30th, or more often if events or circumstances indicate that goodwill might be 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. During 2020, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill allocated to our Hamilton reporting unit.  See Note 5 – Goodwill Impairment for more information.  There were no impairments of goodwill during 2019 or 2018.

Property, Plant and Equipment—Expenditures which extend the useful lives of existing plant and equipment assets are capitalized.  Interest costs associated with major asset additions are capitalized during the construction period.  Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred.  Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Land, machinery and equipment under finance lease agreements are capitalized and amortized over the useful lives of the assets given that in each case, ownership transfers at the end of the lease term.  Preparation plants, processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method over a range from 1 to 22 years.  Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the estimated useful lives of the assets, ranging from 1 to 22 years, limited by the remaining estimated life of each mine.  Depreciable lives for buildings, office equipment and improvements range from 1 to 22 years. Gains or losses arising from retirements are included in operating expenses.  Depletion of coal mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage, which equals estimated proven and probable reserves. Therefore, our coal mineral rights are depleted based on only proven and probable reserves. See Oil & Gas Reserve Quantities and Carrying Amounts below for a discussion of our accounting policies for oil & gas properties.

Mine Development Costs—Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized on a units of production method based on the estimated proven and probable reserves.  Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.  The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete.  Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.  

Leases—We lease buildings and equipment under operating lease agreements that provide for the payment of minimum rentals.  We also have noncancelable lease agreements with third parties for land and equipment under finance

lease obligations.  Some of our arrangements within these agreements have both lease and non-lease components, which are generally accounted for separately.  We have elected a practical expedient to account for lease and non-lease components as a single lease component for leases of buildings and office equipment.  Our leases have approximate lease terms of one year to 20 years, some of which include automatic renewals up to ten years which are likely to be exercised, and some of which include options to terminate the lease within one year.  We also hold numerous mineral reserve leases with both related parties as well as third parties, none of which are accounted for as an operating lease or as a finance lease.  

We review each agreement to determine if an arrangement within the agreement contains a lease at the inception of an arrangement.  Once an arrangement is determined to contain either an operating or finance lease with a term greater than 12 months, we recognize a lease liability for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term based on the present value of lease payments over the lease term. The lease term includes all noncancelable periods defined in the lease as well as periods covered by options to extend the lease that we are reasonably certain to exercise.  As an implicit borrowing rate cannot be determined under most of our leases, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments.

Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease term including any reasonably assured renewal periods, while those determined to be finance leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the income statement.  The determination of whether a lease is accounted for as a finance lease or an operating lease requires management to make estimates primarily about the fair value of the asset and its estimated economic useful life.

Long-Lived Asset Impairment—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.  To the extent the carrying amount is not recoverable, the amount of impairment is measured by the difference between the carrying value and the fair value of the asset (See Note 4 – Long-Lived Asset Impairments).

Oil & Gas Reserve Quantities and Carrying Amounts—We are wholly dependent on third-party operators to explore, develop, produce and operate the properties associated with our mineral interests.  We follow the successful efforts method of accounting for our oil & gas mineral interests. Under this method, costs to acquire mineral interests in oil & gas properties are capitalized when incurred. The costs of mineral interests in unproved properties are capitalized pending the results of exploration and leasing efforts by operators. As mineral interests in unproved properties are determined to be proved, the related costs are transferred to proved oil & gas properties.

Mineral interests in oil & gas properties are grouped using a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, which we may also refer to as a depletable group. Mineral interests in proved oil & gas properties are depleted based on the units-of-production method.  Proved reserves are quantities of oil & gas that can be estimated with reasonable certainty to be recoverable in the future from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations.  Proved developed resources are the quantities expected to be recovered through our operators' existing wells with existing equipment, infrastructure and operating methods.

We evaluate impairment of our mineral interests in proved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable group basis. We compare the undiscounted projected future cash flows expected in connection with a depletable group to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable group exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future expenditures, and a risk-adjusted discount rate.

Our mineral interests in unproved properties are also assessed for impairment periodically on a depletable group basis when facts and circumstances indicate that the carrying value may not be recoverable.  Impairment of individual unproved properties whose acquisition costs are relatively significant are assessed on a property-by-property basis, and an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value for the property.  Impairment of unproved properties whose acquisition costs are not individually significant are assessed on a group basis.

Any amount of loss to be recognized and the amount of a valuation allowance needed to provide for impairment of those properties is determined by amortizing those properties in the aggregate on the basis of historical experience and other relevant information, such as the relative proportion of such properties on which proved reserves have been found in the past.  The carrying value of unproved properties, including unleased mineral rights, are determined based on management's assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

Upon the sale of a complete depletable group, the book value thereof, less proceeds or salvage value, are charged to income. Upon the sale or retirement of an aggregation of interests which make up less than a complete depletable group, the proceeds are credited to accumulated depreciation, depletion and amortization, unless doing so would significantly alter the depreciation, depletion and amortization rate of the depletable group, in which case a gain or loss would be recorded.

Intangibles—Intangibles subject to amortization include contracts with covenants not to compete, customer contracts acquired from other parties and mining permits.  Intangibles other than customer contracts are amortized on a straight-line basis over their useful life.  Intangibles for customer contracts are amortized on a per unit basis over the terms of the contracts.  Amortization expense attributable to intangibles was $4.9 million, $9.1 million and $6.9 million for the years ending December 31, 2020, 2019 and 2018, respectively.  Our intangibles are included in Prepaid expenses and other assets and Other long-term assets on our consolidated balance sheets at December 31, 2020 and 2019.  Our intangibles are summarized as follows:

	December 31, 2020						December 31, 2019
			Accumulated		Intangibles,				Accumulated		Intangibles,
	Original Cost		Amortization		Net		Original Cost		Amortization		Net
	(in thousands)
Non-compete agreements	$	—	$	—	$	—	$	9,803	$	(9,440)	$	363
Customer contracts and other		10,623		(5,744)		4,879		32,371		(24,258)		8,113
Mining permits		1,500		(373)		1,127		1,500		(307)		1,193
Total	$	12,123	$	(6,117)	$	6,006	$	43,674	$	(34,005)	$	9,669

Amortization expense attributable to intangible assets is estimated as follows:

Year Ended December 31,		(in thousands)
2021	$	2,831
2022		1,600
2023		647
2024		66
2025		66
Thereafter		795

Investments—Our investments and ownership interests in equity securities without readily determinable fair values in entities in which we do not have a controlling financial interest or significant influence are accounted for using a measurement alternative other than fair value which is historical cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same entity.  Distributions received on those investments are recorded as income unless those distributions are considered a return on investment, in which case the historical cost is reduced.  We accounted for our ownership interests in Kodiak Gas Services, LLC ("Kodiak") as equity securities without readily determinable fair values.  In the first quarter of 2019, Kodiak redeemed our preferred interests and therefore Kodiak ceased to be an equity security investment. See Note 13 – Investments for further discussion of this investment.    

Our investments and ownership interests in entities in which we do not have a controlling financial interest are accounted for under the equity method of accounting if we have the ability to exercise significant influence over the entity.  Investments accounted for under the equity method are initially recorded at cost, and the difference between the basis of our investment and the underlying equity in the net assets of the joint venture at the investment date, if any, is amortized over the lives of the related assets that gave rise to the difference.  

As of December 31, 2020 and 2019, we held an equity method investment in AllDale III through our subsidiary, Alliance Minerals.  Prior to the AllDale Acquisition, our equity method investments also included AllDale I & II, both held through Cavalier Minerals.  AllDale III and AllDale I & II are collectively referred to as the "AllDale Partnerships."  See Note 13 – Investments for further discussion of our equity method investment in AllDale III and Note 3 – Acquisitions for discussion of the AllDale Acquisition.    

We review our investments for impairment whenever events or changes in circumstances indicate a loss in the value of the investment may be other-than-temporary.

Advance Royalties—Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments.  Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset.  As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed.  Our Advance royalties are summarized as follows:

	December 31,
	2020		2019
	(in thousands)
Advance royalties, affiliates (see Note 21 – Related-Party Transactions)	$	48,389	$	41,216
Advance royalties, third-parties		12,570		12,685
Total advance royalties	$	60,959	$	53,901

Asset Retirement Obligations—Our coal mining operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan.  We record a liability for the fair value of the estimated cost of future mine asset retirement and closing procedures, escalated for inflation then discounted, on a present value basis in the period 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.  Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time.  The depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets. 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.  Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis.  See Note 19 – Asset Retirement Obligations for more information.

Pension Benefits—The funded status of our pension benefit plan is recognized separately in our consolidated balance sheets as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan's benefit obligation. Pension obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates including expected return on assets, discount rates, mortality assumptions, employee turnover rates and retirement dates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary (See Note 16 – Employee Benefit Plans).

The discount rate is determined for our pension benefit plan based on an approach specific to our plan. The year end discount rate is determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows.

The expected long-term rate of return on plan assets is determined based on broad equity and bond indices, the investment goals and objectives, the target investment allocation and on the average annual total return for each asset class.

Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive loss until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants' average remaining future years of service.  

Workers' Compensation and Pneumoconiosis (Black Lung) Benefits—We are liable for workers' compensation benefits for traumatic injuries and benefits for black lung disease (or pneumoconiosis).  Both traumatic claims and pneumoconiosis benefits are covered through our self-insured programs.  In addition, certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis benefits to eligible employees and former employees and their dependents.  

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.  Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial 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.

Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis obligation.  Our actuarial calculations are based on numerous assumptions including claim development patterns, medical costs and mortality.  Actuarial gains or losses are amortized over the remaining service period of active miners.  See Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for more information on Workers' Compensation and Pneumoconiosis Benefits.

Coal Revenue Recognition—Revenues from coal supply contracts with customers, which primarily relate to sales of thermal coal, are recognized at the point in time when control of the coal passes to the customer.  We have determined that each ton of coal represents a separate and distinct performance obligation.  Our coal supply contracts and other revenue contracts vary in length from short-term to long-term sales contracts and do not typically have significant financing components.  Transportation revenues represent the fulfillment costs incurred for the services provided to customers through third-party carriers and for which we are directly reimbursed.  Other revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, other coal contract fees and other handling and service fees.  Performance obligations under these contracts are typically satisfied upon transfer of control of the goods or services to our customer which is determined by the contract and could be upon shipment or upon delivery.  

The estimated transaction price from each of our contracts is based on the total amount of consideration we expect to be entitled to under the contract.  Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services, government imposition claims, per ton price fluctuations based on certain coal sales price indices and anticipated payments in lieu of shipments.  We have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.  The estimated transaction price for each contract is allocated to our performance obligations based on relative standalone selling prices determined at contract inception.  Variable consideration is allocated to a specific part of the contract in many instances, such as if the variable consideration is based on production activities for coal delivered during a certain period or the outcome of a customer's ability to accept coal shipments over a certain period.

Contract assets are recorded as trade receivables and reported separately in our consolidated balance sheet from other contract assets as title passes to the customer and our right to consideration becomes unconditional.  Payments for coal shipments are typically due within two to four weeks of performance.  We typically do not have material contract assets that are stated separately from trade receivables as our performance obligations are satisfied as control of the goods or services passes to the customer thereby granting us an unconditional right to receive consideration.  Contract liabilities relate to consideration received in advance of the satisfaction of our performance obligations.  Contract liabilities are recognized as revenue at the point in time when control of the good or service passes to the customer.

Oil & Gas Revenue Recognition—Oil & gas royalty revenues are recognized at the point in time when control of the product is transferred to the purchaser by the lessee and collectability of the sales price is reasonably assured. Oil & gas are priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The royalty we receive is tied to a market index, with certain adjustments based on,

among other factors, whether a well connects to a gathering or transmission line, quality and heat content of the product, and prevailing supply and demand conditions.

We also periodically earn revenue from lease bonuses. We recognize lease bonus revenue when we execute a lease of our mineral interests to exploration and production companies. A lease agreement represents our contract with an operator, which is generally an exploration and production company.  The contract will a) generally transfer the rights to any oil or gas discovered, b) grant us a right to a specified royalty interest from the operator, and c) require the operator to commence drilling and complete operations within a specified time period. Control of the minerals transfers to the operator when the lease agreement is executed.  At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we do not adjust the expected amount of consideration for the effects of any significant financing component.

As a non-operator, we have limited visibility into the timing of when new wells start producing.  In addition, production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices from our properties are estimated and recorded within the Trade receivables line item in our consolidated balance sheets.  Generally, the difference between our estimates and the actual amounts received for oil & gas royalty revenue are immaterial and recorded in the month that payment is received from the third-party purchaser unless new production information is received prior to the payment allowing us to update the estimate recorded.

Common Unit-Based Compensation—We have the Long-Term Incentive Plan ("LTIP") for certain employees and officers of MGP and its affiliates who perform services for us.  As part of the LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance based vesting requirements, entitle the LTIP participant to receive ARLP common units.  Annual grant levels and vesting provisions of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval of the compensation committee of our general partner ("Compensation Committee").  Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests.  If it is not probable that the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant.  Assuming the financial tests are expected to be met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants.  We expect to settle restricted unit grants by delivery of ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants.  We account for forfeitures of non-vested LTIP restricted unit grants as they occur.  As provided under the distribution equivalent rights ("DERs") provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period.  If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid.

We utilize the Supplemental Executive Retirement Plan ("SERP") to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units.  The SERP is administered by the Compensation Committee.

Our directors participate in the MGP Amended and Restated Deferred Compensation Plan for Directors ("Directors' Deferred Compensation Plan"). Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units.  Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units.

For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units.  All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

The fair value of restricted common unit grants under the LTIP, SERP and the Directors' Deferred Compensation Plan are determined on the grant date of the award and recognized as compensation expense on a pro rata basis for LTIP and SERP awards, as appropriate, over the requisite service period. Compensation expense is fully recognized on the grant date for quarterly distributions credited to SERP accounts and Directors' Deferred Compensation Plan awards. The corresponding liability is classified as equity and included in limited partners' capital in the consolidated financial statements (See Note 17 – Compensation Plans).

Income Taxes—We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code.  Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in our consolidated financial statements.  Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in our partnership is not available to us. We have certain subsidiaries that are subject to federal and state income taxes.  These income taxes are not material to our financial position or results of operations.  

New Accounting Standards Issued and Adopted—In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirement for Fair Value Measurement ("ASU 2018-13").  ASU 2018-13 amended the fair value measurement guidance by removing and modifying certain disclosure requirements, while also adding new disclosure requirements including the requirement to disclose the range and weighted average of significant unobservable inputs used to develop certain Level 3 measurements.  These changes are to be applied prospectively for only the most recent interim or annual period presented in the year of adoption.  We adopted ASU 2018-13 on January 1, 2020.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13").  ASU 2016-13 changes the impairment model for most financial assets and certain other instruments to require the use of a new forward-looking "expected loss" model that generally will result in earlier recognition of allowances for losses.  The new standard provides for the use of a modified retrospective transition method that allows for a cumulative-effect adjustment to retained earnings upon adoption.  The new standard also requires disclosure of significantly more information related to these items.  We adopted ASU 2016-13 on January 1, 2020. Because of the credit profile of our customers, the fact that we do not have a history of credit losses on our financial instruments and the absences of any material expected losses, the adoption of ASU 2016-13 did not have any material impact on our consolidated financial statements.

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ACQUISITIONS

12 Months Ended

Dec. 31, 2020

ACQUISITION

ACQUISITION

3.ACQUISITIONS

AllDale I & II

On the AllDale Acquisition Date, we acquired all of the limited partner interests not owned by Cavalier Minerals in AllDale I & II and the general partner interests in AllDale I & II for $176.2 million, which was funded with cash on hand and borrowings under the Revolving Credit Facility.  As a result of the AllDale Acquisition and our previous investments held through Cavalier Minerals, we acquired control of approximately 43,000 net royalty acres strategically positioned primarily in the core of the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins.  The AllDale Acquisition provides us with diversified exposure to industry leading operators and is consistent with our general business strategy to grow our Minerals segment.  

Because the underlying mineral interests held by AllDale I & II include royalty interests in both producing properties and unproved properties, we have determined that the AllDale Acquisition should be accounted for as a business combination and the underlying assets and liabilities of AllDale I & II should be recorded at their AllDale Acquisition Date fair value on our consolidated balance sheet.

The final total fair value of the cash paid in the AllDale Acquisition and our previous investments were as follows:

	As of January 3, 2019
	(in thousands)
Cash	$	176,205
Previously held investments		307,322
Total	$	483,527

Prior to the AllDale Acquisition Date, we accounted for our investments in AllDale I & II, held through Cavalier Minerals, as equity method investments. The combined fair value of our equity method investments on the AllDale Acquisition Date was $307.3 million.  We re-measured our equity method investments, which had an aggregate carrying value of $130.3 million immediately prior to the AllDale Acquisition.  The re-measurement resulted in a gain of $177.0 million which is recorded in the Acquisition gain line item in our consolidated statements of income.

The following table summarizes the final fair value allocation of assets acquired and liabilities assumed as of the AllDale Acquisition Date:

	(in thousands)
Cash and cash equivalents	$	900
Mineral interests in proved properties		184,032
Mineral interests in unproved properties		291,190
Receivables		9,326
Accounts payable		(1,921)
Net assets acquired	$	483,527

Our previous equity method investments in AllDale I & II were held through Cavalier Minerals.  Bluegrass Minerals Management, LLC ("Bluegrass Minerals") continues to hold a 4% membership interest (the "Bluegrass Interest") as well as a profits interest in Cavalier Minerals as it did before the AllDale Acquisition.  This Bluegrass Interest represents an indirect noncontrolling interest in AllDale I & II.  The AllDale Acquisition Date fair value of the Bluegrass Interest was $12.3 million.  

The fair value of our previous equity method investments, the mineral interests and the Bluegrass Interest were determined using an income approach primarily comprised of discounted cash flow models.  The assumptions used in the discounted cash flow models include estimated production, projected cash flows, forward oil & gas prices and a risk adjusted discount rate.  Certain assumptions used are not observable in active markets, therefore the fair value measurements represent Level 3 fair value measurements.  AllDale I & II's carrying value of the receivables and accounts payable represent their fair value given their short-term nature.  

The amounts of revenue and earnings, exclusive of the acquisition gain, of AllDale I & II included in our consolidated statements of income from the AllDale Acquisition Date through December 31, 2019 are as follows:

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	48,411
Net income		18,543

The following represents our actual and pro forma consolidated revenues and net income for the year ended December 31, 2018. Pro forma revenues and net income assumes AllDale I & II had been included in our consolidated results since January 1, 2018.  These amounts have been calculated after applying our accounting policies.  Pro forma information is not necessary for the year ended December 31, 2019 as the AllDale Acquisition occurred at the beginning of 2019.  Additionally, our pro forma results have been adjusted to remove the effect of our past equity method investments in AllDale I & II.

	Year Ended
	December 31,
	2018
	(in thousands)
Total revenues
As reported	$	2,002,857
Pro forma		2,042,545
Net income
As reported	$	367,470
Pro forma		358,741

Wing

On August 2, 2019 (the "Wing Acquisition Date"), our subsidiary, AR Midland acquired from Wing approximately 9,000 net royalty acres in the Midland Basin, with exposure to more than 400,000 gross acres, for a cash purchase price of $144.9 million.  The purchase price was funded with cash on hand and borrowings under our Revolving Credit Facility discussed in Note 8 – Long-Term Debt.  The Wing Acquisition enhances our ownership position in the Permian Basin, expands our exposure to industry leading operators and furthers our business strategy to grow our Minerals segment.  Concurrent with the Wing Acquisition, JC Resources LP, an entity owned by Mr. Craft, acquired from Wing, in a separate transaction, mineral interests that we elected not to acquire.

Because the mineral interests acquired in the Wing Acquisition include royalty interests in both producing properties and unproved properties, we have determined that the acquisition should be accounted for as a business combination and the underlying assets should be recorded at fair value as of the Wing Acquisition Date on our consolidated balance sheet. During the year ended December 31, 2020, we recorded adjustments to our mineral interests in proved and unproved properties after receiving additional information regarding proved and unproved reserve quantities, production and projections as of the Wing Acquisition Date.  In addition, we increased our receivables by $0.3 million as a result of information received from operators concerning royalty payments owed to us from production that occurred prior to the Wing Acquisition Date.  

The following table summarizes our final fair value allocation of assets acquired as of the Wing Acquisition Date incorporating measurement period adjustments made to the allocation:

	As Previously
	Reported		Adjustments		Final
			(in thousands)
Mineral interests in proved properties	$	58,084		16,987	$	75,071
Mineral interests in unproved properties		84,976		(17,275)		67,701
Receivables		1,867		288		2,155
Net assets acquired	$	144,927			$	144,927

The fair value of the mineral interests was determined using a weighting of both income and market approaches.  Our income approach primarily comprised 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 weighted average cost of capital.  Our market approach consisted of the observation of recent acquisitions in the Permian Basin to determine a market price for similar mineral interests.  Certain assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  The carrying value of the receivables represents the fair value given the short-term nature of the receivables.

The amounts of revenue and earnings from the mineral interests acquired in the Wing Acquisition included in our consolidated statements of income from the Wing Acquisition Date through December 31, 2019 are as follows:

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	4,625
Net income		1,291

The following represents our actual and pro forma consolidated revenues and net income for the years ended December 31, 2019 and 2018. Pro forma revenues and net income assumes the mineral interests acquired in the Wing Acquisition had been included in our consolidated results since January 1, 2018. These pro forma amounts have been calculated after applying our accounting policies.

	Year Ended
	December 31,
	2019		2018
	(in thousands)
Total revenues
As reported	$	1,961,720	$	2,002,857
Pro forma		1,966,291		2,008,559
Net income
As reported	$	406,926	$	367,470
Pro forma		411,217		372,810

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LONG-LIVED ASSET IMPAIRMENTS

12 Months Ended

Dec. 31, 2020

LONG-LIVED ASSET IMPAIRMENTS

LONG-LIVED ASSET IMPAIRMENTS

4. LONG-LIVED ASSET IMPAIRMENTS

During the year ended December 31, 2020, we recorded $25.0 million of non-cash asset impairment charges in our Illinois Basin segment due to sealing our idled Gibson North mine, resulting in its permanent closure, and a decrease in the fair value of certain mining equipment at our idled operations and greenfield coal reserves as a result of weakened coal market conditions.

During the year ended December 31, 2019, we recorded an asset impairment charge of $15.2 million in our Illinois Basin segment due to the cessation of coal production at our Dotiki mine, effective August 16, 2019, in an effort to focus on maximizing production at our lower-cost mines in the segment. We adjusted the carrying value of Dotiki's assets from $35.9 million to its fair value of $25.8 million and accrued $5.1 million with respect to scheduled payments to WKY CoalPlay for leased coal reserves from which we may not receive future economic benefit.  See Note 12 – Variable Interest Entities for more information about WKY CoalPlay.

During the year ended December 31, 2018, due to the reduction of Dotiki’s economic mine life, we recorded a $34.3 million impairment charge when we adjusted the carrying value of Dotiki's assets from $85.3 million to its fair value of $51.0 million.  We also had a decrease in the fair value of an option entitling us to lease certain coal reserves, which resulted in an impairment charge of $6.2 million.  Both of these impairment charges were incurred in our Illinois Basin segment.

The fair values of the impaired assets were determined using a combination of market and income approaches, both of which represent Level 3 fair value measurements under the fair value hierarchy. The fair value analysis used assumptions of marketability of certain assets as well as discounted cash flows over the remaining life of the assets.

With the uncertainty related to energy demand as a result of weak electricity demand and an oversupply and lack of storage for oil and natural gas during the quarter ended March 31, 2020 (the "First Quarter"), both due in part to the COVID-19 pandemic and other market and production factors impacting both our coal mining operations and our mineral interests activities, we performed recoverability tests during the First Quarter using undiscounted cash flows based on our estimate of sales volume and prices, operating margins and capital expenditures from information available to us and

determined we would be able to recover the costs of our assets, excluding the impaired assets discussed above.  Amid cost reduction efforts, increased customer commitments for coal, a modest recovery in commodity futures prices and increased clarity into production levels by operators of our oil & gas mineral interests during the year, we determined impairment of our long-lived assets subsequent to the First Quarter was not necessary.  The cash flow estimates used in our impairment assessments, by their very nature, are dependent on conditions that could materially change in future periods based on new information.  If in future periods changes to these estimates were to materially reduce our expected cash flows, additional impairments could be necessary.

See Note 2 – Summary of Significant Accounting Policies – Long-Lived Asset Impairment for more information on our accounting policy for asset impairments.

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GOODWILL IMPAIRMENT

12 Months Ended

Dec. 31, 2020

GOODWILL IMPAIRMENT

GOODWILL IMPAIRMENT

5.GOODWILL IMPAIRMENT

At December 31, 2019, our consolidated balance sheet included $136.4 million of goodwill, of which $132.0 million was associated with the reporting unit representing our Hamilton County Coal, LLC ("Hamilton") mine, which is included in our Illinois Basin segment. 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, 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 First 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 an income approach utilizing a discounted cash flow model.  The assumptions used in the discounted cash flow model included estimated production, forward coal prices, operating expenses, capital expenditures and a weighted average cost of capital.  Our forecasts of future cash flows 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. Key assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  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 and as part of our annual impairment evaluation on November 30, 2020, we also performed tests on ARLP's remaining goodwill balances not associated with Hamilton and concluded no impairment was necessary for our other reporting units.

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INVENTORIES

12 Months Ended

Dec. 31, 2020

INVENTORIES

INVENTORIES

6. INVENTORIES

Inventories consist of the following:

	December 31,
	2020		2019
	(in thousands)
Coal	$	19,756	$	63,645
Supplies (net of reserve for obsolescence of $5,547 and $5,555, respectively)		36,651		37,660
Total inventories, net	$	56,407	$	101,305

For the year ended December 31, 2020, we recorded lower of cost or net realizable value adjustments of $3.2 million to our coal inventories as a result of lower coal sale prices and higher cost per ton due to the impact of lower production on our fixed costs per ton in addition to the impact of challenging market conditions on our production levels.  The lower of cost or net realizable value adjustments reflect the impacts of the challenging market conditions and were primarily attributable to the Mettiki and Hamilton mining complexes.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for inventories.

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2020

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT

7.PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consist of the following:

	December 31,
	2020		2019
	(in thousands)
Mining equipment and processing facilities	$	1,896,324	$	1,937,642
Land and coal mineral rights		454,310		453,237
Oil & gas mineral interests (1)		616,904		618,282
Buildings, office equipment and improvements		279,938		304,111
Construction and mine development in progress		25,799		86,876
Mine development costs		280,815		283,860
Property, plant and equipment, at cost		3,554,090		3,684,008
Less accumulated depreciation, depletion and amortization		(1,753,845)		(1,675,022)
Total property, plant and equipment, net	$	1,800,245	$	2,008,986

(1) Oil & gas mineral interests acquired in the AllDale and Wing Acquisitions. See Note 3 – Acquisitions for more information.

At December 31, 2020 and 2019, land and coal mineral rights above include $37.5 million and $40.1 million, respectively, of carrying value associated with coal reserves attributable to properties where we or a third party to which we lease reserves are not currently engaged in mining operations or leasing to third parties, and therefore, the coal reserves are not currently being depleted.  We believe that the carrying value of these coal reserves will be recovered.  

At December 31, 2020 and 2019, our oil & gas mineral interests noted in the table above includes the carrying value of our unproved oil & gas mineral interests totaling $340.5 million and $376.2 million, respectively.  As discussed in Note 2 – Summary of Significant Accounting Policies, we generally do not record depletion expense for our unproved oil & gas mineral interests; however, we do review for impairment as needed throughout the year.

During 2020 and 2019, we incurred $13.1 million and $13.2 million, respectively, in mine development costs, primarily related to the development of our Excel Mine No. 5 at our MC Mining complex.  All past capitalized mine development costs are associated with other mines that shifted to the production phase in past years and we are amortizing these costs accordingly.  We believe that the carrying value of the past development costs will be recovered.  For information regarding long-lived asset impairments please see Note 4 – Long-Lived Asset Impairments.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for property, plant and equipment.

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2020

LONG-TERM DEBT

LONG-TERM DEBT

8.LONG-TERM DEBT

Long-term debt consists of the following:

					Unamortized Discount and
	Principal				Debt Issuance Costs
	December 31,				December 31,
	2020		2019		2020		2019
	(in thousands)
Revolving credit facility	$	87,500	$	255,000	$	(7,196)	$	(3,050)
Senior notes		400,000		400,000		(3,964)		(4,879)
Securitization facility		55,900		73,800		—		—
May 2019 equipment financing		4,956		8,199		—		—
November 2019 equipment financing		42,367		52,281		—		—
June 2020 equipment financing		13,057		—		—		—
		603,780		789,280		(11,160)		(7,929)
Less current maturities		(73,199)		(13,157)		—		—
Total long-term debt	$	530,581	$	776,123	$	(11,160)	$	(7,929)

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 $6.3 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.  

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 Resource Finance Corporation (as co-issuer), a wholly owned subsidiary of the Intermediate Partnership ("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, LLC ("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 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.  Upon 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.

Aggregate maturities of long-term debt are payable as follows:

Year Ended
December 31,	(in thousands)
2021	$	73,199
2022		16,071
2023		24,970
2024		89,540
2025		400,000
	$	603,780

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LEASES

12 Months Ended

Dec. 31, 2020

LEASES

LEASES

9.LEASES

The components of lease expense were as follows:

	December 31,
	2020		2019
	(in thousands)
Finance lease cost:			$
Amortization of right-of-use assets	$	704		14,608
Interest on lease liabilities		377		2,085
Operating lease cost		3,873		9,169
Short-term lease cost		84		464
Variable lease cost		1,375		1,360
Total lease cost	$	6,413	$	27,686

Rental expense was $5.2 million, $11.0 million and $14.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Supplemental cash flow information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3,870		9,124
Operating cash flows for finance leases	$	377		891
Financing cash flows for finance leases	$	8,368		46,725
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	278		25,593

Supplemental balance sheet information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Finance leases:
Property and equipment finance lease assets, gross	$	5,485	$	30,610
Accumulated depreciation		(3,867)		(20,564)
Property and equipment finance lease assets, net	$	1,618	$	10,046

	December 31,
	2020		2019
Weighted average remaining lease term
Operating leases		13.4 years		13.1 years
Finance leases		3.9 years		1.6 years
Weighted average discount rate
Operating leases		6.0 %		6.0 %
Finance leases		8.0 %		6.0 %

Maturities of lease liabilities as of December 31, 2020 were as follows:

	Operating leases		Finance leases
	(in thousands)
2021	$	2,346	$	912
2022		2,245		912
2023		2,061		139
2024		1,841		139
2025		1,527		139
Thereafter		11,838		280
Total lease payments		21,858		2,521
Less imputed interest		(6,926)		(297)
Total	$	14,932	$	2,224

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2020

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

10.FAIR VALUE MEASUREMENTS

The following table summarizes our fair value measurements within the hierarchy not included elsewhere in these notes:

	December 31, 2020						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)
Long-term debt	$	—	$	518,317	$	—	$	—	$	736,206	$	—
Total	$	—	$	518,317	$	—	$	—	$	736,206	$	—

See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding fair value hierarchy levels.

The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued and other liabilities, due from affiliates and due to affiliates approximate fair value due to the short maturity of those instruments.

The estimated fair value of our long-term debt, including current maturities, is based on interest rates that we believe are currently available to us in active markets for issuance of debt with similar terms and remaining maturities (See Note 8 – Long-Term Debt).  The fair value of debt, which is based upon these interest rates, is classified as a Level 2 measurement under the fair value hierarchy.

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PARTNERS' CAPITAL

12 Months Ended

Dec. 31, 2020

PARTNERS' CAPITAL

PARTNERS' CAPITAL

11.PARTNERS' CAPITAL

Distributions

Our available cash that is not used for unit repurchases may, at the discretion of our general partner, be distributed within 45 days after the end of each quarter to unitholders of record.  Available cash is generally defined in the partnership agreement as all cash and cash equivalents on hand at the end of each quarter less reserves established by MGP in its reasonable discretion for future cash requirements.  These reserves are retained to provide for the conduct of our business,

the payment of debt principal and interest and to provide funds for future distributions.  The following table summarizes the quarterly per unit distribution paid during each quarter of 2018 through 2020:

	Year Ended December 31,
	2020		2019		2018
First Quarter	$	0.400	$	0.530	$	0.510
Second Quarter	$	—	$	0.535	$	0.515
Third Quarter	$	—	$	0.540	$	0.520
Fourth Quarter	$	—	$	0.540	$	0.525

In response to the disruptions to the economy and the uncertainty surrounding the COVID-19 pandemic, the Board of Directors of ARLP's general partner began suspending cash distributions to unitholders with the First Quarter and has continued through the quarter ended December 31, 2020.

Simplification Transactions

On May 31, 2018, as part of the Simplification Transactions discussed in Note 1 – Organization and Presentation, ARLP issued 1,322,388 ARLP common units to the Owners of SGP in exchange for causing SGP to contribute to ARLP all of SGP's limited partner interests 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.

The Simplification Transactions are accounted for prospectively as an exchange of equity interests between entities under common control. Since ARLP and AHGP were under common control both before and after the Simplification Transactions, no fair value adjustment was made to the assets or liabilities of AHGP and its subsidiaries and no gain or loss was recognized on our consolidated financial statements.

Unit Repurchase Program

In May 2018, the Board of Directors approved the establishment of a unit repurchase program authorizing us to repurchase and retire 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.  No unit repurchases were made during the year ended December 31, 2020.  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.  

Affiliated Entity Contributions

An affiliated entity controlled by Mr. Craft made a capital contribution of $2.1 million during the year ended December 31, 2018 for the purpose of funding certain general and administrative expenses.  On June 29, 2018, the members of this affiliated entity contributed 467,018 ARLP common units for similar purposes.

Other

The noncontrolling interest in our consolidated balance sheets represents Bluegrass Minerals' ownership interest in Cavalier Minerals.   Our accumulated other comprehensive loss consists of unrecognized actuarial gains and losses as well as unrecognized prior service costs related to our pension and pneumoconiosis benefits.   See Note 12 – Variable Interest Entities, Note 16 –Employee Benefit Plans and Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for further information.

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VARIABLE INTEREST ENTITIES

12 Months Ended

Dec. 31, 2020

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

12.VARIABLE INTEREST ENTITIES

Cavalier Minerals

On November 10, 2014, our subsidiary, Alliance Minerals, and Bluegrass Minerals entered into a limited liability company agreement (the "Cavalier Agreement") to create Cavalier Minerals, which was formed to indirectly acquire oil & gas mineral interests through its ownership in AllDale I & II.  Alliance Minerals owns a 96% member interest in Cavalier Minerals, and Bluegrass Minerals owns a 4% member interest in Cavalier Minerals and a profits interest which entitles it to receive distributions equal to 25% of all distributions (including in liquidation) after all members have recovered their

investment.  Distributions with respect to Bluegrass Minerals' profits interest will be offset by all distributions received by Bluegrass Minerals from the former general partners of AllDale I & II.  To date, there has been no profits interest distribution.  Bluegrass Minerals was Cavalier Minerals' managing member prior to the AllDale Acquisition (see Note 3 – Acquisitions).  In conjunction with the AllDale Acquisition, we became the managing member in Cavalier Minerals.  Total contributions to and cumulative distributions from Cavalier Minerals are as follows:

	Alliance		Bluegrass
	Minerals		Minerals
	(in thousands)
Contributions	$	143,112	$	5,963
Distributions		89,380		3,723

We have concluded that Cavalier Minerals is a VIE which we consolidate as the primary beneficiary because we are the managing member and a substantial equity owner in Cavalier Minerals.  Bluegrass Minerals' equity ownership of Cavalier Minerals is accounted for as noncontrolling ownership interest in our consolidated balance sheets.  In addition, earnings attributable to Bluegrass Minerals are recognized as noncontrolling interest in our consolidated statements of income.

AllDale III

In February 2017, Alliance Minerals committed to directly invest $30.0 million in AllDale III which was created for similar investment purposes as AllDale I & II.  Alliance Minerals completed funding of this commitment in 2018. Alliance Minerals' limited partner interest in AllDale III at December 31, 2020 was 13.9%.

The AllDale III Partnership Agreement includes a 25% profits interest for the general partner, subject to a return hurdle equal to the greater of 125% of cumulative capital contributions and a 10% internal rate of return, and following an 80/20 "catch-up" provision for the general partner.  

Since AllDale III is structured as a limited partnership with the limited partners 1) not having the ability to remove the general partner and 2) not participating significantly in the operational decisions, we concluded that AllDale III is a VIE.  We are not the primary beneficiary of AllDale III as we do not have the power to direct the activities that most significantly impact AllDale III's economic performance.  We account for our ownership interest in the income or loss of AllDale III as an equity method investment.  We record equity income or loss based on AllDale III's distribution structure.  See Note 13 – Investments for more information.

WKY CoalPlay

On November 17, 2014, SGP Land, LLC ("SGP Land"), a wholly owned subsidiary of SGP, and two limited liability companies ("Craft Companies") owned by irrevocable trusts established by Mr. Craft and his children entered into a limited liability company agreement to form WKY CoalPlay, LLC ("WKY CoalPlay").  WKY CoalPlay was formed, in part, to purchase and lease coal reserves.  WKY CoalPlay is managed by one of the Craft Companies.  In December 2014 and February 2015, we entered into various coal reserve leases with WKY CoalPlay.  See Note 21 – Related-Party Transactions for further information on our lease terms with WKY CoalPlay.

We concluded that WKY CoalPlay was a VIE because of our ability to exercise options to acquire reserves under lease with WKY CoalPlay (Note 21 – Related-Party Transactions), which was not within the control of the equity holders and, if it had occurred, could potentially limit the expected residual return to the owners of WKY CoalPlay.  We hold no economic or governance rights related to WKY CoalPlay and our options did not give us any rights to impact WKY CoalPlay's economic performance.  We therefore concluded that we were not the primary beneficiary of WKY CoalPlay.  These options expired in December 2020 and February 2021.  Upon the expiration of these options, WKY CoalPlay ceased to be a VIE.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for variable interest entities.

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INVESTMENTS

12 Months Ended

Dec. 31, 2020

INVESTMENTS

INVESTMENTS

13.INVESTMENTS

AllDale III

As discussed in Note 12 – Variable Interest Entities, we account for our ownership interest in the income or loss of AllDale III as an equity method investment.  We record equity income or loss based on AllDale III's distribution structure.  The changes in our equity method investment in AllDale III for each of the periods presented were as follows:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Beginning balance	$	28,529	$	28,974	$	14,182
Contributions		—		—		15,600
Equity method investment income		907		2,203		547
Distributions received		(1,895)		(2,648)		(1,355)
Other		(273)		—		—
Ending balance	$	27,268	$	28,529	$	28,974

As discussed in Note 4 – Long-Lived Asset Impairments, there was uncertainty related to energy demand in the First Quarter as a result of weak electricity demand and an oversupply and lack of storage for oil and natural gas, both due in part to the COVID-19 pandemic and other market and production factors, which could have impacted our investment in AllDale III.  As a result, as part of our First Quarter impairment assessment, we compared the fair value of our investment to its carrying value and concluded that the fair value exceeded the carrying value and no impairment in our investment was necessary.  In our subsequent impairment assessments, amid a modest recovery in commodity futures prices and increased clarity into production levels by operators during the year, we again compared the fair value of our investment to its carrying value and concluded no impairment was necessary.  To calculate the fair value of the investment we used an income approach utilizing a discounted cash flow model based on our estimate of both production, prices and expenses from information available to us.  Key assumptions used in our valuation are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.  The cash flow estimates used in our assessments, by their very nature, are dependent on conditions that could materially change in future periods based on new information.  If in future periods changes to these estimates were to materially reduce our expected cash flows, an impairment of our investment could be necessary.

Kodiak

On July 19, 2017, Alliance Minerals purchased $100 million of Series A-1 Preferred Interests from Kodiak, a privately-held company providing large-scale, high-utilization gas compression assets to customers operating primarily in the Permian Basin.  This structured investment provided us with a quarterly cash or payment-in-kind return.  On February 8, 2019, Kodiak redeemed our preferred interest for $135.0 million in cash resulting in an $11.5 million gain due to an early redemption premium. The gain is included in the Equity securities income line item.  We no longer hold any ownership interests in Kodiak.  Prior to the redemption, we accounted for our ownership interests in Kodiak as equity securities without readily determinable fair values.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for investments.

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REVENUE FROM CONTRACTS WITH CUSTOMERS

12 Months Ended

Dec. 31, 2020

REVENUE FROM CONTRACTS WITH CUSTOMERS

REVENUE FROM CONTRACTS WITH CUSTOMERS

14.REVENUE FROM CONTRACTS WITH CUSTOMERS

The following table illustrates the disaggregation of our revenues by type, including a reconciliation to our segment presentation as presented in Note 24 – Segment Information.

	Illinois						Other and
	Basin		Appalachia		Minerals		Corporate		Elimination		Consolidated
	(in thousands)
Year Ended December 31, 2020
Coal sales	$	755,208	$	477,064	$	—	$	—	$	—	$	1,232,272
Oil & gas royalties		—		—		42,912		—		—		42,912
Transportation revenues		12,817		8,312		—		—		—		21,129
Other revenues		2,026		14,954		229		25,124		(10,517)		31,816
Total revenues	$	770,051	$	500,330	$	43,141	$	25,124	$	(10,517)	$	1,328,129
Year Ended December 31, 2019
Coal sales	$	1,128,588	$	628,406	$	—	$	22,138	$	(16,690)	$	1,762,442
Oil & gas royalties		—		—		51,735		—		—		51,735
Transportation revenues		94,686		4,817		—		—		—		99,503
Other revenues		13,034		11,166		1,301		34,712		(12,173)		48,040
Total revenues	$	1,236,308	$	644,389	$	53,036	$	56,850	$	(28,863)	$	1,961,720
Year Ended December 31, 2018
Coal sales	$	1,197,143	$	635,530	$	—	$	43,393	$	(31,258)	$	1,844,808
Transportation revenues		106,947		5,435		—		3		—		112,385
Other revenues		16,999		3,000		—		38,096		(12,431)		45,664
Total revenues	$	1,321,089	$	643,965	$	—	$	81,492	$	(43,689)	$	2,002,857

The following table illustrates the amount of our transaction price for all current coal supply contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2020 and disaggregated by segment and contract duration.

							2024 and
	2021		2022		2023		Thereafter		Total
	(in thousands)
Illinois Basin coal revenues	$	653,208	$	253,654	$	187,570	$	140,750	$	1,235,182
Appalachia coal revenues		318,984		95,471		—		—		414,455
Total coal revenues (1)	$	972,192	$	349,125	$	187,570	$	140,750	$	1,649,637

(1) Coal revenues generally consists of consolidated revenues excluding our Minerals segment.

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EARNINGS PER LIMITED PARTNER UNIT

12 Months Ended

Dec. 31, 2020

EARNINGS PER LIMITED PARTNER UNIT

EARNINGS PER LIMITED PARTNER UNIT

15.EARNINGS PER LIMITED PARTNER UNIT

We utilize the two-class method in calculating basic and diluted earnings per limited partner unit ("EPU").  Subsequent to the Simplification Transactions, net income attributable to ARLP is only allocated to limited partners and participating securities under deferred compensation plans.  Net losses attributable to ARLP are allocated to limited partners but not to participating securities.  Prior to the Simplification Transactions, net income attributable to ARLP was allocated to our general partner, limited partners and participating securities under deferred compensation plans in accordance with their respective partnership ownership percentages.  As a result of the Simplification Transactions, MGP no longer holds economic interests in the Intermediate Partnership or Alliance Coal.  We currently do not make distributions or allocate income and losses to MGP in our calculation of EPU.  Please see Note 1 – Organization and Presentation for more information on the Simplification Transactions.

Our participating securities under deferred compensation plans include rights to nonforfeitable distributions or distribution equivalents. Our participating securities are outstanding awards under our LTIP and phantom units in notional accounts under our SERP and the Directors' Deferred Compensation Plan.  

The following is a reconciliation of net income (loss) attributable to ARLP used for calculating basic and diluted earnings per unit and the weighted-average units used in computing EPU.

	Year Ended December 31,
	2020		2019		2018
	(in thousands, except per unit data)
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Adjustment:
General partner's equity ownership (1)		—		—		(1,560)
Limited partners' interest in net income (loss) attributable to ARLP		(129,220)		399,414		365,044
Less:
Distributions to participating securities		—		(4,254)		(5,114)
Undistributed earnings attributable to participating securities		—		(2,237)		(1,641)
Net income (loss) attributable to ARLP available to limited partners	$	(129,220)	$	392,923	$	358,289
Weighted-average limited partner units outstanding – basic and diluted		127,165		128,117		130,758
Earnings per limited partner unit - basic and diluted (2)	$	(1.02)	$	3.07	$	2.74

(1) Amounts presented for periods subsequent to the first quarter of 2018 reflect the impact of the Simplification Transactions, which ended net income allocations and quarterly cash distributions to MGP after May 31, 2018.  Prior to the Simplification Transactions, MGP maintained a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal and thus received quarterly distributions and income and loss allocations during this time period.

(2) Diluted EPU gives effect to all potentially dilutive common units outstanding during the period using the treasury stock method.  Diluted EPU excludes all potentially dilutive units calculated under the treasury stock method if their effect is anti-dilutive.  For the years ended December 31, 2020, 2019 and 2018, the combined total of LTIP, SERP and Directors' Deferred Compensation Plan units of 773,664, 1,284,013 and 1,658,908, respectively, were considered anti-dilutive under the treasury stock method.

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2020

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS

16.EMPLOYEE BENEFIT PLANS

Defined Contribution Plans—Eligible employees currently participate in a defined contribution profit sharing and savings plan ("PSSP") that we sponsor.  The PSSP covers all regular full-time employees.  PSSP participants may elect to make voluntary contributions to this plan up to a specified amount of their compensation. We make matching contributions based on a percent of an employee's eligible compensation and also make an additional non-matching contribution.  Our contribution expense for the PSSP was approximately $16.1 million, $21.1 million and $19.9 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Defined Benefit Plan—Eligible employees and former employees of certain of our mining operations participate in a defined benefit plan (the "Pension Plan") that we sponsor.  The Pension Plan is closed to new applicants.  Participants in the Pension Plan are no longer receiving benefit accruals for service.  Participants can participate in enhanced benefits provisions under the PSSP.  The benefit formula for the Pension Plan is a fixed-dollar unit based on years of service.

The following sets forth changes in benefit obligations and plan assets for the years ended December 31, 2020 and 2019 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements:

	December 31,
	2020		2019
	(dollars in thousands)
Change in benefit obligations:
Benefit obligations at beginning of year	$	136,425	$	118,958
Interest cost		4,185		4,864
Actuarial loss		12,396		17,084
Benefits paid		(5,072)		(4,481)
Benefit obligations at end of year		147,934		136,425
Change in plan assets:
Fair value of plan assets at beginning of year		91,567		75,823
Employer contribution		1,739		5,559
Actual return on plan assets		12,735		14,666
Benefits paid		(5,072)		(4,481)
Fair value of plan assets at end of year		100,969		91,567
Funded status at the end of year	$	(46,965)	$	(44,858)
Amounts recognized in balance sheet:
Non-current liability	$	(46,965)	$	(44,858)
Amounts recognized in accumulated other comprehensive income consists of:
Prior service cost	$	(754)	$	(940)
Net actuarial loss		(46,519)		(45,125)
	$	(47,273)	$	(46,065)
Weighted-average assumption to determine benefit obligations as of December 31,
Discount rate		2.37%		3.15%
Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,
Discount rate		3.15%		4.17%
Expected return on plan assets		6.50%		6.50%

The actuarial loss components of the change in benefit obligations in 2020 and 2019 were primarily attributable to decreases in the discount rate compared to the prior year-end, offset in part by updated mortality tables.  

The expected long-term rate of return used to determine our pension liability is based on a 1.5% active management premium in addition to an asset allocation assumption of:

	Asset allocation
As of December 31, 2020	assumption
Equity securities	62%
Fixed income securities	33%
Real estate	5%
	100%

The actual return on plan assets was 14.2% and 19.2% for the years ended December 31, 2020 and 2019, respectively.

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Components of net periodic benefit cost:
Interest cost	$	4,185	$	4,864	$	4,462
Expected return on plan assets		(5,861)		(4,932)		(5,784)
Amortization of prior service cost		186		186		186
Amortization of net loss		4,128		3,922		3,608
Net periodic benefit cost (1)	$	2,638	$	4,040	$	2,472

(1) Nonservice components of net periodic benefit cost are included in the Other income (expense) line item within our consolidated statements of income.

	Year Ended December 31,
	2020		2019
	(in thousands)
Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive loss:
Net actuarial loss	$	(5,522)	$	(7,350)
Reversal of amortization item:
Prior service cost		186		186
Net actuarial loss		4,128		3,922
Total recognized in accumulated other comprehensive loss		(1,208)		(3,242)
Net periodic benefit cost		(2,638)		(4,040)
Total recognized in net periodic benefit cost and accumulated other comprehensive loss	$	(3,846)	$	(7,282)

Estimated future benefit payments as of December 31, 2020 are as follows:

Year Ended
December 31,	(in thousands)
2021	$	5,629
2022		5,954
2023		6,269
2024		6,488
2025		6,620
2026-2030		34,674
	$	65,634

We expect to contribute $6.5 million to the Pension Plan in 2021.  

The Compensation Committee has appointed an investment manager with full investment authority with respect to Pension Plan investments subject to investment guidelines and compliance with ERISA or other applicable laws.  The investment manager employs a series of asset allocation strategy phases to glide the portfolio risk commensurate with both plan characteristics and market conditions.  The objective of the allocation policy is to reach and maintain fully funded status.  The total portfolio allocation will be adjusted as the funded ratio of the Pension Plan changes and market conditions warrant.  The target allocation includes investments in equity and fixed income commingled investment funds.  Total

account performance is reviewed at least annually, using a dynamic benchmark approach to track investment performance.  General asset allocation guidelines at December 31, 2020 are as follows:

	Percentage of Total Portfolio
	Minimum	Target	Maximum
Equity securities	45%	62%	80%
Fixed income securities	10%	33%	55%
Real estate	0%	5%	10%

Equity securities include domestic equity securities, developed international securities, emerging markets equity securities and real estate investment trust.  Fixed income securities include domestic and international investment grade fixed income securities, high yield securities and emerging markets fixed income securities.  Fixed income futures may also be utilized within the fixed income securities asset allocation.  

The following information discloses the fair values of our Pension Plan assets by asset category:

	December 31,
	2020		2019
	(in thousands)
Cash and cash equivalents (a)	$	3,888	$	2,958
Commingled investment funds measured at net asset value (b):
Equities - Global		17,549		10,028
Equities - United States		31,835		26,812
Equities - United States futures		(2,616)		—
Equities - International developed markets		8,920		10,528
Equities - International developed markets futures		(4,921)		—
Equities - International emerging markets		6,600		8,410
Equities - International emerging markets futures		(975)		—
Fixed income - Investment grade		25,703		26,186
Fixed income - High yield		10,056		—
Fixed income - Emerging markets		2,664		—
Fixed income - Futures		(1,265)		—
Real estate		3,531		4,355
Other		—		2,290
Total	$	100,969	$	91,567

(a) Cash and cash equivalents represents a Level 1 fair value measurement.  See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding the definitions of fair value hierarchy levels.

(b) Investments measured at fair value using the net asset value per share (or its equivalent) have not been classified within the fair value hierarchy.  The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the fund's assets at fair value less liabilities, divided by the number of units outstanding.

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for pension benefits.

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COMMON UNIT-BASED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2020

COMMON UNIT-BASED COMPENSATION PLANS

COMMON UNIT-BASED COMPENSATION PLANS

17.COMMON UNIT-BASED COMPENSATION PLANS

Long-Term Incentive Plan

We maintain the LTIP for certain employees and officers of MGP and its affiliates who perform services for us.  As part of our LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance-based vesting requirements, entitle the LTIP participant to receive ARLP common units.  Annual grant levels and vesting provisions of restricted units for designated participants are

recommended by Mr. Craft, subject to review and approval of the Compensation Committee.  Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests.  If it is not probable the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant.  Assuming the financial tests are met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants.  We expect to settle restricted unit grants by delivery of ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants.  We account for forfeitures of non-vested LTIP restricted unit grants as they occur.  As provided under the DERs provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period. If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid.  

A summary of non-vested LTIP grants of restricted units is as follows:

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Non-vested grants at January 1, 2018	1,694,026	$	19.62	$	33,372
Granted	511,305		20.40
Vested (1)	(331,502)		34.61
Forfeited	(45,749)		17.40
Non-vested grants at December 31, 2018	1,828,080		17.18		31,699
Granted	682,155		18.63
Vested (1)	(885,381)		12.38
Forfeited	(21,476)		20.84
Non-vested grants at December 31, 2019	1,603,378		20.39		17,349
Granted (2)	1,430,489		5.02
Vested (3)	(919,524)		21.70
Grants canceled (4)	(675,302)		18.62
Forfeited	(8,552)		20.16
Non-vested grants at December 31, 2020	1,430,489		5.02		6,409

(1) During the years ended December 31, 2019 and 2018, we issued 596,650 and 191,858, respectively, unrestricted common units to LTIP participants.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.

(2) In December 2020, we modified the vesting requirements for certain restricted units that we granted in February 2020 which were determined to be improbable of vesting under the original vesting requirements (the "2020 Grants"). The new vesting requirements make it probable the modified restricted units will vest.  Also in December 2020, an additional 578,114 restricted units under these modified vesting requirements were granted.  The grant date fair value reflects the modification date fair value for those awards that were modified.

(3) In February 2020, we issued 279,622 unrestricted common units to LTIP participants as a result of satisfying the vesting requirements for 424,486 restricted units that were granted in 2017.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.  In December 2020, we accelerated the vesting requirements for 495,038 restricted units that were granted in 2018 (the "2018 Grants") and settled these restricted units in cash.

(4) In December 2020, 675,302 restricted units that were granted in 2019 (the "2019 Grants") were canceled since it was determined that the vesting requirements for these restricted units were not probable of being satisfied.

For the years ended December 31, 2020, 2019 and 2018, our LTIP expense for grants of restricted units was $8.1 million, $10.4 million and $10.8 million, respectively.  LTIP expense for grants of restricted units for the year ended December 31, 2020 includes the impact of the reversal of the 2019 Grants, the modification of the 2020 Grants and incremental compensation cost associated with the cash settlement of the 2018 Grants.  The cash settlement of the 2018

Grants was the first time we have settled restricted units in cash and we currently do not expect to do so again in the future.  The cash settlement of the 2018 Grants resulted in $5.4 million in incremental compensation cost.  The 2019 Grants were determined to be not probable of vesting therefore $4.8 million of cumulative previously recognized expense was reversed in 2020, offset in part by related DERs for the 2019 Grants previously recorded to equity and then expensed in 2020.  The 2020 Grants were determined to be improbable of vesting therefore the Compensation Committee modified the awards to change the vesting requirement, which made the grants probable of vesting, and granted additional restricted units under these modified vesting requirements as previously discussed.  As a result, the grant date fair value of the modified awards was changed to reflect the modification date fair value of the awards resulting in a net reduction in LTIP expense of $1.0 million for the year ended, December 31, 2020.

The total obligation associated with LTIP grants of restricted units as of December 31, 2020 and 2019 was $1.3 million and $20.2 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets.  As of December 31, 2020, there was $5.8 million in total unrecognized compensation expense related to the non-vested LTIP restricted unit grants that are expected to vest.  That expense is expected to be recognized over a weighted-average period of 2.0 years.

Approximately 1.7 million units remain available under the LTIP for issuance in the future, assuming all grants currently issued and outstanding are settled with common units, without reduction for tax withholding, no future forfeitures occur and DERs are paid in cash versus additional phantom units.

Supplemental Executive Retirement Plan and Directors' Deferred Compensation Plan

We utilize the SERP to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units.  The SERP is administered by the Compensation Committee.

Our directors participate in the Directors' Deferred Compensation Plan. Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units.  Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units.

For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units.  All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

A summary of SERP and Directors' Deferred Compensation Plan activity is as follows:

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Phantom units outstanding as of January 1, 2018	561,784	$	28.64	$	11,067
Granted	84,417		18.78
Issued (1)	(10,364)		27.92
Phantom units outstanding as of December 31, 2018	635,837		27.34		11,025
Granted	111,012		14.50
Issued (1)	(115,484)		25.20
Phantom units outstanding as of December 31, 2019	631,365		25.48		6,831
Granted	129,265		5.25
Phantom units outstanding as of December 31, 2020	760,630		22.04		3,408

(1) During the years ended December 31, 2019 and 2018, we issued ARLP common units of 115,484 and 7,181, respectively, to participants under the SERP and Directors' Deferred Compensation Plan.  Units issued in 2018 were net of units settled in cash to satisfy tax withholding obligations.

Total SERP and Directors' Deferred Compensation Plan expense was $0.7 million, $1.6 million and $1.6 million for the years ended December 31, 2020, 2019 and 2018, respectively.  As of December 31, 2020 and 2019, the total obligation associated with the SERP and Directors' Deferred Compensation Plan was $16.8 million and $16.1 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for unit-based compensation.

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SUPPLEMENTAL CASH FLOW INFORMATION

12 Months Ended

Dec. 31, 2020

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

18.SUPPLEMENTAL CASH FLOW INFORMATION

	Year Ended December 31,
	2020		2019		2018
		(in thousands)
Cash Paid For:
Interest	$	44,226	$	43,093	$	38,450
Income taxes	$	12	$	—	$	34
Non-Cash Activity:
Accounts payable for purchase of property, plant and equipment	$	5,731	$	14,504	$	14,585
Right-of-use assets acquired by operating lease	$	278		25,593		—
Market value of common units issued under deferred compensation plans before tax withholding requirements	$	3,837	$	17,415	$	6,142

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ASSET RETIREMENT OBLIGATIONS

12 Months Ended

Dec. 31, 2020

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

19.ASSET RETIREMENT OBLIGATIONS

The majority of our operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan.  

The following table presents the activity affecting the asset retirement and mine closing liability:

	Year Ended December 31,
	2020		2019
	(in thousands)
Beginning balance	$	137,514	$	137,114
Accretion expense		4,033		4,087
Payments		(1,769)		(2,948)
Allocation of liability associated with acquisitions, mine development and change in assumptions		(11,880)		(739)
Ending balance	$	127,898	$	137,514

For the year ended December 31, 2020, the allocation of liability associated with acquisition, mine development and change in assumptions was a net decrease of $11.9 million.  This net decrease was attributable to lower cost assumptions and completion of certain reclamation obligations across all operations, permit modifications and extension of projected mine life estimates at certain mines, partially offset by acquisition of property with existing reclamation liabilities.  

For the year ended December 31, 2019, the allocation of liability associated with acquisition, mine development and change in assumptions was immaterial.

The impact of discounting our estimated cash flows resulted in reducing the accrual for asset retirement obligations by $102.1 million and $102.9 million at December 31, 2020 and 2019, respectively. Estimated payments of asset retirement obligations as of December 31, 2020 are as follows:

Year Ended
December 31,	(in thousands)
2021	$	6,411
2022		2,723
2023		2,570
2024		3,317
2025		4,601
Thereafter		210,330
Aggregate undiscounted asset retirement obligations		229,952
Effect of discounting		(102,054)
Total asset retirement obligations		127,898
Less: current portion		(6,411)
Non-current asset retirement obligations	$	121,487

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis.  As of December 31, 2020 and 2019, we had approximately $171.1 million and $181.6 million, respectively, in surety bonds outstanding to secure the performance of our reclamation obligations.  

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for asset retirement obligations.

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

12 Months Ended

Dec. 31, 2020

ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

20.ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

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.  Certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents.  Both pneumoconiosis and traumatic claims are covered through our self-insured programs.

The following is a reconciliation of the changes in workers' compensation liability (including current and long-term liability balances):

	December 31,
	2020		2019
	(in thousands)
Beginning balance	$	53,384	$	49,539
Accruals increase		5,146		7,162
Payments		(8,482)		(11,320)
Interest accretion		1,278		1,606
Valuation loss		3,413		6,397
Ending balance	$	54,739	$	53,384

The discount rate used to calculate the estimated present value of future obligations for workers' compensation was 1.95% and 2.81% at December 31, 2020 and 2019, respectively.

The valuation losses in both 2020 and 2019 were primarily attributable to a decrease in the discount rate used to calculate the estimated present value of future obligations as well as unfavorable changes in claims development in their respective years.

As of December 31, 2020 and 2019, we had $95.2 million and $90.2 million, respectively, in surety bonds and letters of credit outstanding to secure workers' compensation obligations.

We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for the particular claim year have been met.  Our workers' compensation liability above is presented on a gross basis and does not include our expected receivables on our insurance policy.  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. Our receivables are included in Other long-term assets on our consolidated balance sheets.

The following is a reconciliation of the changes in pneumoconiosis benefit obligations:

	December 31,
	2020		2019
	(in thousands)
Benefit obligations at beginning of year	$	97,683	$	72,095
Service cost		3,526		2,593
Interest cost		2,998		3,044
Actuarial (gain) loss		7,787		23,298
Benefits and expenses paid		(3,498)		(3,347)
Benefit obligations at end of year	$	108,496	$	97,683

The following is a reconciliation of the changes in the pneumoconiosis benefit obligation recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Net actuarial gain (loss)	$	(7,787)	$	(23,298)	$	4,599
Reversal of amortization item:
Net actuarial (gain) loss		(686)		(4,582)		2
Total recognized in accumulated other comprehensive loss	$	(8,473)	$	(27,880)	$	4,601

The discount rate used to calculate the estimated present value of future obligations for pneumoconiosis benefits was 2.38%, 3.12% and 4.13% at December 31, 2020, 2019 and 2018, respectively.

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Amount recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	40,399	$	31,927	$	4,047

The actuarial loss component of the change in benefit obligations in 2020 was primarily attributable to a) a decrease in the discount rate used to calculate the estimated present value of the future obligations and b) an increase in the assumptions regarding future medical benefits and legal expenses. These components were partially offset in part by favorable demographic changes in the at-risk population.  The actuarial loss component of the change in benefit obligations in 2019 was primarily attributable to a) a decrease in the discount rate used to calculate the estimated present value of the future obligations and b) an increase in Federal and State benefit levels. These components were offset in part by favorable demographic changes in the at-risk population.  

Summarized below is information about the amounts recognized in the accompanying consolidated balance sheets for pneumoconiosis and workers' compensation benefits:

	December 31,
	2020		2019
	(in thousands)
Workers’ compensation claims	$	54,739	$	53,384
Pneumoconiosis benefit claims		108,496		97,683
Total obligations		163,235		151,067
Less current portion		(10,646)		(11,175)
Non-current obligations	$	152,589	$	139,892

Both the pneumoconiosis benefit and workers' compensation obligations were unfunded at December 31, 2020 and 2019.

The pneumoconiosis benefit and workers' compensation expense consists of the following components:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Black lung benefits:
Service cost	$	3,526	$	2,593	$	2,525
Interest cost (1)		2,998		3,044		2,542
Net amortization (1)		(686)		(4,582)		2
Total pneumoconiosis expense		5,838		1,055		5,069
Workers' compensation expense		12,305		17,541		11,270
Net periodic benefit cost	$	18,143	$	18,596	$	16,339

________________________________________

(1) Interest cost and net amortization is included in the Other income (expense) line item within our consolidated statements of income (see Note 2 – Summary of Significant Accounting Policies).

See Note 2 – Summary of Significant Accounting Policies for more information on our accounting policy for workers' compensation and pneumoconiosis benefits.

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RELATED-PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2020

RELATED-PARTY TRANSACTIONS

RELATED-PARTY TRANSACTIONS

21.RELATED-PARTY TRANSACTIONS

We have continuing related-party transactions with MGP and its affiliates.  The Board of Directors and its conflicts committee ("Conflicts Committee") review our related-party transactions that involve a potential conflict of interest between our general partner or its affiliates and ARLP or its subsidiaries or any other partner of ARLP to determine that such transactions are fair and reasonable to ARLP.  As a result of these reviews, the Board of Directors and the Conflicts Committee approved each of the transactions described below that had such potential conflict of interest as fair and reasonable to ARLP.

Affiliate Coal Lease Agreements

The following table summarizes advanced royalties outstanding and related payments and recoupments under our affiliate coal lease agreements:

				WKY CoalPlay
				Towhead		Webster		Henderson		WKY
		SGP/Craft Foundations		Coal		Coal		Coal		CoalPlay
				Henderson						Henderson
		Tunnel		& Union		Webster		Henderson		& Union
		Ridge		Counties, KY		County, KY		County, KY		Counties, KY		Total
		Acquired		Acquired		Acquired		Acquired		Acquired
		2005		December 2014		December 2014		December 2014		February 2015
	(in thousands)
As of January 1, 2018		$	3,000	$	10,684	$	5,356	$	7,566	$	6,387	$	32,993
Payments			—		3,597		2,570		2,520		2,131		10,818
Recoupment			(3,000)		(204)		(31)		—		(36)		(3,271)
Unrecoupable			—		—		(7,895)		—		—		(7,895)
As of December 31, 2018			—		14,077		—		10,086		8,482		32,645
Payments			4,500		3,597		2,568		2,521		2,131		15,317
Recoupment			(3,000)		(1,071)		—		—		(107)		(4,178)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2019			1,500		16,603		—		12,607		10,506		41,216
Payments			3,000		3,597		2,568		2,522		2,132		13,819
Recoupment			(3,000)		(1,022)		—		—		(56)		(4,078)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2020		$	1,500	$	19,178	$	—	$	15,129	$	12,582	$	48,389

SGP/Craft Foundations—In January 2005, we acquired Tunnel Ridge from ARH.  In connection with this acquisition, we assumed a coal lease with SGP.  Under the terms of the lease, Tunnel Ridge is required to pay an annual minimum royalty of $3.0 million.  The lease expires the earlier of January 1, 2033 or upon the exhaustion of the mineable and merchantable leased coal.  Tunnel Ridge incurred $6.1 million, $7.2 million and $6.0 million in earned royalties in 2020, 2019 and 2018 respectively.  As of January 1, 2019 the property subject to this lease is owned by the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation, an undivided one-half interest each (the "Craft Foundations").

WKY CoalPlay—In February 2015, WKY CoalPlay entered into a coal lease agreement with Alliance Resource Properties, LLC ("Alliance Resource Properties") regarding coal reserves located in Henderson and Union Counties, Kentucky. The lease has an initial term of 20 years and provides for earned royalty payments to WKY CoalPlay of 4.0% of the coal sales price and annual minimum royalty payments of $2.1 million. All annual minimum royalty payments are recoupable from future earned royalties. Alliance Resource Properties also was granted an option to acquire the leased reserves at any time during a three-year period beginning in February 2018 for a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in these reserves taking into account payments previously made under the lease (See Note 12 – Variable Interest Entities).

In December 2014, WKY CoalPlay's subsidiaries, Towhead Coal Reserves, LLC and Henderson Coal Reserves, LLC entered into coal lease agreements with Alliance Resource Properties.  The leases have initial terms of 20 years and provide for earned royalty payments of 4.0% of the coal sales price to both and annual minimum royalty payments of $3.6 million and $2.5 million, respectively.  All annual minimum royalty payments for each agreement are recoupable from future earned royalties related to their respective agreements.  Each agreement granted Alliance Resource Properties an option to acquire the leased reserves at any time during a three-year period beginning in December 2017 for a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in the reserves taking into account payments previously made under the leases. These options expired in December 2020. (See Note 12 – Variable Interest Entities).

In December 2014, WKY CoalPlay's subsidiary, Webster Coal Reserves, LLC entered into a coal lease agreement with Alliance Resource Properties.  The lease has an initial term of 7 years and provides for earned royalty payments of 4.0% of the coal sales price and annual minimum payments of $2.6 million.  The agreement grants Alliance Resource Properties an option to acquire the leased reserves at any time during a three year period beginning in December 2017 for

a purchase price that would provide WKY CoalPlay a 7.0% internal rate of return on its investment in the reserves taking into account payments previously made under the lease (See Note 12 – Variable Interest Entities).  In the third quarter of 2019 it was determined that the balance of advanced royalties, the advance royalty payment in 2020 and the remaining advanced royalty payment expected in 2021 totaling $2.6 million, may not be recouped as a result of the reduction of the Dotiki’s economic mine life determined in 2018 and the subsequent ceasing of production in the third quarter of 2019.  We accrued the expected future advance payments and recognized the charge in Asset Impairment expense in the third quarter of 2019.  See Note 4 – Long-Lived Asset Impairments for more information.

Cavalier Minerals– As discussed in Note 12 – Variable Interest Entities, through our subsidiaries, we hold a non-economic managing member interest and a 96% non-managing member interest in Cavalier Minerals and, Bluegrass Minerals, a third party, holds a 4% non-managing member interest and a profits interest.  See Note 13 – Investments for information on payments made and distributions received by Cavalier Minerals.  

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2020

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

22.COMMITMENTS AND CONTINGENCIES

Commitments—We lease buildings and equipment under operating lease agreements that provide for the payment of both minimum and contingent rentals.  We also have noncancelable coal reserve leases as discussed in Note 21 – Related-Party Transactions and noncancelable leases with a third party for equipment under finance lease obligations. For information regarding future minimum lease payments see Note 9 – Leases.

Contractual Commitments—In connection with planned capital projects, we have contractual commitments of approximately $21.0 million at December 31, 2020.  As of December 31, 2020, we had no commitments to purchase coal from external production sources in 2021 and thereafter.

General Litigation—On March 9, 2018, we finalized an agreement with a customer and certain of its affiliates to settle breach of contract litigation we initiated in January 2015.  The agreement provided for a $93.0 million cash payment to us, execution of a new coal supply agreement with the customer, continued export transloading capacity for our Appalachian mines and the acquisition of certain coal reserves for $2.0 million from an affiliate of the customer.  The $93.0 million cash payment we received was the total compensation recorded in our consolidated statements of income for the agreement.  We have paid or accrued in total, $13.0 million of legal fees and associated incentive compensation costs related to this settlement which resulted in a net gain of $80.0 million reflected in the Settlement gain line item in our consolidated statements of income.

Various lawsuits, claims and regulatory proceedings incidental to our business are pending against the ARLP Partnership.  We record an accrual for a potential loss related to these matters when, in management's opinion, such loss is probable and reasonably estimable.  Based on known facts and circumstances, we believe the ultimate outcome of these outstanding lawsuits, claims and regulatory proceedings will not have a material adverse effect on our financial condition, results of operations or liquidity.  However, if the results of these matters were different from management's current opinion and in amounts greater than our accruals, then they could have a material adverse effect.

Other—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.

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CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2020

CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

23.CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

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.  Our sales into the international coal market are considered exports and 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.  No individual country was attributed greater than 10% of total domestic and export tons sold during the years ended December 31, 2020, 2019 and 2018.  

We have significant long-term coal supply agreements, some of which contain prospective price adjustment provisions designed to reflect changes in market conditions, labor and other production costs and, in the infrequent circumstance when the coal is sold other than free on board the mine, changes in transportation rates.  Our major customers are defined as those customers from which we derive at least ten percent of our total revenues, including transportation revenues.  Total revenues from major customers are as follows:

		Year Ended December 31,
	Segment	2020		2019		2018
		(in thousands)
Customer A	Illinois Basin	$	197,379	$	228,500	$	219,115
Customer B	Appalachia		—		213,319		—
Customer C	Illinois Basin		157,271		—		—
Customer D	Illinois Basin/Appalachia		137,785		—		—

Trade accounts receivable from major customers totaled approximately $32.0 million and $26.3 million at December 31, 2020 and 2019, respectively.  Our bad debt experience has historically been insignificant.  Financial conditions of our customers could result in a material change to our bad debt expense in future periods.  The coal supply agreements with these customers expire in 2022 for Customer C and Customer D and 2020 for Customer A.

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SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2020

SEGMENT INFORMATION

SEGMENT INFORMATION

24.SEGMENT INFORMATION

We operate in the United States as 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.  We aggregate multiple operating segments into three reportable segments, Illinois Basin, Appalachia, and Minerals.  We also have an "all other" category referred to as Other and Corporate.  Our 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 two coal segments include seven mining complexes operating in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia and a coal loading terminal in Indiana on the Ohio River.  The Minerals reportable segment aggregates our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins.  The operations within our Minerals reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests.

The Illinois Basin reportable segment includes currently operating mining complexes (a) Gibson County Coal, LLC's ("Gibson") mining complex, which includes the Gibson South mine, (b) the Warrior Coal, LLC ("Warrior") mining complex, (c) the River View Coal, LLC ("River View") mining complex and (d) the Hamilton mining complex. The Illinois Basin reportable segment also includes our currently operating Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") coal loading terminal in Indiana on the Ohio River.

The Illinois Basin reportable segment also includes Mid-America Carbonates, LLC ("MAC")  and other support services as well as non-operating mining complexes (a) Gibson North mine, which ceased production in the fourth quarter of 2019, (b) Webster County Coal, LLC's Dotiki mining complex, which ceased production in August 2019, (c) White County Coal, LLC's Pattiki mining complex, (d) the Hopkins County Coal, LLC mining complex, and (e) Sebree Mining, LLC's mining complex.    

The Appalachia reportable segment includes currently operating mining complexes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining, LLC ("MC Mining") mining complex. The Mettiki mining complex includes Mettiki Coal (WV), LLC's Mountain View mine and Mettiki Coal, LLC's preparation plant.  The Appalachia reportable segment also includes the Penn Ridge assets, which are primarily coal mineral interests.

The Minerals reportable segment includes oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interests in both AllDale III (Note 13 – Investments) and Cavalier Minerals.  AR Midland acquired its mineral interest in the Wing Acquisition (Note 3 – Acquisitions).

Other and Corporate includes marketing and administrative activities, Matrix Design Group, LLC and its subsidiaries ("Matrix Design"), Alliance Design Group, LLC ("Alliance Design") (collectively, Matrix Design and Alliance Design referred to as 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 (see Note 13 – Investments).  In addition, Other and Corporate includes certain Alliance Resource Properties, LLC's 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 and Alliance Finance (both discussed in Note 8 – Long-Term Debt).

In response to the impacts of the COVID-19 pandemic, we announced on March 30, 2020 a temporary cessation of coal production at our River View, Gibson, Hamilton and Warrior mining complexes in our Illinois Basin segment and on April 9, 2020 a temporary cessation of coal production at our MC Mining complex in our Appalachia segment.  Underground production operations resumed in the second quarter of 2020 at each of our mining complexes.  All of our seven mining complexes are now producing coal.  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.  Due to the ongoing and unforeseen impacts of the COVID-19 pandemic, on April 26, 2020, the employment of 116 employees of Gibson and 78 employees of the Hamilton mining complexes was terminated permanently.  In addition to reduced production levels and employment adjustments, we took numerous actions in 2020 to optimize cash flows and preserve liquidity by reducing capital expenditures, working capital, costs and expenses, including adjusting our corporate support structure to better align to current operating levels.

Reportable segment results are presented below.

	Illinois						Other and		Elimination
	Basin		Appalachia		Minerals		Corporate		(1)		Consolidated
	(in thousands)
Year Ended December 31, 2020
Revenues - Outside	$	770,051	$	500,330	$	43,141	$	14,607	$	—	$	1,328,129
Revenues - Intercompany		—		—		—		10,517		(10,517)		—
Total revenues (2)		770,051		500,330		43,141		25,124		(10,517)		1,328,129
Segment Adjusted EBITDA Expense (3)		520,324		319,730		4,106		18,543		(1,454)		861,249
Segment Adjusted EBITDA (4)		236,911		172,288		39,773		6,580		(9,063)		446,489
Total assets		1,018,916		448,567		613,916		477,469		(392,852)		2,166,016
Capital expenditures		48,648		70,960		—		1,493		—		121,101
Year Ended December 31, 2019
Revenues - Outside	$	1,219,618	$	644,389	$	53,036	$	44,677	$	—	$	1,961,720
Revenues - Intercompany		16,690		—		—		12,173		(28,863)		—
Total revenues (2)		1,236,308		644,389		53,036		56,850		(28,863)		1,961,720
Segment Adjusted EBITDA Expense (3)		756,423		423,623		7,811		36,845		(19,806)		1,204,896
Segment Adjusted EBITDA (4)		385,200		215,950		46,997		32,911		(9,057)		672,001
Total assets		1,373,516		500,027		643,213		541,261		(471,323)		2,586,694
Capital expenditures (5)		189,270		111,739		—		4,849		—		305,858
Year Ended December 31, 2018
Revenues - Outside	$	1,289,898	$	643,898	$	—	$	69,061	$	—	$	2,002,857
Revenues - Intercompany		31,191		67		—		12,431		(43,689)		—
Total revenues (2)		1,321,089		643,965		—		81,492		(43,689)		2,002,857
Segment Adjusted EBITDA Expense (3)		796,370		398,243		—		52,321		(35,134)		1,211,800
Segment Adjusted EBITDA (4)		417,773		240,286		21,323		44,864		(8,555)		715,691
Total assets		1,380,912		440,518		161,312		589,010		(177,004)		2,394,748
Capital expenditures		166,468		64,037		—		2,975		—		233,480

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations, coal sales and purchases between operations within different segments, sales of receivables to AROP Funding, financing between segments and insurance premiums paid to Wildcat Insurance.

(2) Revenues included in the Other and Corporate column are primarily attributable to the outside and affiliate revenues at the Matrix Group and coal brokerage activities.  In additions, Other and Corporate includes affiliate revenues for administrative and Wildcat Insurance services.

(3) Segment Adjusted EBITDA Expense includes operating expenses, coal purchases and other income. Transportation expenses are excluded as transportation revenues are recognized in an amount equal to transportation expenses when title passes to the customer.  

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expenses (excluding depreciation, depletion and amortization):

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Segment Adjusted EBITDA Expense	$	861,249	$	1,204,896	$	1,211,800
Outside coal purchases		—		(23,357)		(1,466)
Other income (expense)		(1,593)		561		(2,621)
Operating expenses (excluding depreciation, depletion and amortization)	$	859,656	$	1,182,100	$	1,207,713

(4) Segment Adjusted EBITDA is defined 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.    Consolidated Segment Adjusted EBITDA is reconciled to net income (loss) as follows:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Consolidated Segment Adjusted EBITDA	$	446,489	$	672,001	$	715,691
General and administrative		(59,806)		(72,997)		(68,298)
Depreciation, depletion and amortization		(313,387)		(309,075)		(280,225)
Settlement gain		—		—		80,000
Asset impairments		(24,977)		(15,190)		(40,483)
Goodwill impairment		(132,026)		—		—
Interest expense, net		(45,478)		(45,496)		(40,059)
Acquisition gain		—		177,043		—
Income tax (expense) benefit		(35)		211		(22)
Acquisition gain attributable to noncontrolling interest		—		(7,083)		—
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Noncontrolling interest		169		7,512		866
Net income (loss)	$	(129,051)	$	406,926	$	367,470

.

(5) Capital Expenditures shown exclude the AllDale Acquisition on January 3, 2019 and the Wing Acquisition on August 2, 2019 (Note 3 – Acquisitions).

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2020

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

25.SUBSEQUENT EVENTS

Other than the event described in Note 8, there were no subsequent events.

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SCHEDULE I CONSOLIDATED FINANCIAL INFORMATION OF REGISTRANT

12 Months Ended

Dec. 31, 2020

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT

ALLIANCE RESOURCE PARTNERS, L.P.

CONDENSED BALANCE SHEETS (PARENT)

DECEMBER 31, 2020 AND 2019

(In thousands, except unit data)

	December 31,
	2020		2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,174	$	2,176
Total current assets		2,174		2,176
OTHER ASSETS:
Investments in consolidated subsidiaries		1,146,491		1,329,406
Total other assets		1,146,491		1,329,406
TOTAL ASSETS	$	1,148,665	$	1,331,582
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued taxes other than income taxes	$	100	$	100
Total current liabilities		100		100
Total liabilities		100		100
PARTNERS' CAPITAL:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively		1,148,565		1,331,482
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$	1,148,665	$	1,331,582

See accompanying notes.

CONDENSED STATEMENTS OF OPERATIONS (PARENT)

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands, except unit and per unit data)

	Year Ended December 31,
	2020		2019		2018
EXPENSES:
General and administrative	$	—	$	41	$	30
Total operating expenses		—		41		30
INCOME (LOSS) FROM OPERATIONS		—		(41)		(30)
Interest income		24		34		22
Equity in earnings of consolidated subsidiaries		(129,244)		399,421		366,612
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	$	(129,220)	$	399,414	$	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER	$	—	$	—	$	1,560
LIMITED PARTNERS	$	(129,220)	$	399,414	$	365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$	(1.02)	$	3.07	$	2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED		127,164,659		128,116,670		130,758,169

See accompanying notes.

CONDENSED STATEMENTS OF CASH FLOWS (PARENT)

FOR THE YEARS ENDED DECEMBER 31, 2020, 2019 AND 2018

(In thousands)

	Year Ended December 31,
	2020		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:	$	51,751	$	278,308	$	275,924
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions paid to Partners		(51,753)		(278,425)		(275,902)
Net cash used in financing activities		(51,753)		(278,425)		(275,902)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(2)		(117)		22
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		2,176		2,293		2,271
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,174	$	2,176	$	2,293

See accompanying notes.

NOTES TO FINANCIAL INFORMATION (PARENT)

1.BASIS OF PRESENTATION

In these parent-company-only financial statements, our investment in consolidated subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries and reduced by distributions received from subsidiaries since the date of acquisition.  These parent-company-only financial statements should be read in conjunction with our consolidated financial statements in "Item 8. Financial Statements and Supplementary Data" of this Annual Report on Form 10-K.

2.GUARANTEES

As the parent of the Intermediate Partnership, we are a guarantor of both the Credit Agreement and Senior Notes discussed in "Item 8. Financial Statements and Supplementary Data—Note 8 – Long-Term Debt" of this Annual Report on Form 10-K.  In addition to these guarantees, we have provided guarantees on surety indemnity agreements and financially guaranteed certain coal supply agreements. The duration of these guarantees varies and the maximum undiscounted potential future payment obligation related to these guarantees as of December 31, 2020 is not material.

3.CASH DISTRIBUTIONS RECEIVED

We received distributions of $51.8 million, $278.4 million and $275.9 million from our consolidated subsidiaries during the years ended December 31, 2020, 2019, and 2018, respectively.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2020

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Presentation

Presentation

The consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2020 and 2019, and results of our operations, comprehensive income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2020.  All of our intercompany transactions and accounts have been eliminated.

Consolidation

Consolidation—The consolidated financial statements present the consolidated financial position, results of operations and cash flows of ARLP, the Intermediate Partnership, Alliance Coal and other directly and indirectly wholly- and majority-owned subsidiaries of ARLP.  For the periods presented prior to the Simplification Transactions, MGP's interests in both Alliance Coal and the Intermediate Partnership are reported as part of the general partner's interest in the ARLP Partnership's consolidated financial statements.  All intercompany transactions and accounts have been eliminated.  See Note 1 – Organization and Presentation for more information regarding the Simplification Transactions.

Variable Interest Entity ("VIE")

Variable Interest Entity ("VIE")—VIEs are primarily entities that lack sufficient equity to finance their activities without additional financial support from other parties or whose equity holders, as a group, lack one or more of the following characteristics: (a) direct or indirect ability to make decisions, (b) obligation to absorb expected losses or (c) right to receive expected residual returns. A VIE must be evaluated quantitatively and qualitatively to determine the primary beneficiary, which is the reporting entity that has (a) the power to direct activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE for financial reporting purposes.

To determine a VIE's primary beneficiary, we perform a qualitative assessment to determine which party, if any, has the power to direct activities of the VIE and the obligation to absorb losses and/or receive its benefits. This assessment involves identifying the activities that most significantly impact the VIE's economic performance and determine whether it, or another party, has the power to direct those activities. When evaluating whether we are the primary beneficiary of a VIE, we perform a qualitative analysis that considers the design of the VIE, the nature of our involvement and the variable interests held by other parties. See Note 12 – Variable Interest Entities for further information.

Estimates

Estimates—The preparation of consolidated financial statements in conformity with generally accepted accounting principles of the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. Actual results could differ from those estimates. Significant estimates and assumptions include:

● Impairment assessments of investments, property, plant and equipment, and goodwill;

● Asset retirement obligations;

● Pension valuation variables;

● Workers' compensation and pneumoconiosis valuation variables;

● Acquisition related purchase price allocations;

● Life of mine assumptions;

● Oil & gas reserve quantities and carrying amounts; and

● Determination of oil & gas revenue accruals

These significant estimates and assumptions are discussed throughout these notes to the consolidated financial statements.

Fair Value Measurements

Fair Value Measurements—We apply fair value measurements to certain assets and liabilities.  Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date.  Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations.  Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid).  Valuation techniques used in our fair value measurements are based upon observable and unobservable inputs.  Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our own market assumptions.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

● Level 1 – Quoted prices for identical assets and liabilities in active markets that we have the ability to access at the measurement date.

● Level 2 – Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model derived valuations whose inputs are observable or whose significant value drivers are observable.

● Level 3 – Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability. Significant fair value measurements are used in our significant estimates and are discussed throughout these notes.

Cash and Cash Equivalents

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand and on deposit, including highly liquid investments with maturities of three months or less.

Cash Management

Cash Management—The cash flows from operating activities section of our consolidated statements of cash flows reflects immaterial adjustments representing book overdrafts.  We did not have material book overdrafts at December 31, 2020, 2019 and 2018.

Inventories

Inventories—Coal inventories are stated at the lower of cost or net realizable value on a first-in, first-out basis.  Supply inventories are stated at an average cost basis, less a reserve for obsolete and surplus items.

Business Combinations

Business Combinations—For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value, which in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques.

Goodwill

Goodwill—Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead is evaluated for impairment periodically. We evaluate goodwill for impairment annually on November 30th, or more often if events or circumstances indicate that goodwill might be 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. During 2020, we recognized an impairment charge of $132.0 million consisting of the total carrying amount of goodwill allocated to our Hamilton reporting unit.  See Note 5 – Goodwill Impairment for more information.  There were no impairments of goodwill during 2019 or 2018.

Property, Plant and Equipment

Property, Plant and Equipment—Expenditures which extend the useful lives of existing plant and equipment assets are capitalized.  Interest costs associated with major asset additions are capitalized during the construction period.  Maintenance and repairs that do not extend the useful life or increase productivity of the asset are charged to operating expense as incurred.  Exploration expenditures are charged to operating expense as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Land, machinery and equipment under finance lease agreements are capitalized and amortized over the useful lives of the assets given that in each case, ownership transfers at the end of the lease term.  Preparation plants, processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method over a range from 1 to 22 years.  Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the estimated useful lives of the assets, ranging from 1 to 22 years, limited by the remaining estimated life of each mine.  Depreciable lives for buildings, office equipment and improvements range from 1 to 22 years. Gains or losses arising from retirements are included in operating expenses.  Depletion of coal mineral rights is provided on the basis of tonnage mined in relation to estimated recoverable tonnage, which equals estimated proven and probable reserves. Therefore, our coal mineral rights are depleted based on only proven and probable reserves. See Oil & Gas Reserve Quantities and Carrying Amounts below for a discussion of our accounting policies for oil & gas properties.

Mine Development Costs

Mine Development Costs—Mine development costs are capitalized until production, other than production incidental to the mine development process, commences and are amortized on a units of production method based on the estimated proven and probable reserves.  Mine development costs represent costs incurred in establishing access to mineral reserves and include costs associated with sinking or driving shafts and underground drifts, permanent excavations, roads and tunnels.  The end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete.  Coal extracted during the development phase is incidental to the mine's production capacity and is not considered to shift the mine into the production phase.  

Leases

Leases—We lease buildings and equipment under operating lease agreements that provide for the payment of minimum rentals.  We also have noncancelable lease agreements with third parties for land and equipment under finance

lease obligations.  Some of our arrangements within these agreements have both lease and non-lease components, which are generally accounted for separately.  We have elected a practical expedient to account for lease and non-lease components as a single lease component for leases of buildings and office equipment.  Our leases have approximate lease terms of one year to 20 years, some of which include automatic renewals up to ten years which are likely to be exercised, and some of which include options to terminate the lease within one year.  We also hold numerous mineral reserve leases with both related parties as well as third parties, none of which are accounted for as an operating lease or as a finance lease.  

We review each agreement to determine if an arrangement within the agreement contains a lease at the inception of an arrangement.  Once an arrangement is determined to contain either an operating or finance lease with a term greater than 12 months, we recognize a lease liability for the obligation to make lease payments and a right-of-use asset for the right to use the underlying asset for the lease term based on the present value of lease payments over the lease term. The lease term includes all noncancelable periods defined in the lease as well as periods covered by options to extend the lease that we are reasonably certain to exercise.  As an implicit borrowing rate cannot be determined under most of our leases, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments.

Expenses related to leases determined to be operating leases will be recognized on a straight-line basis over the lease term including any reasonably assured renewal periods, while those determined to be finance leases will be recognized following a front-loaded expense profile in which interest and amortization are presented separately in the income statement.  The determination of whether a lease is accounted for as a finance lease or an operating lease requires management to make estimates primarily about the fair value of the asset and its estimated economic useful life.

Long-Lived Asset Impairment

Long-Lived Asset Impairment—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.  To the extent the carrying amount is not recoverable, the amount of impairment is measured by the difference between the carrying value and the fair value of the asset (See Note 4 – Long-Lived Asset Impairments).

Oil & Gas Reserve Quantities and Carrying Amounts

Oil & Gas Reserve Quantities and Carrying Amounts—We are wholly dependent on third-party operators to explore, develop, produce and operate the properties associated with our mineral interests.  We follow the successful efforts method of accounting for our oil & gas mineral interests. Under this method, costs to acquire mineral interests in oil & gas properties are capitalized when incurred. The costs of mineral interests in unproved properties are capitalized pending the results of exploration and leasing efforts by operators. As mineral interests in unproved properties are determined to be proved, the related costs are transferred to proved oil & gas properties.

Mineral interests in oil & gas properties are grouped using a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, which we may also refer to as a depletable group. Mineral interests in proved oil & gas properties are depleted based on the units-of-production method.  Proved reserves are quantities of oil & gas that can be estimated with reasonable certainty to be recoverable in the future from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations.  Proved developed resources are the quantities expected to be recovered through our operators' existing wells with existing equipment, infrastructure and operating methods.

We evaluate impairment of our mineral interests in proved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable group basis. We compare the undiscounted projected future cash flows expected in connection with a depletable group to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable group exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future expenditures, and a risk-adjusted discount rate.

Our mineral interests in unproved properties are also assessed for impairment periodically on a depletable group basis when facts and circumstances indicate that the carrying value may not be recoverable.  Impairment of individual unproved properties whose acquisition costs are relatively significant are assessed on a property-by-property basis, and an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value for the property.  Impairment of unproved properties whose acquisition costs are not individually significant are assessed on a group basis.

Any amount of loss to be recognized and the amount of a valuation allowance needed to provide for impairment of those properties is determined by amortizing those properties in the aggregate on the basis of historical experience and other relevant information, such as the relative proportion of such properties on which proved reserves have been found in the past.  The carrying value of unproved properties, including unleased mineral rights, are determined based on management's assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

Upon the sale of a complete depletable group, the book value thereof, less proceeds or salvage value, are charged to income. Upon the sale or retirement of an aggregation of interests which make up less than a complete depletable group, the proceeds are credited to accumulated depreciation, depletion and amortization, unless doing so would significantly alter the depreciation, depletion and amortization rate of the depletable group, in which case a gain or loss would be recorded.

Intangibles

Intangibles—Intangibles subject to amortization include contracts with covenants not to compete, customer contracts acquired from other parties and mining permits.  Intangibles other than customer contracts are amortized on a straight-line basis over their useful life.  Intangibles for customer contracts are amortized on a per unit basis over the terms of the contracts.  Amortization expense attributable to intangibles was $4.9 million, $9.1 million and $6.9 million for the years ending December 31, 2020, 2019 and 2018, respectively.  Our intangibles are included in Prepaid expenses and other assets and Other long-term assets on our consolidated balance sheets at December 31, 2020 and 2019.  Our intangibles are summarized as follows:

	December 31, 2020						December 31, 2019
			Accumulated		Intangibles,				Accumulated		Intangibles,
	Original Cost		Amortization		Net		Original Cost		Amortization		Net
	(in thousands)
Non-compete agreements	$	—	$	—	$	—	$	9,803	$	(9,440)	$	363
Customer contracts and other		10,623		(5,744)		4,879		32,371		(24,258)		8,113
Mining permits		1,500		(373)		1,127		1,500		(307)		1,193
Total	$	12,123	$	(6,117)	$	6,006	$	43,674	$	(34,005)	$	9,669

Amortization expense attributable to intangible assets is estimated as follows:

Year Ended December 31,		(in thousands)
2021	$	2,831
2022		1,600
2023		647
2024		66
2025		66
Thereafter		795

Investments

Investments—Our investments and ownership interests in equity securities without readily determinable fair values in entities in which we do not have a controlling financial interest or significant influence are accounted for using a measurement alternative other than fair value which is historical cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same entity.  Distributions received on those investments are recorded as income unless those distributions are considered a return on investment, in which case the historical cost is reduced.  We accounted for our ownership interests in Kodiak Gas Services, LLC ("Kodiak") as equity securities without readily determinable fair values.  In the first quarter of 2019, Kodiak redeemed our preferred interests and therefore Kodiak ceased to be an equity security investment. See Note 13 – Investments for further discussion of this investment.    

Our investments and ownership interests in entities in which we do not have a controlling financial interest are accounted for under the equity method of accounting if we have the ability to exercise significant influence over the entity.  Investments accounted for under the equity method are initially recorded at cost, and the difference between the basis of our investment and the underlying equity in the net assets of the joint venture at the investment date, if any, is amortized over the lives of the related assets that gave rise to the difference.  

As of December 31, 2020 and 2019, we held an equity method investment in AllDale III through our subsidiary, Alliance Minerals.  Prior to the AllDale Acquisition, our equity method investments also included AllDale I & II, both held through Cavalier Minerals.  AllDale III and AllDale I & II are collectively referred to as the "AllDale Partnerships."  See Note 13 – Investments for further discussion of our equity method investment in AllDale III and Note 3 – Acquisitions for discussion of the AllDale Acquisition.    

We review our investments for impairment whenever events or changes in circumstances indicate a loss in the value of the investment may be other-than-temporary.

Advance Royalties, net

Advance Royalties—Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments.  Where royalty payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts expected to be recouped within one year classified as a current asset.  As mining occurs on these leases, the royalty prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated future production. Royalty prepayments estimated to be nonrecoverable are expensed.  Our Advance royalties are summarized as follows:

	December 31,
	2020		2019
	(in thousands)
Advance royalties, affiliates (see Note 21 – Related-Party Transactions)	$	48,389	$	41,216
Advance royalties, third-parties		12,570		12,685
Total advance royalties	$	60,959	$	53,901

Asset Retirement Obligations

Asset Retirement Obligations—Our coal mining operations are governed by various state statutes and the Federal Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing standards. These regulations require, among other things, restoration of property in accordance with specified standards and an approved reclamation plan.  We record a liability for the fair value of the estimated cost of future mine asset retirement and closing procedures, escalated for inflation then discounted, on a present value basis in the period 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.  Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time.  The depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets. 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.  Federal and state laws require bonds to secure our obligations to reclaim lands used for mining and are typically renewable on a yearly basis.  See Note 19 – Asset Retirement Obligations for more information.

Pension Benefits

Pension Benefits—The funded status of our pension benefit plan is recognized separately in our consolidated balance sheets as either an asset or liability. The funded status is the difference between the fair value of plan assets and the plan's benefit obligation. Pension obligations and net periodic benefit costs are actuarially determined and impacted by various assumptions and estimates including expected return on assets, discount rates, mortality assumptions, employee turnover rates and retirement dates. We evaluate our assumptions periodically and make adjustments to these assumptions and the recorded liability as necessary (See Note 16 – Employee Benefit Plans).

The discount rate is determined for our pension benefit plan based on an approach specific to our plan. The year end discount rate is determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows.

The expected long-term rate of return on plan assets is determined based on broad equity and bond indices, the investment goals and objectives, the target investment allocation and on the average annual total return for each asset class.

Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded in accumulated other comprehensive loss until amortized as a component of net periodic benefit cost. Unrecognized actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants' average remaining future years of service.  

Workers' Compensation and Pneumoconiosis (Black Lung) Benefits

Workers' Compensation and Pneumoconiosis (Black Lung) Benefits—We are liable for workers' compensation benefits for traumatic injuries and benefits for black lung disease (or pneumoconiosis).  Both traumatic claims and pneumoconiosis benefits are covered through our self-insured programs.  In addition, certain of our mine operating entities are liable under state statutes and the Federal Coal Mine Health and Safety Act of 1969, as amended, to pay pneumoconiosis benefits to eligible employees and former employees and their dependents.  

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.  Our liability for traumatic injury claims is the estimated present value of current workers' compensation benefits, based on our actuarial 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.

Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis obligation.  Our actuarial calculations are based on numerous assumptions including claim development patterns, medical costs and mortality.  Actuarial gains or losses are amortized over the remaining service period of active miners.  See Note 20 – Accrued Workers' Compensation and Pneumoconiosis Benefits for more information on Workers' Compensation and Pneumoconiosis Benefits.

Revenue Recognition

Coal Revenue Recognition—Revenues from coal supply contracts with customers, which primarily relate to sales of thermal coal, are recognized at the point in time when control of the coal passes to the customer.  We have determined that each ton of coal represents a separate and distinct performance obligation.  Our coal supply contracts and other revenue contracts vary in length from short-term to long-term sales contracts and do not typically have significant financing components.  Transportation revenues represent the fulfillment costs incurred for the services provided to customers through third-party carriers and for which we are directly reimbursed.  Other revenues primarily consist of transloading fees, administrative service revenues from our affiliates, mine safety services and products, other coal contract fees and other handling and service fees.  Performance obligations under these contracts are typically satisfied upon transfer of control of the goods or services to our customer which is determined by the contract and could be upon shipment or upon delivery.  

The estimated transaction price from each of our contracts is based on the total amount of consideration we expect to be entitled to under the contract.  Included in the transaction price for certain coal supply contracts is the impact of variable consideration, including quality price adjustments, handling services, government imposition claims, per ton price fluctuations based on certain coal sales price indices and anticipated payments in lieu of shipments.  We have constrained the expected value of variable consideration in our estimation of transaction price and only included this consideration to the extent that it is probable that a significant revenue reversal will not occur.  The estimated transaction price for each contract is allocated to our performance obligations based on relative standalone selling prices determined at contract inception.  Variable consideration is allocated to a specific part of the contract in many instances, such as if the variable consideration is based on production activities for coal delivered during a certain period or the outcome of a customer's ability to accept coal shipments over a certain period.

Contract assets are recorded as trade receivables and reported separately in our consolidated balance sheet from other contract assets as title passes to the customer and our right to consideration becomes unconditional.  Payments for coal shipments are typically due within two to four weeks of performance.  We typically do not have material contract assets that are stated separately from trade receivables as our performance obligations are satisfied as control of the goods or services passes to the customer thereby granting us an unconditional right to receive consideration.  Contract liabilities relate to consideration received in advance of the satisfaction of our performance obligations.  Contract liabilities are recognized as revenue at the point in time when control of the good or service passes to the customer.

Oil & Gas Revenue Recognition—Oil & gas royalty revenues are recognized at the point in time when control of the product is transferred to the purchaser by the lessee and collectability of the sales price is reasonably assured. Oil & gas are priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The royalty we receive is tied to a market index, with certain adjustments based on,

among other factors, whether a well connects to a gathering or transmission line, quality and heat content of the product, and prevailing supply and demand conditions.

We also periodically earn revenue from lease bonuses. We recognize lease bonus revenue when we execute a lease of our mineral interests to exploration and production companies. A lease agreement represents our contract with an operator, which is generally an exploration and production company.  The contract will a) generally transfer the rights to any oil or gas discovered, b) grant us a right to a specified royalty interest from the operator, and c) require the operator to commence drilling and complete operations within a specified time period. Control of the minerals transfers to the operator when the lease agreement is executed.  At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we do not adjust the expected amount of consideration for the effects of any significant financing component.

As a non-operator, we have limited visibility into the timing of when new wells start producing.  In addition, production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices from our properties are estimated and recorded within the Trade receivables line item in our consolidated balance sheets.  Generally, the difference between our estimates and the actual amounts received for oil & gas royalty revenue are immaterial and recorded in the month that payment is received from the third-party purchaser unless new production information is received prior to the payment allowing us to update the estimate recorded.

Common Unit-Based Compensation

Common Unit-Based Compensation—We have the Long-Term Incentive Plan ("LTIP") for certain employees and officers of MGP and its affiliates who perform services for us.  As part of the LTIP, unit awards of non-vested "phantom" or notional units, also referred to as "restricted units", may be granted which upon satisfaction of time and performance based vesting requirements, entitle the LTIP participant to receive ARLP common units.  Annual grant levels and vesting provisions of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval of the compensation committee of our general partner ("Compensation Committee").  Vesting of all restricted units outstanding is subject to the satisfaction of certain financial tests.  If it is not probable that the financial tests for a particular grant of restricted units will be met, any previously expensed amounts for that grant are reversed and no future expense will be recognized for that grant.  Assuming the financial tests are expected to be met, grants of restricted units issued to LTIP participants are generally expected to cliff vest on January 1st of the third year following issuance of the grants.  We expect to settle restricted unit grants by delivery of ARLP common units, except for the portion of the grants that will satisfy employee tax withholding obligations of LTIP participants.  We account for forfeitures of non-vested LTIP restricted unit grants as they occur.  As provided under the distribution equivalent rights ("DERs") provisions of the LTIP and the terms of the LTIP restricted unit awards, all non-vested restricted units include contingent rights to receive quarterly distributions in cash or, at the discretion of the Compensation Committee, phantom units in lieu of cash credited to a bookkeeping account with value equal to the cash distributions we make to unitholders during the vesting period.  If it is not probable the financial tests for a particular grant of restricted units will be met, any previously paid DER amounts for that grant are reversed from Partners’ Capital and recorded as compensation expense and any future DERs, for that grant, if any, will be recognized as compensation expense when paid.

We utilize the Supplemental Executive Retirement Plan ("SERP") to provide deferred compensation benefits for certain officers and key employees. All allocations made to participants under the SERP are made in the form of "phantom" ARLP units and SERP distributions will be settled in the form of ARLP common units.  The SERP is administered by the Compensation Committee.

Our directors participate in the MGP Amended and Restated Deferred Compensation Plan for Directors ("Directors' Deferred Compensation Plan"). Pursuant to the Directors' Deferred Compensation Plan, for amounts deferred either automatically or at the election of the director, a notional account is established and credited with notional common units of ARLP, described in the Directors' Deferred Compensation Plan as "phantom" units.  Distributions from the Directors' Deferred Compensation Plan will be settled in the form of ARLP common units.

For both the SERP and Directors' Deferred Compensation Plan, when quarterly cash distributions are made with respect to ARLP common units, an amount equal to such quarterly distribution is credited to each participant's notional account as additional phantom units.  All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

The fair value of restricted common unit grants under the LTIP, SERP and the Directors' Deferred Compensation Plan are determined on the grant date of the award and recognized as compensation expense on a pro rata basis for LTIP and SERP awards, as appropriate, over the requisite service period. Compensation expense is fully recognized on the grant date for quarterly distributions credited to SERP accounts and Directors' Deferred Compensation Plan awards. The corresponding liability is classified as equity and included in limited partners' capital in the consolidated financial statements (See Note 17 – Compensation Plans).

Income Taxes

Income Taxes—We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to the unitholders. Although publicly traded partnerships as a general rule will be taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code.  Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. Individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units. Furthermore, each unitholder's tax accounting, which is partially dependent upon the unitholder's tax position, differs from the accounting followed in our consolidated financial statements.  Accordingly, the aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each unitholder's tax attributes in our partnership is not available to us. We have certain subsidiaries that are subject to federal and state income taxes.  These income taxes are not material to our financial position or results of operations.

New Accounting Standards Issued and Adopted

New Accounting Standards Issued and Adopted—In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirement for Fair Value Measurement ("ASU 2018-13").  ASU 2018-13 amended the fair value measurement guidance by removing and modifying certain disclosure requirements, while also adding new disclosure requirements including the requirement to disclose the range and weighted average of significant unobservable inputs used to develop certain Level 3 measurements.  These changes are to be applied prospectively for only the most recent interim or annual period presented in the year of adoption.  We adopted ASU 2018-13 on January 1, 2020.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13").  ASU 2016-13 changes the impairment model for most financial assets and certain other instruments to require the use of a new forward-looking "expected loss" model that generally will result in earlier recognition of allowances for losses.  The new standard provides for the use of a modified retrospective transition method that allows for a cumulative-effect adjustment to retained earnings upon adoption.  The new standard also requires disclosure of significantly more information related to these items.  We adopted ASU 2016-13 on January 1, 2020. Because of the credit profile of our customers, the fact that we do not have a history of credit losses on our financial instruments and the absences of any material expected losses, the adoption of ASU 2016-13 did not have any material impact on our consolidated financial statements.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Dec. 31, 2020

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Summary of intangible assets

	December 31, 2020						December 31, 2019
			Accumulated		Intangibles,				Accumulated		Intangibles,
	Original Cost		Amortization		Net		Original Cost		Amortization		Net
	(in thousands)
Non-compete agreements	$	—	$	—	$	—	$	9,803	$	(9,440)	$	363
Customer contracts and other		10,623		(5,744)		4,879		32,371		(24,258)		8,113
Mining permits		1,500		(373)		1,127		1,500		(307)		1,193
Total	$	12,123	$	(6,117)	$	6,006	$	43,674	$	(34,005)	$	9,669

Schedule of estimated amortization expense attributable to intangible assets

Year Ended December 31,		(in thousands)
2021	$	2,831
2022		1,600
2023		647
2024		66
2025		66
Thereafter		795

Summary of advance royalties

	December 31,
	2020		2019
	(in thousands)
Advance royalties, affiliates (see Note 21 – Related-Party Transactions)	$	48,389	$	41,216
Advance royalties, third-parties		12,570		12,685
Total advance royalties	$	60,959	$	53,901

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ACQUISITIONS (Tables)

12 Months Ended

Dec. 31, 2020

AllDale I and II

ACQUISITION

Schedule of total fair value of consideration transferred

	As of January 3, 2019
	(in thousands)
Cash	$	176,205
Previously held investments		307,322
Total	$	483,527

Summary of fair value allocation of assets acquired and liabilities assumed

	(in thousands)
Cash and cash equivalents	$	900
Mineral interests in proved properties		184,032
Mineral interests in unproved properties		291,190
Receivables		9,326
Accounts payable		(1,921)
Net assets acquired	$	483,527

Schedule of revenue and earnings since acquisition date and pro forma condensed consolidated income statement

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	48,411
Net income		18,543

	Year Ended
	December 31,
	2018
	(in thousands)
Total revenues
As reported	$	2,002,857
Pro forma		2,042,545
Net income
As reported	$	367,470
Pro forma		358,741

Wing

ACQUISITION

Summary of fair value allocation of assets acquired and liabilities assumed

	As Previously
	Reported		Adjustments		Final
			(in thousands)
Mineral interests in proved properties	$	58,084		16,987	$	75,071
Mineral interests in unproved properties		84,976		(17,275)		67,701
Receivables		1,867		288		2,155
Net assets acquired	$	144,927			$	144,927

Schedule of revenue and earnings since acquisition date and pro forma condensed consolidated income statement

	Year Ended
	December 31,
	2019
	(in thousands)
Revenue	$	4,625
Net income		1,291

The following represents our actual and pro forma consolidated revenues and net income for the years ended December 31, 2019 and 2018. Pro forma revenues and net income assumes the mineral interests acquired in the Wing Acquisition had been included in our consolidated results since January 1, 2018. These pro forma amounts have been calculated after applying our accounting policies.

	Year Ended
	December 31,
	2019		2018
	(in thousands)
Total revenues
As reported	$	1,961,720	$	2,002,857
Pro forma		1,966,291		2,008,559
Net income
As reported	$	406,926	$	367,470
Pro forma		411,217		372,810

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INVENTORIES (Tables)

12 Months Ended

Dec. 31, 2020

INVENTORIES

Schedule of inventories

	December 31,
	2020		2019
	(in thousands)
Coal	$	19,756	$	63,645
Supplies (net of reserve for obsolescence of $5,547 and $5,555, respectively)		36,651		37,660
Total inventories, net	$	56,407	$	101,305

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2020

PROPERTY, PLANT AND EQUIPMENT

Schedule of property, plant and equipment

	December 31,
	2020		2019
	(in thousands)
Mining equipment and processing facilities	$	1,896,324	$	1,937,642
Land and coal mineral rights		454,310		453,237
Oil & gas mineral interests (1)		616,904		618,282
Buildings, office equipment and improvements		279,938		304,111
Construction and mine development in progress		25,799		86,876
Mine development costs		280,815		283,860
Property, plant and equipment, at cost		3,554,090		3,684,008
Less accumulated depreciation, depletion and amortization		(1,753,845)		(1,675,022)
Total property, plant and equipment, net	$	1,800,245	$	2,008,986

(1) Oil & gas mineral interests acquired in the AllDale and Wing Acquisitions. See Note 3 – Acquisitions for more information.

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2020

LONG-TERM DEBT

Schedule of long-term debt

					Unamortized Discount and
	Principal				Debt Issuance Costs
	December 31,				December 31,
	2020		2019		2020		2019
	(in thousands)
Revolving credit facility	$	87,500	$	255,000	$	(7,196)	$	(3,050)
Senior notes		400,000		400,000		(3,964)		(4,879)
Securitization facility		55,900		73,800		—		—
May 2019 equipment financing		4,956		8,199		—		—
November 2019 equipment financing		42,367		52,281		—		—
June 2020 equipment financing		13,057		—		—		—
		603,780		789,280		(11,160)		(7,929)
Less current maturities		(73,199)		(13,157)		—		—
Total long-term debt	$	530,581	$	776,123	$	(11,160)	$	(7,929)

Schedule of aggregate maturities of long-term debt

Year Ended
December 31,	(in thousands)
2021	$	73,199
2022		16,071
2023		24,970
2024		89,540
2025		400,000
	$	603,780

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LEASES (Tables)

12 Months Ended

Dec. 31, 2020

LEASES

Schedule of lease cost and other information

The components of lease expense were as follows:

	December 31,
	2020		2019
	(in thousands)
Finance lease cost:			$
Amortization of right-of-use assets	$	704		14,608
Interest on lease liabilities		377		2,085
Operating lease cost		3,873		9,169
Short-term lease cost		84		464
Variable lease cost		1,375		1,360
Total lease cost	$	6,413	$	27,686

Supplemental cash flow information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows for operating leases	$	3,870		9,124
Operating cash flows for finance leases	$	377		891
Financing cash flows for finance leases	$	8,368		46,725
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	278		25,593

Supplemental balance sheet information related to leases was as follows:

	December 31,
	2020		2019
	(in thousands)
Finance leases:
Property and equipment finance lease assets, gross	$	5,485	$	30,610
Accumulated depreciation		(3,867)		(20,564)
Property and equipment finance lease assets, net	$	1,618	$	10,046

Summary of supplemental lease information

	December 31,
	2020		2019
Weighted average remaining lease term
Operating leases		13.4 years		13.1 years
Finance leases		3.9 years		1.6 years
Weighted average discount rate
Operating leases		6.0 %		6.0 %
Finance leases		8.0 %		6.0 %

Schedule of maturities of operating lease liabilities

	Operating leases		Finance leases
	(in thousands)
2021	$	2,346	$	912
2022		2,245		912
2023		2,061		139
2024		1,841		139
2025		1,527		139
Thereafter		11,838		280
Total lease payments		21,858		2,521
Less imputed interest		(6,926)		(297)
Total	$	14,932	$	2,224

Schedule of maturities of finance lease liabilities

	Operating leases		Finance leases
	(in thousands)
2021	$	2,346	$	912
2022		2,245		912
2023		2,061		139
2024		1,841		139
2025		1,527		139
Thereafter		11,838		280
Total lease payments		21,858		2,521
Less imputed interest		(6,926)		(297)
Total	$	14,932	$	2,224

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2020

FAIR VALUE MEASUREMENTS

Summary of fair value measurements within the hierarchy

	December 31, 2020						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in thousands)
Long-term debt	$	—	$	518,317	$	—	$	—	$	736,206	$	—
Total	$	—	$	518,317	$	—	$	—	$	736,206	$	—

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PARTNERS' CAPITAL (Tables)

12 Months Ended

Dec. 31, 2020

PARTNERS' CAPITAL

Summary of quarterly per unit distribution paid

	Year Ended December 31,
	2020		2019		2018
First Quarter	$	0.400	$	0.530	$	0.510
Second Quarter	$	—	$	0.535	$	0.515
Third Quarter	$	—	$	0.540	$	0.520
Fourth Quarter	$	—	$	0.540	$	0.525

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VARIABLE INTEREST ENTITIES (Tables)

12 Months Ended

Dec. 31, 2020

VARIABLE INTEREST ENTITIES

Schedule of distributions

	Alliance		Bluegrass
	Minerals		Minerals
	(in thousands)
Contributions	$	143,112	$	5,963
Distributions		89,380		3,723

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INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2020

INVESTMENTS

Schedule of changes in equity method investment

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Beginning balance	$	28,529	$	28,974	$	14,182
Contributions		—		—		15,600
Equity method investment income		907		2,203		547
Distributions received		(1,895)		(2,648)		(1,355)
Other		(273)		—		—
Ending balance	$	27,268	$	28,529	$	28,974

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REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2020

REVENUE FROM CONTRACTS WITH CUSTOMERS

Schedule of disaggregation of revenues by type

	Illinois						Other and
	Basin		Appalachia		Minerals		Corporate		Elimination		Consolidated
	(in thousands)
Year Ended December 31, 2020
Coal sales	$	755,208	$	477,064	$	—	$	—	$	—	$	1,232,272
Oil & gas royalties		—		—		42,912		—		—		42,912
Transportation revenues		12,817		8,312		—		—		—		21,129
Other revenues		2,026		14,954		229		25,124		(10,517)		31,816
Total revenues	$	770,051	$	500,330	$	43,141	$	25,124	$	(10,517)	$	1,328,129
Year Ended December 31, 2019
Coal sales	$	1,128,588	$	628,406	$	—	$	22,138	$	(16,690)	$	1,762,442
Oil & gas royalties		—		—		51,735		—		—		51,735
Transportation revenues		94,686		4,817		—		—		—		99,503
Other revenues		13,034		11,166		1,301		34,712		(12,173)		48,040
Total revenues	$	1,236,308	$	644,389	$	53,036	$	56,850	$	(28,863)	$	1,961,720
Year Ended December 31, 2018
Coal sales	$	1,197,143	$	635,530	$	—	$	43,393	$	(31,258)	$	1,844,808
Transportation revenues		106,947		5,435		—		3		—		112,385
Other revenues		16,999		3,000		—		38,096		(12,431)		45,664
Total revenues	$	1,321,089	$	643,965	$	—	$	81,492	$	(43,689)	$	2,002,857

Schedule of current coal supply contracts allocated to performance obligations that are unsatisfied or partially unsatisfied

							2024 and
	2021		2022		2023		Thereafter		Total
	(in thousands)
Illinois Basin coal revenues	$	653,208	$	253,654	$	187,570	$	140,750	$	1,235,182
Appalachia coal revenues		318,984		95,471		—		—		414,455
Total coal revenues (1)	$	972,192	$	349,125	$	187,570	$	140,750	$	1,649,637

(1) Coal revenues generally consists of consolidated revenues excluding our Minerals segment.

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EARNINGS PER LIMITED PARTNER UNIT (Tables)

12 Months Ended

Dec. 31, 2020

EARNINGS PER LIMITED PARTNER UNIT

Reconciliation of net income and EPU calculations

	Year Ended December 31,
	2020		2019		2018
	(in thousands, except per unit data)
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Adjustment:
General partner's equity ownership (1)		—		—		(1,560)
Limited partners' interest in net income (loss) attributable to ARLP		(129,220)		399,414		365,044
Less:
Distributions to participating securities		—		(4,254)		(5,114)
Undistributed earnings attributable to participating securities		—		(2,237)		(1,641)
Net income (loss) attributable to ARLP available to limited partners	$	(129,220)	$	392,923	$	358,289
Weighted-average limited partner units outstanding – basic and diluted		127,165		128,117		130,758
Earnings per limited partner unit - basic and diluted (2)	$	(1.02)	$	3.07	$	2.74

(1) Amounts presented for periods subsequent to the first quarter of 2018 reflect the impact of the Simplification Transactions, which ended net income allocations and quarterly cash distributions to MGP after May 31, 2018.  Prior to the Simplification Transactions, MGP maintained a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal and thus received quarterly distributions and income and loss allocations during this time period.

(2) Diluted EPU gives effect to all potentially dilutive common units outstanding during the period using the treasury stock method.  Diluted EPU excludes all potentially dilutive units calculated under the treasury stock method if their effect is anti-dilutive.  For the years ended December 31, 2020, 2019 and 2018, the combined total of LTIP, SERP and Directors' Deferred Compensation Plan units of 773,664, 1,284,013 and 1,658,908, respectively, were considered anti-dilutive under the treasury stock method.

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EMPLOYEE BENEFIT PLANS (Tables) - Defined benefit pension plan

12 Months Ended

Dec. 31, 2020

Employee Benefit Plans

Summary of benefit plans for employees

	December 31,
	2020		2019
	(dollars in thousands)
Change in benefit obligations:
Benefit obligations at beginning of year	$	136,425	$	118,958
Interest cost		4,185		4,864
Actuarial loss		12,396		17,084
Benefits paid		(5,072)		(4,481)
Benefit obligations at end of year		147,934		136,425
Change in plan assets:
Fair value of plan assets at beginning of year		91,567		75,823
Employer contribution		1,739		5,559
Actual return on plan assets		12,735		14,666
Benefits paid		(5,072)		(4,481)
Fair value of plan assets at end of year		100,969		91,567
Funded status at the end of year	$	(46,965)	$	(44,858)
Amounts recognized in balance sheet:
Non-current liability	$	(46,965)	$	(44,858)
Amounts recognized in accumulated other comprehensive income consists of:
Prior service cost	$	(754)	$	(940)
Net actuarial loss		(46,519)		(45,125)
	$	(47,273)	$	(46,065)
Weighted-average assumption to determine benefit obligations as of December 31,
Discount rate		2.37%		3.15%
Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,
Discount rate		3.15%		4.17%
Expected return on plan assets		6.50%		6.50%

Schedule of long-term rate of return assumptions

	Asset allocation
As of December 31, 2020	assumption
Equity securities	62%
Fixed income securities	33%
Real estate	5%
	100%

Components of net periodic benefit cost

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Components of net periodic benefit cost:
Interest cost	$	4,185	$	4,864	$	4,462
Expected return on plan assets		(5,861)		(4,932)		(5,784)
Amortization of prior service cost		186		186		186
Amortization of net loss		4,128		3,922		3,608
Net periodic benefit cost (1)	$	2,638	$	4,040	$	2,472

(1) Nonservice components of net periodic benefit cost are included in the Other income (expense) line item within our consolidated statements of income.

Schedule of other changes in plan assets and benefit obligation recognized in accumulated other comprehensive income

	Year Ended December 31,
	2020		2019
	(in thousands)
Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive loss:
Net actuarial loss	$	(5,522)	$	(7,350)
Reversal of amortization item:
Prior service cost		186		186
Net actuarial loss		4,128		3,922
Total recognized in accumulated other comprehensive loss		(1,208)		(3,242)
Net periodic benefit cost		(2,638)		(4,040)
Total recognized in net periodic benefit cost and accumulated other comprehensive loss	$	(3,846)	$	(7,282)

Schedule of estimated future benefit payments

Year Ended
December 31,	(in thousands)
2021	$	5,629
2022		5,954
2023		6,269
2024		6,488
2025		6,620
2026-2030		34,674
	$	65,634

Schedule of asset allocation guidelines, actual asset allocations and fair value of Pension Plan assets

	Percentage of Total Portfolio
	Minimum	Target	Maximum
Equity securities	45%	62%	80%
Fixed income securities	10%	33%	55%
Real estate	0%	5%	10%

	December 31,
	2020		2019
	(in thousands)
Cash and cash equivalents (a)	$	3,888	$	2,958
Commingled investment funds measured at net asset value (b):
Equities - Global		17,549		10,028
Equities - United States		31,835		26,812
Equities - United States futures		(2,616)		—
Equities - International developed markets		8,920		10,528
Equities - International developed markets futures		(4,921)		—
Equities - International emerging markets		6,600		8,410
Equities - International emerging markets futures		(975)		—
Fixed income - Investment grade		25,703		26,186
Fixed income - High yield		10,056		—
Fixed income - Emerging markets		2,664		—
Fixed income - Futures		(1,265)		—
Real estate		3,531		4,355
Other		—		2,290
Total	$	100,969	$	91,567

(a) Cash and cash equivalents represents a Level 1 fair value measurement.  See Note 2 – Summary of Significant Accounting Policies – Fair Value Measurements for more information regarding the definitions of fair value hierarchy levels.

(b) Investments measured at fair value using the net asset value per share (or its equivalent) have not been classified within the fair value hierarchy.  The fair values of all commingled investment funds are determined based on the net asset values per unit of each of the funds. The net asset values per unit represent the aggregate value of the fund's assets at fair value less liabilities, divided by the number of units outstanding.

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COMMON UNIT-BASED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2020

ARLP LTIP

COMMON UNIT-BASED COMPENSATION PLANS

Summary of activity in share-based plans

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Non-vested grants at January 1, 2018	1,694,026	$	19.62	$	33,372
Granted	511,305		20.40
Vested (1)	(331,502)		34.61
Forfeited	(45,749)		17.40
Non-vested grants at December 31, 2018	1,828,080		17.18		31,699
Granted	682,155		18.63
Vested (1)	(885,381)		12.38
Forfeited	(21,476)		20.84
Non-vested grants at December 31, 2019	1,603,378		20.39		17,349
Granted (2)	1,430,489		5.02
Vested (3)	(919,524)		21.70
Grants canceled (4)	(675,302)		18.62
Forfeited	(8,552)		20.16
Non-vested grants at December 31, 2020	1,430,489		5.02		6,409

(1) During the years ended December 31, 2019 and 2018, we issued 596,650 and 191,858, respectively, unrestricted common units to LTIP participants.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.

(2) In December 2020, we modified the vesting requirements for certain restricted units that we granted in February 2020 which were determined to be improbable of vesting under the original vesting requirements (the "2020 Grants"). The new vesting requirements make it probable the modified restricted units will vest.  Also in December 2020, an additional 578,114 restricted units under these modified vesting requirements were granted.  The grant date fair value reflects the modification date fair value for those awards that were modified.

(3) In February 2020, we issued 279,622 unrestricted common units to LTIP participants as a result of satisfying the vesting requirements for 424,486 restricted units that were granted in 2017.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.  In December 2020, we accelerated the vesting requirements for 495,038 restricted units that were granted in 2018 (the "2018 Grants") and settled these restricted units in cash.

(4) In December 2020, 675,302 restricted units that were granted in 2019 (the "2019 Grants") were canceled since it was determined that the vesting requirements for these restricted units were not probable of being satisfied.

SERP and Directors' Compensation Plans

COMMON UNIT-BASED COMPENSATION PLANS

Summary of activity in share-based plans

	Number of units	Weighted average grant date fair value per unit		Intrinsic value
				(in thousands)
Phantom units outstanding as of January 1, 2018	561,784	$	28.64	$	11,067
Granted	84,417		18.78
Issued (1)	(10,364)		27.92
Phantom units outstanding as of December 31, 2018	635,837		27.34		11,025
Granted	111,012		14.50
Issued (1)	(115,484)		25.20
Phantom units outstanding as of December 31, 2019	631,365		25.48		6,831
Granted	129,265		5.25
Phantom units outstanding as of December 31, 2020	760,630		22.04		3,408

(1) During the years ended December 31, 2019 and 2018, we issued ARLP common units of 115,484 and 7,181, respectively, to participants under the SERP and Directors' Deferred Compensation Plan.  Units issued in 2018 were net of units settled in cash to satisfy tax withholding obligations.

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

12 Months Ended

Dec. 31, 2020

SUPPLEMENTAL CASH FLOW INFORMATION

Schedule of supplemental cash flow information

	Year Ended December 31,
	2020		2019		2018
		(in thousands)
Cash Paid For:
Interest	$	44,226	$	43,093	$	38,450
Income taxes	$	12	$	—	$	34
Non-Cash Activity:
Accounts payable for purchase of property, plant and equipment	$	5,731	$	14,504	$	14,585
Right-of-use assets acquired by operating lease	$	278		25,593		—
Market value of common units issued under deferred compensation plans before tax withholding requirements	$	3,837	$	17,415	$	6,142

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ASSET RETIREMENT OBLIGATIONS (Tables)

12 Months Ended

Dec. 31, 2020

ASSET RETIREMENT OBLIGATIONS

Schedule of activity affecting the asset retirement and mine closing liability

	Year Ended December 31,
	2020		2019
	(in thousands)
Beginning balance	$	137,514	$	137,114
Accretion expense		4,033		4,087
Payments		(1,769)		(2,948)
Allocation of liability associated with acquisitions, mine development and change in assumptions		(11,880)		(739)
Ending balance	$	127,898	$	137,514

Schedule of estimated payments of asset retirement obligations

Year Ended
December 31,	(in thousands)
2021	$	6,411
2022		2,723
2023		2,570
2024		3,317
2025		4,601
Thereafter		210,330
Aggregate undiscounted asset retirement obligations		229,952
Effect of discounting		(102,054)
Total asset retirement obligations		127,898
Less: current portion		(6,411)
Non-current asset retirement obligations	$	121,487

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS (Tables)

12 Months Ended

Dec. 31, 2020

Accrued Workers Compensation And Pneumoconiosis Benefits

Reconciliation of changes in workers' compensation liability

	December 31,
	2020		2019
	(in thousands)
Beginning balance	$	53,384	$	49,539
Accruals increase		5,146		7,162
Payments		(8,482)		(11,320)
Interest accretion		1,278		1,606
Valuation loss		3,413		6,397
Ending balance	$	54,739	$	53,384

Reconciliation of changes in pneumoconiosis benefit obligation

	December 31,
	2020		2019
	(in thousands)
Benefit obligations at beginning of year	$	97,683	$	72,095
Service cost		3,526		2,593
Interest cost		2,998		3,044
Actuarial (gain) loss		7,787		23,298
Benefits and expenses paid		(3,498)		(3,347)
Benefit obligations at end of year	$	108,496	$	97,683

Components of pneumoconiosis and workers' compensation expense

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Black lung benefits:
Service cost	$	3,526	$	2,593	$	2,525
Interest cost (1)		2,998		3,044		2,542
Net amortization (1)		(686)		(4,582)		2
Total pneumoconiosis expense		5,838		1,055		5,069
Workers' compensation expense		12,305		17,541		11,270
Net periodic benefit cost	$	18,143	$	18,596	$	16,339

________________________________________

(1) Interest cost and net amortization is included in the Other income (expense) line item within our consolidated statements of income (see Note 2 – Summary of Significant Accounting Policies).

Pneumoconiosis benefits

Accrued Workers Compensation And Pneumoconiosis Benefits

Reconciliation of changes in the pneumoconiosis benefit obligation recognized in AOCI

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Net actuarial gain (loss)	$	(7,787)	$	(23,298)	$	4,599
Reversal of amortization item:
Net actuarial (gain) loss		(686)		(4,582)		2
Total recognized in accumulated other comprehensive loss	$	(8,473)	$	(27,880)	$	4,601

Schedule of amount recognized in accumulated other comprehensive income

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Amount recognized in accumulated other comprehensive loss consists of:
Net actuarial loss	$	40,399	$	31,927	$	4,047

Summary of information about amounts recognized in the consolidated balance sheets

	December 31,
	2020		2019
	(in thousands)
Workers’ compensation claims	$	54,739	$	53,384
Pneumoconiosis benefit claims		108,496		97,683
Total obligations		163,235		151,067
Less current portion		(10,646)		(11,175)
Non-current obligations	$	152,589	$	139,892

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RELATED-PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2020

RELATED-PARTY TRANSACTIONS

Summary of advanced royalties outstanding

				WKY CoalPlay
				Towhead		Webster		Henderson		WKY
		SGP/Craft Foundations		Coal		Coal		Coal		CoalPlay
				Henderson						Henderson
		Tunnel		& Union		Webster		Henderson		& Union
		Ridge		Counties, KY		County, KY		County, KY		Counties, KY		Total
		Acquired		Acquired		Acquired		Acquired		Acquired
		2005		December 2014		December 2014		December 2014		February 2015
	(in thousands)
As of January 1, 2018		$	3,000	$	10,684	$	5,356	$	7,566	$	6,387	$	32,993
Payments			—		3,597		2,570		2,520		2,131		10,818
Recoupment			(3,000)		(204)		(31)		—		(36)		(3,271)
Unrecoupable			—		—		(7,895)		—		—		(7,895)
As of December 31, 2018			—		14,077		—		10,086		8,482		32,645
Payments			4,500		3,597		2,568		2,521		2,131		15,317
Recoupment			(3,000)		(1,071)		—		—		(107)		(4,178)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2019			1,500		16,603		—		12,607		10,506		41,216
Payments			3,000		3,597		2,568		2,522		2,132		13,819
Recoupment			(3,000)		(1,022)		—		—		(56)		(4,078)
Unrecoupable			—		—		(2,568)		—		—		(2,568)
As of December 31, 2020		$	1,500	$	19,178	$	—	$	15,129	$	12,582	$	48,389

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CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS (Tables)

12 Months Ended

Dec. 31, 2020

CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

Schedule of total revenues from major customers

		Year Ended December 31,
	Segment	2020		2019		2018
		(in thousands)
Customer A	Illinois Basin	$	197,379	$	228,500	$	219,115
Customer B	Appalachia		—		213,319		—
Customer C	Illinois Basin		157,271		—		—
Customer D	Illinois Basin/Appalachia		137,785		—		—

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SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2020

SEGMENT INFORMATION

Schedule of reportable segment results

	Illinois						Other and		Elimination
	Basin		Appalachia		Minerals		Corporate		(1)		Consolidated
	(in thousands)
Year Ended December 31, 2020
Revenues - Outside	$	770,051	$	500,330	$	43,141	$	14,607	$	—	$	1,328,129
Revenues - Intercompany		—		—		—		10,517		(10,517)		—
Total revenues (2)		770,051		500,330		43,141		25,124		(10,517)		1,328,129
Segment Adjusted EBITDA Expense (3)		520,324		319,730		4,106		18,543		(1,454)		861,249
Segment Adjusted EBITDA (4)		236,911		172,288		39,773		6,580		(9,063)		446,489
Total assets		1,018,916		448,567		613,916		477,469		(392,852)		2,166,016
Capital expenditures		48,648		70,960		—		1,493		—		121,101
Year Ended December 31, 2019
Revenues - Outside	$	1,219,618	$	644,389	$	53,036	$	44,677	$	—	$	1,961,720
Revenues - Intercompany		16,690		—		—		12,173		(28,863)		—
Total revenues (2)		1,236,308		644,389		53,036		56,850		(28,863)		1,961,720
Segment Adjusted EBITDA Expense (3)		756,423		423,623		7,811		36,845		(19,806)		1,204,896
Segment Adjusted EBITDA (4)		385,200		215,950		46,997		32,911		(9,057)		672,001
Total assets		1,373,516		500,027		643,213		541,261		(471,323)		2,586,694
Capital expenditures (5)		189,270		111,739		—		4,849		—		305,858
Year Ended December 31, 2018
Revenues - Outside	$	1,289,898	$	643,898	$	—	$	69,061	$	—	$	2,002,857
Revenues - Intercompany		31,191		67		—		12,431		(43,689)		—
Total revenues (2)		1,321,089		643,965		—		81,492		(43,689)		2,002,857
Segment Adjusted EBITDA Expense (3)		796,370		398,243		—		52,321		(35,134)		1,211,800
Segment Adjusted EBITDA (4)		417,773		240,286		21,323		44,864		(8,555)		715,691
Total assets		1,380,912		440,518		161,312		589,010		(177,004)		2,394,748
Capital expenditures		166,468		64,037		—		2,975		—		233,480

(1) The elimination column represents the elimination of intercompany transactions and is primarily comprised of sales from the Matrix Group to our mining operations, coal sales and purchases between operations within different segments, sales of receivables to AROP Funding, financing between segments and insurance premiums paid to Wildcat Insurance.

(2) Revenues included in the Other and Corporate column are primarily attributable to the outside and affiliate revenues at the Matrix Group and coal brokerage activities.  In additions, Other and Corporate includes affiliate revenues for administrative and Wildcat Insurance services.

(3) Segment Adjusted EBITDA Expense includes operating expenses, coal purchases and other income. Transportation expenses are excluded as transportation revenues are recognized in an amount equal to transportation expenses when title passes to the customer.  

The following is a reconciliation of consolidated Segment Adjusted EBITDA Expense to Operating expenses (excluding depreciation, depletion and amortization):

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Segment Adjusted EBITDA Expense	$	861,249	$	1,204,896	$	1,211,800
Outside coal purchases		—		(23,357)		(1,466)
Other income (expense)		(1,593)		561		(2,621)
Operating expenses (excluding depreciation, depletion and amortization)	$	859,656	$	1,182,100	$	1,207,713

(4) Segment Adjusted EBITDA is defined 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.    Consolidated Segment Adjusted EBITDA is reconciled to net income (loss) as follows:

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Consolidated Segment Adjusted EBITDA	$	446,489	$	672,001	$	715,691
General and administrative		(59,806)		(72,997)		(68,298)
Depreciation, depletion and amortization		(313,387)		(309,075)		(280,225)
Settlement gain		—		—		80,000
Asset impairments		(24,977)		(15,190)		(40,483)
Goodwill impairment		(132,026)		—		—
Interest expense, net		(45,478)		(45,496)		(40,059)
Acquisition gain		—		177,043		—
Income tax (expense) benefit		(35)		211		(22)
Acquisition gain attributable to noncontrolling interest		—		(7,083)		—
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Noncontrolling interest		169		7,512		866
Net income (loss)	$	(129,051)	$	406,926	$	367,470

.

(5) Capital Expenditures shown exclude the AllDale Acquisition on January 3, 2019 and the Wing Acquisition on August 2, 2019 (Note 3 – Acquisitions).

Reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expenses (excluding depreciation, depletion and amortization)

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Segment Adjusted EBITDA Expense	$	861,249	$	1,204,896	$	1,211,800
Outside coal purchases		—		(23,357)		(1,466)
Other income (expense)		(1,593)		561		(2,621)
Operating expenses (excluding depreciation, depletion and amortization)	$	859,656	$	1,182,100	$	1,207,713

Reconciliation of consolidated Segment Adjusted EBITDA to net income

	Year Ended December 31,
	2020		2019		2018
	(in thousands)
Consolidated Segment Adjusted EBITDA	$	446,489	$	672,001	$	715,691
General and administrative		(59,806)		(72,997)		(68,298)
Depreciation, depletion and amortization		(313,387)		(309,075)		(280,225)
Settlement gain		—		—		80,000
Asset impairments		(24,977)		(15,190)		(40,483)
Goodwill impairment		(132,026)		—		—
Interest expense, net		(45,478)		(45,496)		(40,059)
Acquisition gain		—		177,043		—
Income tax (expense) benefit		(35)		211		(22)
Acquisition gain attributable to noncontrolling interest		—		(7,083)		—
Net income (loss) attributable to ARLP	$	(129,220)	$	399,414	$	366,604
Noncontrolling interest		169		7,512		866
Net income (loss)	$	(129,051)	$	406,926	$	367,470

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ORGANIZATION AND PRESENTATION (Details)					12 Months Ended
	Aug. 02, 2019 a	Feb. 08, 2019 a	Jan. 03, 2019 a	May 31, 2018 shares	Dec. 31, 2020
AllDale I and II
Ownership interests
Royalty acres, net | a			43,000
Wing
Ownership interests
Royalty acres controlled | a		55,700
Royalty acres, net | a	9,000
Royalty acres, gross | a	400,000
SGP | AHGP
Ownership interests
Ownership percentage by limited partners					34.48%
Simplification Transactions | SGP
Ownership interests
Common units issued in exchange | shares				29,188,997
Issuance of units to Owners of SGP in Simplification Transactions (in units) | shares				1,322,388
Simplification Transactions | AHGP
Ownership interests
Units issued in exchange (in units) | shares				1.4782
Simplification Transactions | Intermediate Partnership
Ownership interests
Ownership percentage by general partners				1.0001%
Simplification Transactions | Alliance Coal
Ownership interests
Ownership percentage by general partners				0.001%
Simplification Transactions | AHGP
Ownership interests
Approved written consent percent				68.00%
Units issued in exchange (in units) | shares				1.4782
Simplification Transactions | AHGP | Intermediate Partnership
Ownership interests
Ownership percentage by general partners				1.0001%
Simplification Transactions | AHGP | Alliance Coal
Ownership interests
Ownership percentage by general partners				0.001%
Simplification Transactions | SGP | Intermediate Partnership
Ownership interests
Ownership percentage by general partners				1.0001%
Simplification Transactions | SGP | Alliance Coal
Ownership interests
Ownership percentage by general partners				0.001%

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Goodwill
Impairments of goodwill	$ 132,026	$ 0	$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Tangible Assets (Details)	12 Months Ended
	Dec. 31, 2020
Preparation plants, processing facilities and mineral rights | Minimum
Property, Plant and Equipment
Estimated useful life	1 year
Preparation plants, processing facilities and mineral rights | Maximum
Property, Plant and Equipment
Estimated useful life	22 years
Other plant and equipment and mining equipment | Minimum
Property, Plant and Equipment
Estimated useful life	1 year
Other plant and equipment and mining equipment | Maximum
Property, Plant and Equipment
Estimated useful life	22 years
Buildings, office equipment and improvements | Minimum
Property, Plant and Equipment
Estimated useful life	1 year
Buildings, office equipment and improvements | Maximum
Property, Plant and Equipment
Estimated useful life	22 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Leases (Details)	12 Months Ended
	Dec. 31, 2020
Lease renewal term	10 years
Lease termination option term	1 year
Minimum
Lease term	1 year
Maximum
Lease term	20 years

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Intangible Assets
Amortization expense attributable to intangible assets	$ 4,900	$ 9,100	$ 6,900
Original Cost	12,123	43,674
Accumulated Amortization	(6,117)	(34,005)
Intangibles, Net	6,006	9,669
Estimated amortization expense attributable to intangible assets
2021	2,831
2022	1,600
2023	647
2024	66
2025	66
Thereafter	795
Noncompete agreement
Intangible Assets
Original Cost		9,803
Accumulated Amortization		(9,440)
Intangibles, Net		363
Customer contracts, net
Intangible Assets
Original Cost	10,623	32,371
Accumulated Amortization	(5,744)	(24,258)
Intangibles, Net	4,879	8,113
Permits
Intangible Assets
Original Cost	1,500	1,500
Accumulated Amortization	(373)	(307)
Intangibles, Net	$ 1,127	$ 1,193

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Advance Royalties (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Advance Royalties
Advance royalties, net, affiliates	$ 48,389	$ 41,216
Advance royalties, net, third-parties	12,570	12,685
Total advance royalties, net	$ 60,959	$ 53,901

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Taxes
Percentage of qualifying income for tax purposes	90.00%
Assets and Liabilities, Lessee
Operating lease liabilities	$ 14,932
Offsetting right-of-use assets	$ 15,004	$ 17,660
Minimum
Revenue Recognition
Coal shipments, payment period	14 days
Maximum
Revenue Recognition
Coal shipments, payment period	28 days
Defined benefit pension plan
Employee Benefit Plans
Threshold for amortization of unrecognized actuarial gains and losses (as a percent)	10.00%

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ACQUISITIONS - Assets and Liabilities (Details) $ in Thousands	Aug. 02, 2019 USD ($) a	Jan. 03, 2019 USD ($) a	Dec. 31, 2020 USD ($)
Assets acquired and liabilities assumed
Cash and cash equivalents		$ 900
Mineral interests in proved properties		184,032
Mineral interests in unproved properties		291,190
Receivables		9,326
Accounts payable		(1,921)
Net assets acquired		$ 483,527
Wing
ACQUISITION
Royalty acres, net | a	9,000
Royalty acres, gross | a	400,000
Cash	$ 144,900
Assets acquired and liabilities assumed
Mineral interests in proved properties	75,071
Mineral interests in unproved properties	67,701
Receivables	2,155
Net assets acquired	144,927
Wing | Previously Reported
Assets acquired and liabilities assumed
Mineral interests in proved properties	58,084
Mineral interests in unproved properties	84,976
Receivables	1,867
Net assets acquired	144,927
Wing | Adjustments
Assets acquired and liabilities assumed
Mineral interests in proved properties	16,987
Mineral interests in unproved properties	(17,275)
Receivables	$ 288		$ 300
AllDale I and II
ACQUISITION
Royalty acres, net | a		43,000
Cash		$ 176,205
Assets acquired and liabilities assumed
Noncontrolling interest fair value		$ 12,300

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ACQUISITIONS - Consideration (Details) - USD ($) $ in Thousands			12 Months Ended
	Aug. 02, 2019	Jan. 03, 2019	Dec. 31, 2019	Dec. 31, 2020	Jan. 02, 2019
ACQUISITION
Equity method investments			$ 28,529	$ 27,268
Acquisition gain			$ 177,043
AllDale I and II
ACQUISITION
Cash		$ 176,205
Previously held investment		307,322
Total		483,527
Equity method investments					$ 130,300
Acquisition gain		$ 177,000
Wing
ACQUISITION
Cash	$ 144,900

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ACQUISITIONS - Pro Forma (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pro forma condensed consolidated income statement
Total revenues, As reported	$ 1,328,129	$ 1,961,720	$ 2,002,857
Net income (loss)	$ (129,051)	406,926	367,470
Wing
Acquisitions, additional information
Revenue of acquired business		4,625
Net income of acquired business		1,291
Pro forma condensed consolidated income statement
Total revenues, Pro forma		1,966,291	2,008,559
Net income, Pro forma		411,217	372,810
AllDale I and II
Acquisitions, additional information
Revenue of acquired business		48,411
Net income of acquired business		$ 18,543
Pro forma condensed consolidated income statement
Total revenues, As reported			2,002,857
Total revenues, Pro forma			2,042,545
Net income (loss)			367,470
Net income, Pro forma			$ 358,741

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LONG-LIVED ASSET IMPAIRMENTS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Aug. 16, 2019	Aug. 15, 2019	Sep. 30, 2018
Asset impairment charges
Asset impairments	$ 24,977	$ 15,190	$ 40,483
Total assets	2,166,016	2,586,694	2,394,748
Dotiki Mine
Asset impairment charges
Asset impairments		15,200	34,300
Total assets			51,000	$ 25,800	$ 35,900	$ 85,300
Accrued payments				$ 5,100
Coal reserves not to exercise lease option
Asset impairment charges
Asset impairments			6,200
Illinois Basin
Asset impairment charges
Asset impairments	25,000
Total assets	$ 1,018,916	$ 1,373,516	$ 1,380,912

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GOODWILL IMPAIRMENT (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
GOODWILL IMPAIRMENT
Goodwill	$ 4,373	$ 136,399
Impairments of goodwill	132,026	0	$ 0
Hamilton mining complex
GOODWILL IMPAIRMENT
Goodwill		$ 132,000
Impairments of goodwill	$ 132,000

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INVENTORIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
INVENTORIES
Coal	$ 19,756	$ 63,645
Supplies (net of reserve for obsolescence of $5,547 and $5,555, respectively)	36,651	37,660
Total inventories, net	56,407	101,305
Reserve for obsolescence	5,547	5,555
Reduce inventory carrying value to market	$ 3,245	$ 4,895	$ 1,455

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PROPERTY, PLANT AND EQUIPMENT - Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	$ 3,554,090	$ 3,684,008
Less accumulated depreciation, depletion and amortization	(1,753,845)	(1,675,022)
Total property, plant and equipment, net	1,800,245	2,008,986
Mining equipment and processing facilities
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	1,896,324	1,937,642
Land and coal mineral rights
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	454,310	453,237
Coal reserves not subject to depletion	37,500	40,100
Oil and gas mineral interests
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	616,904	618,282
Unproved properties	340,500	376,200
Buildings, office equipment and improvements
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	279,938	304,111
Construction and mine development in progress
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	25,799	86,876
Mine development costs
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, at cost	280,815	283,860
Mine development costs	$ 13,100	$ 13,200

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LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Principal
Aggregate maturities of long-term debt	$ 603,780	$ 789,280
Less current maturities	(73,199)	(13,157)
Total long-term debt	530,581	776,123
Unamortized Discount and Debt Issuance Costs
Unamortized debt issuance costs including current and non-current	(11,160)	(7,929)
Total unamortized debt issuance costs	(11,160)	(7,929)
Revolving credit facility
Principal
Aggregate maturities of long-term debt	87,500	255,000
Unamortized Discount and Debt Issuance Costs
Unamortized debt issuance costs including current and non-current	(7,196)	(3,050)
Senior notes due 2025
Principal
Aggregate maturities of long-term debt	400,000	400,000
Unamortized Discount and Debt Issuance Costs
Unamortized debt issuance costs including current and non-current	(3,964)	(4,879)
Securitization Facility
Principal
Aggregate maturities of long-term debt	55,900	73,800
May 2019 equipment financing
Principal
Aggregate maturities of long-term debt	4,956	8,199
November 2019 equipment financing
Principal
Aggregate maturities of long-term debt	42,367	$ 52,281
June 2020 equipment financing
Principal
Aggregate maturities of long-term debt	$ 13,057

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LONG-TERM DEBT - Credit Facility (Details) $ in Thousands		12 Months Ended
	Mar. 09, 2020 USD ($) item	Dec. 31, 2020 USD ($)	Jan. 27, 2017 USD ($)
Long-Term Debt
Debt issuance costs incurred		$ 6,280
Credit Agreement
Long-Term Debt
Maximum borrowing capacity	$ 537,750
Debt issuance costs incurred		$ 6,300
Number of benchmarks | item	3
ARLP debt arrangements requirements, fixed charge coverage ratio	1.0
ARLP debt arrangements requirements, debt to cash flow ratio	2.5
ARLP debt arrangements requirements, cash flow to interest expense ratio	3.0
ARLP debt arrangements requirements, period over which the ratios are required to be maintained	12 months
Actual debt to cash flow ratio for trailing twelve months		1.53
Actual cash flow to interest expense ratio for trailing twelve months		8.45
Restricted net assets of subsidiaries		$ 240,800
Credit Agreement | Eurodollar Rate
Long-Term Debt
Effective interest rate (as a percent)		3.01%
Credit Agreement | Extended Commitment to May 23, 2021
Long-Term Debt
Maximum borrowing capacity	$ 459,500
Credit Agreement | Credit Agreement, first lien
Long-Term Debt
ARLP debt arrangements requirements, debt to cash flow ratio	1.5
Actual debt to cash flow ratio for trailing twelve months		0.52
Revolving credit facility
Long-Term Debt
Maximum borrowing capacity			$ 494,750
Line of credit facility, available for borrowing		$ 428,500
Annual commitment fee percentage, undrawn portion		0.35%
Letters of credit subfacility
Long-Term Debt
Maximum borrowing capacity	$ 125,000
Letters of credit outstanding		$ 21,800
Swingline subfacility
Long-Term Debt
Maximum borrowing capacity	$ 15,000
Letters of credit - Other
Long-Term Debt
Maximum borrowing capacity		5,000
Letters of credit outstanding		$ 5,000

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LONG-TERM DEBT - 2025 Senior Notes (Details) - Senior notes due 2025 $ in Millions	Apr. 24, 2017 USD ($)
Issuance of Senior Notes
Principal amount	$ 400.0
Term	8 years
Interest rate (as a percent)	7.50%

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LONG-TERM DEBT - Securitization Facility (Details) - Securitization Facility - USD ($) $ in Millions	Jan. 31, 2021	Dec. 31, 2020	Dec. 05, 2014
Long-Term Debt
Maximum borrowing capacity	$ 60.0		$ 100.0
Facility outstanding amount		$ 55.9

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LONG-TERM DEBT - Equipment financing and other (Details) $ in Millions	Jun. 05, 2020 USD ($)	Nov. 06, 2019 USD ($) payment	May 17, 2019 USD ($)	Dec. 31, 2020 USD ($)
May 2019 Equipment Financing
Long-Term Debt
Principal amount			$ 10.0
Term			36 months
Effective interest rate (as a percent)			6.25%
November 2019 Equipment Financing
Long-Term Debt
Principal amount		$ 53.1
Term		4 years
Effective interest rate (as a percent)		4.75%
Number of monthly payments | payment		47
Periodic Payment		$ 1.0
Balloon payment on maturity		$ 11.6
June 2020 equipment financing
Long-Term Debt
Principal amount	$ 14.7
Term	48 months
Effective interest rate (as a percent)	6.10%
Letters of credit - Other
Long-Term Debt
Credit facility amount				$ 5.0

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LONG-TERM DEBT - Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Aggregate maturities of long-term debt
2021	$ 73,199
2022	16,071
2023	24,970
2024	89,540
2025	400,000
Aggregate maturities of long-term debt	$ 603,780	$ 789,280

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LEASES - Lease expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
LEASES
Amortization of right-of-use assets	$ 704	$ 14,608
Interest on lease liabilities	377	2,085
Operating lease cost	3,873	9,169
Short-term lease cost	84	464
Variable lease cost	1,375	1,360
Total lease cost	6,413	27,686
Rental expense	$ 5,200	$ 11,000	$ 14,900

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LEASES - Cash flow (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
LEASES
Operating cash flows for operating leases	$ 3,870	$ 9,124
Operating cash flows for finance leases	377	891
Financing cash flows for finance leases	8,368	46,725	$ 29,353
Operating leases, Right-of-use assets obtained in exchange for lease obligations	$ 278	$ 25,593

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LEASES - Balance Sheet (Details) - Assets under finance lease - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lease balance sheet information
Property and equipment finance lease assets, gross	$ 5,485	$ 30,610
Accumulated depreciation	(3,867)	(20,564)
Property and equipment finance lease assets, net	$ 1,618	$ 10,046

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LEASES - Weighted Average (Details)	Dec. 31, 2020	Dec. 31, 2019
LEASES
Weighted average remaining lease term of operating leases	13 years 4 months 24 days	13 years 1 month 6 days
Weighted average remaining lease term of finance leases	3 years 10 months 24 days	1 year 7 months 6 days
Weighted average discount rate of operating leases (as a percent)	6.00%	6.00%
Weighted average discount rate of finance leases (as a percent)	8.00%	6.00%

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LEASES - Maturities (Details) $ in Thousands	Dec. 31, 2020 USD ($)
Operating leases
2021	$ 2,346
2022	2,245
2023	2,061
2024	1,841
2025	1,527
Thereafter	11,838
Total lease payments	21,858
Less imputed interest	(6,926)
Total	14,932
Finance leases
2021	912
2022	912
2023	139
2024	139
2025	139
Thereafter	280
Total lease payments	2,521
Less imputed interest	(297)
Total	$ 2,224

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FAIR VALUE MEASUREMENTS (Details) - Estimated fair value - Significant Observable Inputs (Level 2) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
FAIR VALUE MEASUREMENTS
Long-term debt	$ 518,317	$ 736,206
Total	$ 518,317	$ 736,206

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PARTNERS' CAPITAL - Distributions (Details) - $ / shares	3 Months Ended									12 Months Ended
	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2020
PARTNERS' CAPITAL
Period following quarter end for distribution of available cash										45 days
Quarterly distribution paid (in dollars per unit)	$ 0.400	$ 0.540	$ 0.540	$ 0.535	$ 0.530	$ 0.525	$ 0.520	$ 0.515	$ 0.510

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PARTNERS' CAPITAL - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands			12 Months Ended
	Jun. 29, 2018	May 31, 2018	Dec. 31, 2020	Dec. 31, 2018
Partners' capital
Cash contribution by affiliated entity				$ 2,142
Affiliated entity controlled by Mr. Craft
Partners' capital
Contribution of units by affiliated entity (in units)	467,018
Cash contribution by affiliated entity				$ 2,100
MGP | Intermediate Partnership
Partners' capital
Ownership percentage by general partners			1.0001%
MGP | Alliance Coal
Partners' capital
Ownership percentage by general partners			0.001%
Limited Partners' Capital
Partners' capital
Issuance of units to Owners of SGP in Simplification Transactions (in units)				1,322,388
Repurchase and retire authorization		$ 100,000
Treasury units retired			$ 93,500
Number of units retired			5,460,639
Repurchase price (in dollars per unit)			$ 17.12
Contribution of units by affiliated entity (in units)				(467,018)
Simplification Transactions | Intermediate Partnership
Partners' capital
Ownership percentage by general partners		1.0001%
Simplification Transactions | Alliance Coal
Partners' capital
Ownership percentage by general partners		0.001%
Simplification Transactions | SGP
Partners' capital
Issuance of units to Owners of SGP in Simplification Transactions (in units)		1,322,388
Simplification Transactions | MGP | Intermediate Partnership
Partners' capital
Ownership percentage by general partners		1.0001%
Simplification Transactions | MGP | Alliance Coal
Partners' capital
Ownership percentage by general partners		0.001%
Simplification Transactions | SGP | Intermediate Partnership
Partners' capital
Ownership percentage by general partners		1.0001%
Simplification Transactions | SGP | Alliance Coal
Partners' capital
Ownership percentage by general partners		0.001%

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VARIABLE INTEREST ENTITIES - Cavalier (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 03, 2019
Variable Interest Entities
Contributions			$ 2,142
Distributions paid to Partners	$ 51,753	$ 278,425	$ 275,902
Cavalier Minerals | Alliance Minerals
Variable Interest Entities
Contributions	143,112
Distributions paid to Partners	89,380
Cavalier Minerals | Bluegrass Minerals
Variable Interest Entities
Contributions	5,963
Distributions paid to Partners	$ 3,723
Cavalier Minerals | Bluegrass Minerals
Variable Interest Entities
Incentive distribution of available cash (as a percent)	25.00%
Cavalier Minerals
Variable Interest Entities
Ownership interest in VIE (as a percent)	96.00%
Cavalier Minerals | Bluegrass Minerals
Variable Interest Entities
Noncontrolling ownership interest (as a percent)	4.00%			4.00%

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VARIABLE INTEREST ENTITIES - All Dale III (Detail) - All Dale Minerals III - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 28, 2017
Equity Investments
Other Commitment		$ 30.0
Distribution after hurdles (as a percent)	25.00%
Specified internal rate of return (as a percent)	10.00%
Percentage of available cash distributed	125.00%
All Dale Minerals III
Equity Investments
Ownership percentage by limited partners	13.90%

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VARIABLE INTEREST ENTITIES - WKY CoalPlay (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Coal lease
Variable Interest Entities
Payments	$ 13,819	$ 15,317	$ 10,818

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INVESTMENTS - AllDale (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ASSETS
Beginning balance	$ 28,529
Equity method investment income	907	$ 2,203	$ 22,189
Ending balance	27,268	28,529
All Dale Minerals III
ASSETS
Beginning balance	28,529	28,974	14,182
Contributions			15,600
Equity method investment income	907	2,203	547
Distributions received	(1,895)	(2,648)	(1,355)
Other	(273)
Ending balance	$ 27,268	$ 28,529	$ 28,974

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INVESTMENTS - Kodiak (Details) - USD ($) $ in Thousands		12 Months Ended
	Feb. 08, 2019	Dec. 31, 2019	Jul. 19, 2017
Equity securities without readily determinable fair value
Redemption of preferred interest		$ 134,288
Kodiak
Equity securities without readily determinable fair value
Equity securities	$ 0		$ 100,000
Redemption of preferred interest	135,000
Gain on redemption	$ 11,500

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REVENUE FROM CONTRACTS WITH CUSTOMERS - Disaggregation of revenues (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of revenues
Revenues	$ 1,328,129	$ 1,961,720	$ 2,002,857
Coal sales
Disaggregation of revenues
Revenues	1,232,272	1,762,442	1,844,808
Oil & gas royalties
Disaggregation of revenues
Revenues	42,912	51,735
Transportation revenues
Disaggregation of revenues
Revenues	21,129	99,503	112,385
Other revenues
Disaggregation of revenues
Revenues	31,816	48,040	45,664
Illinois Basin
Disaggregation of revenues
Revenues	770,051	1,236,308	1,321,089
Illinois Basin | Coal sales
Disaggregation of revenues
Revenues	755,208	1,128,588	1,197,143
Illinois Basin | Transportation revenues
Disaggregation of revenues
Revenues	12,817	94,686	106,947
Illinois Basin | Other revenues
Disaggregation of revenues
Revenues	2,026	13,034	16,999
Appalachia
Disaggregation of revenues
Revenues	500,330	644,389	643,965
Appalachia | Coal sales
Disaggregation of revenues
Revenues	477,064	628,406	635,530
Appalachia | Transportation revenues
Disaggregation of revenues
Revenues	8,312	4,817	5,435
Appalachia | Other revenues
Disaggregation of revenues
Revenues	14,954	11,166	3,000
Minerals
Disaggregation of revenues
Revenues	43,141	53,036
Minerals | Oil & gas royalties
Disaggregation of revenues
Revenues	42,912	51,735
Minerals | Other revenues
Disaggregation of revenues
Revenues	229	1,301
Other and Corporate
Disaggregation of revenues
Revenues	25,124	56,850	81,492
Other and Corporate | Coal sales
Disaggregation of revenues
Revenues		22,138	43,393
Other and Corporate | Transportation revenues
Disaggregation of revenues
Revenues			3
Other and Corporate | Other revenues
Disaggregation of revenues
Revenues	25,124	34,712	38,096
Elimination
Disaggregation of revenues
Revenues	(10,517)	(28,863)	(43,689)
Elimination | Coal sales
Disaggregation of revenues
Revenues		(16,690)	(31,258)
Elimination | Other revenues
Disaggregation of revenues
Revenues	(10,517)	(12,173)	(12,431)
Elimination | Illinois Basin
Disaggregation of revenues
Revenues		16,690	31,191
Elimination | Appalachia
Disaggregation of revenues
Revenues			67
Elimination | Other and Corporate
Disaggregation of revenues
Revenues	$ 10,517	$ 12,173	$ 12,431

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REVENUE FROM CONTRACTS WITH CUSTOMERS - Coal supply contracts (Details) $ in Thousands	Dec. 31, 2020 USD ($)
Performance obligations unsatisfied or partially unsatisfied
Total	$ 1,649,637
Illinois Basin
Performance obligations unsatisfied or partially unsatisfied
Total	1,235,182
Appalachia
Performance obligations unsatisfied or partially unsatisfied
Total	414,455
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Performance obligations unsatisfied or partially unsatisfied
Total	$ 972,192
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Illinois Basin
Performance obligations unsatisfied or partially unsatisfied
Total	$ 653,208
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Appalachia
Performance obligations unsatisfied or partially unsatisfied
Total	$ 318,984
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Performance obligations unsatisfied or partially unsatisfied
Total	$ 349,125
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Illinois Basin
Performance obligations unsatisfied or partially unsatisfied
Total	$ 253,654
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Appalachia
Performance obligations unsatisfied or partially unsatisfied
Total	$ 95,471
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Performance obligations unsatisfied or partially unsatisfied
Total	$ 187,570
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Illinois Basin
Performance obligations unsatisfied or partially unsatisfied
Total	$ 187,570
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Appalachia
Performance obligations unsatisfied or partially unsatisfied
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Performance obligations unsatisfied or partially unsatisfied
Total	$ 140,750
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Illinois Basin
Performance obligations unsatisfied or partially unsatisfied
Total	$ 140,750
Expected timing of satisfaction period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Appalachia
Performance obligations unsatisfied or partially unsatisfied
Expected timing of satisfaction period	1 year

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EARNINGS PER LIMITED PARTNER UNIT - Reconciliation (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss) attributable to ARLP	$ (129,220)	$ 399,414	$ 366,604
General partners' equity ownership			(1,560)
LIMITED PARTNERS	(129,220)	399,414	365,044
Distributions to participating securities		(4,254)	(5,114)
Undistributed earnings attributable to participating securities		(2,237)	(1,641)
Net income (loss) attributable to ARLP available to limited partners	$ (129,220)	$ 392,923	$ 358,289
Weighted-average limited partner units outstanding - basic and diluted	127,164,659	128,116,670	130,758,169
Earnings per limited partner unit - basic and diluted	$ (1.02)	$ 3.07	$ 2.74
Anti-dilutive under the treasury stock method (in units)	773,664	1,284,013	1,658,908
MGP | Intermediate Partnership
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Ownership percentage by general partners	1.0001%
MGP | Alliance Coal
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Ownership percentage by general partners	0.001%

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EMPLOYEE BENEFIT PLANS - Defined Contribution (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
PSSP
Defined Contribution Plans
Contribution expense	$ 16.1	$ 21.1	$ 19.9

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EMPLOYEE BENEFIT PLANS - Benefit Obligations, Plan Assets and Reported Amounts (Details) - Defined benefit pension plan - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Change in benefit obligations:
Benefit obligations at beginning of year	$ 136,425	$ 118,958
Interest cost	4,185	4,864	$ 4,462
Actuarial loss	12,396	17,084
Benefits paid	(5,072)	(4,481)
Benefit obligations at end of year	147,934	136,425	118,958
Change in plan assets:
Fair value of plan assets at beginning of year	91,567	75,823
Employer contribution	1,739	5,559
Actual return on plan assets	12,735	14,666
Benefits paid	(5,072)	(4,481)
Fair value of plan assets at end of year	100,969	91,567	$ 75,823
Funded status at the end of year	(46,965)	(44,858)
Amounts recognized in balance sheet:
Non-current liability	(46,965)	(44,858)
Amount recognized in accumulated other comprehensive income consists of:
Prior service cost	(754)	(940)
Net actuarial loss	(46,519)	(45,125)
Amounts recognized in accumulated other comprehensive income	$ (47,273)	$ (46,065)
Weighted-average assumption to determine benefit obligations
Discount rate	2.37%	3.15%
Weighted-average assumptions used to determine net periodic benefit cost
Discount rate	3.15%	4.17%
Expected return on plan assets	6.50%	6.50%

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EMPLOYEE BENEFIT PLANS - Assumptions (Details) - Defined benefit pension plan	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset allocation assumptions
Active management premium percentage	1.50%
Asset allocation assumption	100.00%
Actual return on plan assets (as a percent)	14.20%	19.20%
Equity securities
Asset allocation assumptions
Asset allocation assumption	62.00%
Fixed income securities
Asset allocation assumptions
Asset allocation assumption	33.00%
Real estate
Asset allocation assumptions
Asset allocation assumption	5.00%

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EMPLOYEE BENEFIT PLANS - Periodic Benefit Cost and Other Changes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive loss:
Total defined benefit pension plan adjustments	$ (9,681)	$ (31,122)	$ 5,069
Defined benefit pension plan
Components of net periodic benefit cost:
Interest cost	4,185	4,864	4,462
Expected return on plan assets	(5,861)	(4,932)	(5,784)
Amortization of prior service cost	186	186	186
Amortization of net loss	4,128	3,922	3,608
Net periodic benefit cost	2,638	4,040	2,472
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive loss:
Net actuarial gain (loss)	(5,522)	(7,350)	(3,326)
Reversal of amortization item: Prior service cost	186	186	186
Reversal of amortization item: net actuarial loss	4,128	3,922	3,608
Total defined benefit pension plan adjustments	(1,208)	(3,242)	468
Net periodic benefit cost	(2,638)	(4,040)	$ (2,472)
Total recognized in net periodic benefit cost and accumulated other comprehensive loss	$ (3,846)	$ (7,282)

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EMPLOYEE BENEFIT PLANS - Estimated Benefit Payments (Details) - Defined benefit pension plan $ in Thousands	Dec. 31, 2020 USD ($)
Estimated future benefit payments
2021	$ 5,629
2022	5,954
2023	6,269
2024	6,488
2025	6,620
2026-2030	34,674
Estimated future benefit payments	65,634
Expected contribution for pension plan in next year	$ 6,500

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EMPLOYEE BENEFIT PLANS - Asset Allocations (Details) - Defined benefit pension plan	Dec. 31, 2020
Equity securities
Employee Benefit Plans
Target allocation	62.00%
Equity securities | Minimum
Employee Benefit Plans
Target allocation	45.00%
Equity securities | Maximum
Employee Benefit Plans
Target allocation	80.00%
Fixed income securities
Employee Benefit Plans
Target allocation	33.00%
Fixed income securities | Minimum
Employee Benefit Plans
Target allocation	10.00%
Fixed income securities | Maximum
Employee Benefit Plans
Target allocation	55.00%
Real estate
Employee Benefit Plans
Target allocation	5.00%
Real estate | Minimum
Employee Benefit Plans
Target allocation	0.00%
Real estate | Maximum
Employee Benefit Plans
Target allocation	10.00%

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EMPLOYEE BENEFIT PLANS - Fair Value of Plan Assets (Details) - Defined benefit pension plan - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	$ 100,969	$ 91,567	$ 75,823
Cash And Cash Equivalents | Quoted Prices In Active Markets For Identical Assets (Level 1)
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	3,888	2,958
Equities - Global | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	17,549	10,028
Equities - United States | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	31,835	26,812
Equities - United States futures | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	(2,616)
Equities - International developed markets | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	8,920	10,528
Equities - International developed markets futures | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	(4,921)
Equities - International emerging markets | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	6,600	8,410
Equities - International emerging markets futures | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	(975)
Fixed income - Investment grade | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	25,703	26,186
Fixed income - High yield | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	10,056
Fixed income - Emerging markets | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	2,664
Fixed income - Futures | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	(1,265)
Real estate | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets	$ 3,531	4,355
Pension Plan assets - Other | Net asset value per share
Employee Benefit Plans
Defined benefit plan, fair value of plan assets		$ 2,290

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COMMON UNIT-BASED COMPENSATION PLANS - LTIP Grants Activity (Details) - ARLP LTIP - USD ($) $ / shares in Units, $ in Thousands		1 Months Ended		12 Months Ended
		Dec. 31, 2020	Feb. 29, 2020	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Number of units
Balance at the beginning of the period (in units)				1,603,378		1,828,080		1,694,026
Granted (in units)				1,430,489	[1]	682,155		511,305		424,486
Vested (in units)				(919,524)	[2]	(885,381)	[3]	(331,502)	[3]
Grants canceled (in units)	[4]			(675,302)
Forfeited (in units)				(8,552)		(21,476)		(45,749)
Balance at the end of the period (in units)		1,430,489		1,430,489		1,603,378		1,828,080		1,694,026
Weighted average grant date fair value per unit
Balance at the beginning of the period (in dollars per unit)				$ 20.39		$ 17.18		$ 19.62
Granted (in dollars per unit)				5.02	[1]	18.63		20.40
Vested (in dollars per unit)				$ 21.70	[2]	12.38	[3]	34.61	[3]
Grants canceled (in dollars per unit)	[4]			18.62
Forfeited (in dollars per unit)				$ 20.16		20.84		17.40
Balance at the end of the period (in dollars per unit)		$ 5.02		$ 5.02		$ 20.39		$ 17.18		$ 19.62
Intrinsic value (in dollars)
Intrinsic value of outstanding grants (in dollars)		$ 6,409		$ 6,409		$ 17,349		$ 31,699		$ 33,372
Other information
Common units issued upon vesting			279,622			596,650		191,858
2018 Grants
Number of units
Vested (in units)		(495,038)
2019 Grants
Number of units
Grants canceled (in units)		675,302
2020 Grants
Number of units
Granted (in units)		578,114

[1] In December 2020, we modified the vesting requirements for certain restricted units that we granted in February 2020 which were determined to be improbable of vesting under the original vesting requirements (the "2020 Grants"). The new vesting requirements make it probable the modified restricted units will vest.  Also in December 2020, an additional 578,114 restricted units under these modified vesting requirements were granted.  The grant date fair value reflects the modification date fair value for those awards that were modified.

[2] In February 2020, we issued 279,622 unrestricted common units to LTIP participants as a result of satisfying the vesting requirements for 424,486 restricted units that were granted in 2017.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.  In December 2020, we accelerated the vesting requirements for 495,038 restricted units that were granted in 2018 (the "2018 Grants") and settled these restricted units in cash.

[3] During the years ended December 31, 2019 and 2018, we issued 596,650 and 191,858, respectively, unrestricted common units to LTIP participants.  The remaining vested units were settled in cash to satisfy tax withholding obligations of the LTIP participants.

[4] In December 2020, 675,302 restricted units that were granted in 2019 (the "2019 Grants") were canceled since it was determined that the vesting requirements for these restricted units were not probable of being satisfied.

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COMMON UNIT-BASED COMPENSATION PLANS - LTIP Other Information (Details) - USD ($) $ in Thousands, shares in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other information
Cash settlement of grants	$ 2,490
ARLP LTIP
Other information
Unit-based compensation expense	8,100	$ 10,400	$ 10,800
Reduction in compensation expense	1,000
Total unit-based obligation recorded	1,300	$ 20,200
Unrecognized compensation expense (in dollars)	$ 5,800
Weighted-average period for recognition of expense	2 years
Units available for grant	1.7
2018 Grants | ARLP LTIP
Other information
Incremental compensation cost	$ 5,400
2019 Grants | ARLP LTIP
Other information
Reversal of cumulative previously recognized expenses	$ 4,800

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COMMON UNIT-BASED COMPENSATION PLANS - SERP and Directors Compensation Activity (Details) - SERP and Directors' Compensation Plans - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other information
Unit-based compensation expense		$ 700	$ 1,600	$ 1,600
Total unit-based obligation recorded		$ 16,800	$ 16,100
Phantom Share Units (PSUs)
Number of units
Balance at the beginning of the period (in units)		631,365	635,837	561,784
Granted (in units)		129,265	111,012	84,417
Issued (in units)	[1]		(115,484)	(10,364)
Balance at the end of the period (in units)		760,630	631,365	635,837
Weighted average grant date fair value per unit
Balance at the beginning of the period (in dollars per unit)		$ 25.48	$ 27.34	$ 28.64
Granted (in dollars per unit)		5.25	14.50	18.78
Issued (in dollars per unit)	[1]		25.20	27.92
Balance at the end of the period (in dollars per unit)		$ 22.04	$ 25.48	$ 27.34
Intrinsic value (in dollars)
Intrinsic value of outstanding grants (in dollars)		$ 3,408	$ 6,831	$ 11,025	$ 11,067
Other information
Common units issued upon vesting			115,484	7,181

[1] During the years ended December 31, 2019 and 2018, we issued ARLP common units of 115,484 and 7,181, respectively, to participants under the SERP and Directors' Deferred Compensation Plan.  Units issued in 2018 were net of units settled in cash to satisfy tax withholding obligations.

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash Paid For:
Interest	$ 44,226	$ 43,093	$ 38,450
Income taxes	12		34
Non-Cash Activity:
Accounts payable for purchase of property, plant and equipment	5,731	14,504	14,585
Right-of-use assets acquired by operating lease	278	25,593
Market value of common units issued under deferred compensation plans before tax withholding requirements	$ 3,837	$ 17,415	$ 6,142

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ASSET RETIREMENT OBLIGATIONS - Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset retirement and mine closing liability
Balance at the beginning of the period	$ 137,514	$ 137,114
Accretion expense	4,033	4,087	$ 3,926
Payments	(1,769)	(2,948)
Allocation of liability associated with acquisitions, mine development and change in assumptions	(11,880)	(739)
Balance at the end of the period	$ 127,898	$ 137,514	$ 137,114

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ASSET RETIREMENT OBLIGATIONS - Estimated Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Estimated payments of asset retirement obligations:
2021	$ 6,411
2022	2,723
2023	2,570
2024	3,317
2025	4,601
Thereafter	210,330
Aggregate undiscounted asset retirement obligations	229,952
Effect of discounting	(102,054)	$ (102,900)
Total asset retirement obligations	127,898	137,514	$ 137,114
Less: current portion	(6,411)
Non-current asset retirement obligations	121,487	133,018
Surety bonds outstanding to performance of reclamation obligations	$ 171,100	$ 181,600

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS - Workers' Compensation Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of changes in the workers' compensation liability
Beginning balance	$ 53,384	$ 49,539
Accruals increase	5,146	7,162
Payments	(8,482)	(11,320)
Interest accretion	1,278	1,606
Valuation loss	3,413	6,397
Ending balance	$ 54,739	$ 53,384
Estimated present value of future obligations and other information
Workers' compensation discount rate	1.95%	2.81%
Letters of credit outstanding to secure workers compensation obligations	$ 95,200	$ 90,200
Other long-term assets
Estimated present value of future obligations and other information
Receivables for traumatic injury claims	$ 7,100	$ 7,700

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS - Benefit Obligations (Details) - Pneumoconiosis benefits - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of the changes in black lung benefit obligations
Benefit obligations at beginning of year	$ 97,683	$ 72,095
Service cost	3,526	2,593	$ 2,525
Interest cost	2,998	3,044	2,542
Actuarial (gain) loss	7,787	23,298
Benefits and expenses paid	(3,498)	(3,347)
Benefit obligations at end of year	$ 108,496	$ 97,683	$ 72,095

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS - Recognized in AOCL (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive loss:
Total defined benefit pension plan adjustments	$ (9,681)	$ (31,122)	$ 5,069
Pneumoconiosis benefits
Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive loss:
Net actuarial gain (loss)	(7,787)	(23,298)	4,599
Reversal of amortization item: Net actuarial (gain) loss	(686)	(4,582)	2
Total defined benefit pension plan adjustments	$ (8,473)	$ (27,880)	$ 4,601
Estimated present value of future obligations and other information
Pneumoconiosis discount rate	2.38%	3.12%	4.13%
Amount recognized in accumulated other comprehensive income consists of:
Net actuarial loss	$ 40,399	$ 31,927	$ 4,047

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS - Recognized in Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS
Workers' compensation claims	$ 54,739	$ 53,384	$ 49,539
Pneumoconiosis benefit claims	108,496	97,683
Total obligations	163,235	151,067
Less current portion	(10,646)	(11,175)
Non-current obligations	$ 152,589	$ 139,892

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ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS - Expense (Details) - Pneumoconiosis benefits - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accrued Workers Compensation And Pneumoconiosis Benefits
Service cost	$ 3,526	$ 2,593	$ 2,525
Interest cost	2,998	3,044	2,542
Net amortization	(686)	(4,582)	2
Net periodic benefit cost	5,838	1,055	5,069
Workers' compensation expense	12,305	17,541	11,270
Total pneumoconiosis expense	$ 18,143	$ 18,596	$ 16,339

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RELATED-PARTY TRANSACTIONS - Affiliate Royalty Agreements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction
As of the beginning of period	$ 53,901
As of the end of period	60,959	$ 53,901
Coal lease
Related Party Transaction
As of the beginning of period	41,216	32,645	$ 32,993
Payments	13,819	15,317	10,818
Recoupment	(4,078)	(4,178)	(3,271)
Unrecoupable	(2,568)	(2,568)	(7,895)
As of the end of period	48,389	41,216	32,645
SGP | Tunnel Ridge
Related Party Transaction
As of the beginning of period	1,500		3,000
Payments	3,000	4,500
Recoupment	(3,000)	(3,000)	(3,000)
As of the end of period	1,500	1,500
WKY CoalPlay | December 2014 coal lease - Henderson and Union Counties, Kentucky
Related Party Transaction
As of the beginning of period	16,603	14,077	10,684
Payments	3,597	3,597	3,597
Recoupment	(1,022)	(1,071)	(204)
As of the end of period	19,178	16,603	14,077
WKY CoalPlay | December 2014 coal lease - Webster County, Kentucky
Related Party Transaction
As of the beginning of period			5,356
Payments	2,568	2,568	2,570
Recoupment			(31)
Unrecoupable	(2,568)	(2,568)	(7,895)
WKY CoalPlay | December 2014 coal lease - Henderson County, Kentucky
Related Party Transaction
As of the beginning of period	12,607	10,086	7,566
Payments	2,522	2,521	2,520
As of the end of period	15,129	12,607	10,086
WKY CoalPlay | February 2015 coal lease - Henderson and Union Counties, Kentucky
Related Party Transaction
As of the beginning of period	10,506	8,482	6,387
Payments	2,132	2,131	2,131
Recoupment	(56)	(107)	(36)
As of the end of period	$ 12,582	$ 10,506	$ 8,482

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RELATED-PARTY TRANSACTIONS - Affiliate Royalty Agreements - SGP (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Tunnel Ridge
Related Party Transaction
Payments for earned royalties	$ 6.1	$ 7.2	$ 6.0
Tunnel Ridge | Joseph W Craft III Foundation | Tunnel Ridge
Related Party Transaction
Property ownership (as a percent)	0.50%
SGP | Tunnel Ridge
Related Party Transaction
Annual minimum royalties	$ 3.0

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RELATED-PARTY TRANSACTIONS - WKY CoalPlay and Cavalier Minerals (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Feb. 28, 2015	Dec. 31, 2014	Dec. 31, 2020	Jan. 03, 2019
WKY CoalPlay | February 2015 coal lease - Henderson and Union Counties, Kentucky
Related Party Transaction
Initial term of lease	20 years
Percentage of earned royalty on coal sale price	4.00%
Annual minimum royalties	$ 2.1
Period for option to acquire the leased reserves	3 years
Percentage of internal rate of return on purchase price, if leased reserves acquired	7.00%
WKY CoalPlay | December 2014 coal lease - Henderson and Union Counties, Kentucky
Related Party Transaction
Initial term of lease		20 years
Percentage of earned royalty on coal sale price		4.00%
Annual minimum royalties		$ 3.6
Period for option to acquire the leased reserves		3 years
Percentage of internal rate of return on purchase price, if leased reserves acquired		7.00%
WKY CoalPlay | December 2014 coal lease - Webster County, Kentucky
Related Party Transaction
Initial term of lease		7 years
Percentage of earned royalty on coal sale price		4.00%
Annual minimum royalties		$ 2.6
Period for option to acquire the leased reserves		3 years
Percentage of internal rate of return on purchase price, if leased reserves acquired		7.00%
Accrued payments			$ 2.6
WKY CoalPlay | December 2014 coal lease - Henderson County, Kentucky
Related Party Transaction
Annual minimum royalties		$ 2.5
Cavalier Minerals
Related Party Transaction
Ownership interest in VIE (as a percent)			96.00%
Cavalier Minerals | Bluegrass Minerals
Related Party Transaction
Noncontrolling ownership interest (as a percent)			4.00%	4.00%

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COMMITMENTS AND CONTINGENCIES - Purchase Commitments (Details) - USD ($) $ in Millions	Dec. 31, 2020	Mar. 09, 2018
Contractual Commitments
Commitments to purchase coal		$ 2.0
Commitments for external coal purchases
Contractual Commitments
Commitments to purchase coal	$ 0.0
Commitments related to planned capital projects
Contractual Commitments
Contractual amount	$ 21.0

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COMMITMENTS AND CONTINGENCIES - General Litigation (Details) - USD ($) $ in Thousands		12 Months Ended
	Mar. 09, 2018	Dec. 31, 2018
Loss Contingency, Information about Litigation Matters [Abstract]
Settlement per agreement	$ 93,000
Purchase of coal reserves, agreed amount	2,000
Legal and other costs of settlement	13,000
Net gain from settlement	$ 80,000	$ 80,000

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COMMITMENTS AND CONTINGENCIES - Insurance (Details) - Property and casualty insurance $ in Millions	Oct. 01, 2020 USD ($)
Commitments And Contingencies
Aggregate maximum insurance limit	$ 100.0
Insurance deductible	$ 1.5
Waiting period one	75 days
Waiting period	90 days
Overall aggregate deductible	$ 10.0
Percentage of participating interest in commercial property insurance program	10.00%

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CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Major Customers
Revenues	$ 1,328,129	$ 1,961,720	$ 2,002,857
Trade receivables	$ 104,579	$ 161,679
Revenue | Geographic Concentration Risk
Major Customers
Concentration of risk (as a percent)	3.30%	17.90%	27.80%
Revenue | Customer Concentration Risk | Customer A
Major Customers
Revenues	$ 197,379	$ 228,500	$ 219,115
Revenue | Customer Concentration Risk | Customer B
Major Customers
Revenues		213,319
Revenue | Customer Concentration Risk | Customer C
Major Customers
Revenues	157,271
Revenue | Customer Concentration Risk | Customer D
Major Customers
Revenues	137,785
Trade accounts receivable | Customer Concentration Risk | Major customers
Major Customers
Trade receivables	$ 32,000	$ 26,300

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SEGMENT INFORMATION - General Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 segment	Feb. 08, 2019 USD ($)	Jul. 19, 2017 USD ($)
Reportable segment results
Number of reportable segments	3
Number of coal reportable segments	2
Number of mining complex	7
Kodiak
Reportable segment results
Equity securities | $		$ 0.0	$ 100.0

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SEGMENT INFORMATION - Segment Results (Details) $ in Thousands			12 Months Ended
	Apr. 26, 2020 employee	Apr. 15, 2020 employee	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Reportable segment results
Revenues			$ 1,328,129	$ 1,961,720	$ 2,002,857
Segment Adjusted EBITDA Expense			861,249	1,204,896	1,211,800
Segment Adjusted EBITDA			446,489	672,001	715,691
Total assets			2,166,016	2,586,694	2,394,748
Capital expenditures			121,101	305,858	233,480
Gibson County mining complex
Segment Information
Number of employees terminated | employee		116
Hamilton mining complex
Segment Information
Number of employees terminated | employee	78
Illinois Basin
Reportable segment results
Revenues			770,051	1,236,308	1,321,089
Segment Adjusted EBITDA Expense			520,324	756,423	796,370
Segment Adjusted EBITDA			236,911	385,200	417,773
Total assets			1,018,916	1,373,516	1,380,912
Capital expenditures			48,648	189,270	166,468
Appalachia
Reportable segment results
Revenues			500,330	644,389	643,965
Segment Adjusted EBITDA Expense			319,730	423,623	398,243
Segment Adjusted EBITDA			172,288	215,950	240,286
Total assets			448,567	500,027	440,518
Capital expenditures			70,960	111,739	64,037
Minerals
Reportable segment results
Revenues			43,141	53,036
Segment Adjusted EBITDA Expense			4,106	7,811
Segment Adjusted EBITDA			39,773	46,997	21,323
Total assets			613,916	643,213	161,312
Other and Corporate
Reportable segment results
Revenues			25,124	56,850	81,492
Segment Adjusted EBITDA Expense			18,543	36,845	52,321
Segment Adjusted EBITDA			6,580	32,911	44,864
Total assets			477,469	541,261	589,010
Capital expenditures			1,493	4,849	2,975
Operating segments
Reportable segment results
Revenues			1,328,129	1,961,720	2,002,857
Operating segments | Illinois Basin
Reportable segment results
Revenues			770,051	1,219,618	1,289,898
Operating segments | Appalachia
Reportable segment results
Revenues			500,330	644,389	643,898
Operating segments | Minerals
Reportable segment results
Revenues			43,141	53,036
Operating segments | Other and Corporate
Reportable segment results
Revenues			14,607	44,677	69,061
Elimination
Reportable segment results
Revenues			(10,517)	(28,863)	(43,689)
Segment Adjusted EBITDA Expense			(1,454)	(19,806)	(35,134)
Segment Adjusted EBITDA			(9,063)	(9,057)	(8,555)
Total assets			(392,852)	(471,323)	(177,004)
Elimination | Illinois Basin
Reportable segment results
Revenues				16,690	31,191
Elimination | Appalachia
Reportable segment results
Revenues					67
Elimination | Other and Corporate
Reportable segment results
Revenues			$ 10,517	$ 12,173	$ 12,431

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SEGMENT INFORMATION - EBITDA Expense Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of consolidated Segment Adjusted EBITDA Expense to operating expenses (excluding depreciation, depletion and amortization)
Segment Adjusted EBITDA Expense	$ 861,249	$ 1,204,896	$ 1,211,800
Outside coal purchases		(23,357)	(1,466)
Other income (expense)	(1,593)	561	(2,621)
Operating expenses (excluding depreciation, depletion and amortization)	$ 859,656	$ 1,182,100	$ 1,207,713

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SEGMENT INFORMATION - EBITDA Reconciliation (Details) - USD ($) $ in Thousands		12 Months Ended
	Mar. 09, 2018	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of consolidated Segment Adjusted EBITDA to net income
Consolidated Segment Adjusted EBITDA		$ 446,489	$ 672,001	$ 715,691
General and administrative		(59,806)	(72,997)	(68,298)
Depreciation, depletion and amortization		(313,387)	(309,075)	(280,225)
Settlement gain	$ 80,000			80,000
Asset impairment		(24,977)	(15,190)	(40,483)
Goodwill impairment		(132,026)	0	0
Interest expense, net		(45,478)	(45,496)	(40,059)
Acquisition gain			177,043
Income tax (expense) benefit		(35)	211	(22)
Acquisition gain attributable to noncontrolling interest			(7,083)
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP		(129,220)	399,414	366,604
Noncontrolling interest		169	7,512	866
NET INCOME (LOSS)		$ (129,051)	$ 406,926	$ 367,470

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - CONDENSED BALANCE SHEETS (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents	$ 55,574	$ 36,482
Total current assets	245,774	319,585
OTHER ASSETS:
Total other assets	119,997	258,123
TOTAL ASSETS	2,166,016	2,586,694	$ 2,394,748
CURRENT LIABILITIES:
Accrued taxes other than income taxes	25,054	15,768
Total current liabilities	214,605	195,586
Total liabilities	1,093,749	1,321,270
PARTNERS' CAPITAL:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively	1,148,565	1,331,482
TOTAL LIABILITIES AND PARTNERS' CAPITAL	2,166,016	2,586,694
Parent Company
CURRENT ASSETS:
Cash and cash equivalents	2,174	2,176
Total current assets	2,174	2,176
OTHER ASSETS:
Investments in consolidated subsidiaries	1,146,491	1,329,406
Total other assets	1,146,491	1,329,406
TOTAL ASSETS	1,148,665	1,331,582
CURRENT LIABILITIES:
Accrued taxes other than income taxes	100	100
Total current liabilities	100	100
Total liabilities	100	100
PARTNERS' CAPITAL:
Limited Partners - Common Unitholders 127,195,219 and 126,915,597 units outstanding, respectively	1,148,565	1,331,482
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 1,148,665	$ 1,331,582

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - CONDENSED BALANCE SHEETS (Parenthetical) (Details) - shares	Dec. 31, 2020	Dec. 31, 2019
Condensed Financial Statements, Captions [Line Items]
Common units outstanding	127,195,219	126,915,597
Parent Company
Condensed Financial Statements, Captions [Line Items]
Common units outstanding	127,195,219	126,915,597

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - CONDENSED STATEMENT OF OPERATIONS (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
EXPENSES:
General and administrative	$ 59,806	$ 72,997	$ 68,298
Total operating expenses	1,410,981	1,702,222	1,630,570
INCOME (LOSS) FROM OPERATIONS	(82,852)	259,498	372,287
Interest income	135	379	159
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	(129,220)	399,414	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER			1,560
LIMITED PARTNERS	$ (129,220)	$ 399,414	$ 365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$ (1.02)	$ 3.07	$ 2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC AND DILUTED	127,164,659	128,116,670	130,758,169
Parent Company
EXPENSES:
General and administrative		$ 41	$ 30
Total operating expenses		41	30
INCOME (LOSS) FROM OPERATIONS		(41)	(30)
Interest income	$ 24	34	22
Equity in earnings of consolidated subsidiaries	(129,244)	399,421	366,612
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP	(129,220)	399,414	366,604
NET INCOME (LOSS) ATTRIBUTABLE TO ARLP
GENERAL PARTNER			1,560
LIMITED PARTNERS	$ (129,220)	$ 399,414	$ 365,044
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED	$ (1.02)	$ 3.07	$ 2.74
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC AND DILUTED	127,164,659	128,116,670	130,758,169

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - CONDENSED STATEMENT OF CASH FLOWS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
CASH FLOWS FROM OPERATING ACTIVITIES	$ 400,645	$ 514,895	$ 694,345
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions paid to Partners	(51,753)	(278,425)	(275,902)
Net cash used in financing activities	(256,429)	(234,447)	(211,702)
NET CHANGE IN CASH AND CASH EQUIVALENTS	19,092	(207,668)	237,394
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	36,482	244,150	6,756
CASH AND CASH EQUIVALENTS AT END OF PERIOD	55,574	36,482	244,150
Parent Company
CASH FLOWS FROM OPERATING ACTIVITIES:
CASH FLOWS FROM OPERATING ACTIVITIES	51,751	278,308	275,924
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions paid to Partners	(51,753)	(278,425)	(275,902)
Net cash used in financing activities	(51,753)	(278,425)	(275,902)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(2)	(117)	22
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	2,176	2,293	2,271
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 2,174	$ 2,176	$ 2,293

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SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF REGISTRANT - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed Financial Statements, Captions [Line Items]
Cash contribution by affiliated entity			$ 2,142
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash contribution by affiliated entity	$ 51,800	$ 278,400	$ 275,900