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, 2023
 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.
 If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
 Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).
 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 $ 1,948,772,132 as of June 30, 2023, 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, 2024, 128,061,981 common units were outstanding.
 DOCUMENTS INCORPORATED BY REFERENCE: None

 Page

 Item 1.

 Business

 Item 1A.

 Risk Factors

 Item 1B.

 Unresolved Staff Comments

 Item 1C.

 Cybersecurity

 Item 2.

 Properties

 Item 3.

 Legal Proceedings

 Item 4.

 Mine Safety Disclosures

 Item 5.

 Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

 Item 6.

 [Reserved]

 Item 7.

 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A.

 Quantitative and Qualitative Disclosures about Market Risk

 Item 8.

 Financial Statements and Supplementary Data

 Report of Independent Registered Public Accounting Firm-Grant Thornton LLP (PCAOB ID Number 248)

 Consolidated Balance Sheets

 Consolidated Statements of Income

 Consolidated Statements of Comprehensive Income

 Consolidated Statements of Cash Flows

 Consolidated Statement of Partners' Capital

 Notes to Consolidated Financial Statements

 1. Organization and Presentation

 2. Summary of Significant Accounting Policies

 3. Acquisitions

 4. Inventories

 5. Property, Plant and Equipment

 6. Long-Term Debt

 7. Income Taxes

 8. Leases

 9. Fair Value Measurements

 10. Partners' Capital

 11. Variable Interest Entities

 12. Equity Investments

 13. Revenue From Contracts With Customers

 14. Earnings Per Limited Partner Unit

 15. Employee Benefit Plans

 16. Common Unit-Based Compensation Plans

 17. Supplemental Cash Flow Information

 18. Asset Retirement Obligations

 19. Accrued Workers' Compensation and Pneumoconiosis Benefits

 20. Related-Party Transactions

 21. Commitments and Contingencies

 22. Concentration of Credit Risk and Major Customers

 23. Segment Information

 Supplemental Oil & Gas Reserve Information (Unaudited)

 Schedule I – Condensed Financial Information of Registrant

 Item 9.

 Changes in and Disagreements with Accountant on Accounting and Financial Disclosure

 Item 9A.

 Controls and Procedures

 Item 9B.

 Other Information

 Item 10.

 Directors, Executive Officers and Corporate Governance of the General Partner

 Item 11.

 Executive Compensation

 Item 12.

 Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

 Item 13.

 Certain Relationships and Related Transactions, and Director Independence

 Item 14.

 Principal Accountant Fees and Services

 Item 15.

 Exhibits and Financial Statement Schedules

 ii

 GLOSSARY

 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 and oil & gas industries:

 2020 Grants

 Restricted units that were granted in 2020

 2022 Registration Statement

 In February 2022, we filed with the SEC a universal shelf registration statement which allows us to issue from time to time an indeterminate amount of debt or equity securities.

 A&D

 Acquisitions and Divestitures

 ACE Rule

 The Affordable Clean Energy Rule

 Acquisition Gain

 The $177.0 million non-cash acquisition gain recognized in 2019 related to the acquisition of the remaining interests in AllDale Minerals LP and AllDale Minerals II, LP

 AGP

 Alliance GP, LLC

 AHGP

 Our subsidiary, Alliance Holdings GP, L.P.

 AllDale I

 Our subsidiary, AllDale Minerals, LP

 AllDale I & II

 Collectively our subsidiaries, AllDale Minerals, LP and AllDale Minerals II, LP

 AllDale II

 Our subsidiary, AllDale Minerals II, LP

 AllDale III

 AllDale Minerals III, LP

 Alliance Coal

 Alliance Coal, LLC, an indirect wholly owned subsidiary of ARLP

 Alliance Design

 Our subsidiary, Alliance Design Group, LLC

 Alliance Finance

 Our subsidiary, Alliance Resource Finance Corporation

 Alliance Minerals

 Alliance Minerals, LLC, an indirect wholly owned subsidiary of ARLP

 Alliance Properties

 Our subsidiary, Alliance Properties, LLC

 Alliance Resource Properties

 Alliance Resource Properties, LLC, an indirect wholly owned subsidiary of ARLP

 Alliance WOR Properties

 Our subsidiary, Alliance WOR Properties, LLC

 Allocation Date

 That first day of each month in which we prorate our items of income, gain, loss and deduction between transferors and transferees of our units based upon the ownership of our units on that day

 AR Midland

 Our subsidiary, AR Midland, LP

 ARH

 Alliance Resource Holdings, Inc.

 ARLP

 Alliance Resource Partners, L.P., individually as the parent company, and not on a consolidated basis

 iii

 ARLP Partnership

 The business and operations of Alliance Resource Partners, L.P., the parent company, as well as its consolidated subsidiaries; references to "Partnership", "we", "us" or "our" also refer to the ARLP Partnership

 AROP Funding

 Our subsidiary, AROP Funding, LLC

 ASC

 Accounting Standards Codification

 Ascend

 Ascend Elements, Inc.

 ASI

 Our subsidiary, Alliance Service, Inc.

 Assigned reserves

 Reserves that have been designated for mining by a specific operation

 ASU

 Accounting Standards Update

 ASU 2023-07

 ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures

 ASU 2023-09

 ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures

 Audit Committee

 The audit committee of the Board of Directors

 Bankruptcy Code

 Title 11 of the United State Code

 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

 Belvedere

 Belvedere Operating, LLC

 Belvedere Acquisition

 On September 9, 2022, AR Midland acquired approximately 394 net oil & gas royalty acres in the Delaware Basin from Belvedere.

 Belvedere Acquisition Date

 September 9, 2022

 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

 BLBA

 Federal Black Lung Benefits Act

 Bluegrass Minerals

 Bluegrass Minerals Management, LLC

 Board of Directors

 The board of directors of our general partner

 BOE

 Barrels of oil equivalent, with six Mcf of natural gas being equivalent to one Bbl of crude oil, condensate, or natural gas liquids

 iv

 Boulders

 Boulders Royalty Corp.

 Boulders Acquisition

 On October 13, 2021, AR Midland acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders.

 BSER

 Best System of Emission Reduction

 Btu

 British thermal unit

 CAA

 Federal Clean Air Act

 CAIR

 Clean Air Mercury Rule

 Cavalier Minerals

 Our subsidiary, Cavalier Minerals JV, LLC

 CCB

 Coal combustion by-products

 CCRs

 Coal combustion residues

 CEO

 Chief Executive Officer

 CERCLA

 Federal Comprehensive Environmental Response, Compensation and Liability Act

 CEQ

 Council on Environmental Quality

 CFO

 Chief Financial Officer

 CGA

 Cawley, Gillespie & Associates, Inc.

 Circuit Court

 United States Court of Appeals for the District of Columbia

 CODM

 Chief operating decision maker

 Compensation Committee

 The compensation committee of the Board of Directors

 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

 Conflicts Committee

 The conflicts committee of the Board of Directors

 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

 COP26

 26 th Conference of the Parties

 COP27

 27 th Conference of the Parties

 COP28

 28 th Conference of the Parties

 Corps of Engineers

 United States Army Corps of Engineers

 COSO

 Committee of Sponsoring Organizations of the Treadway Commission

 CPP

 Clean Power Plan

 Craft Foundations

 Collectively, the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation

 v

 Credit Agreement

 The credit agreement entered into by Alliance Coal, as borrower, on January 13, 2023

 CSAPR

 Cross-State Air Pollution Rule

 CSX

 CSX Transportation, Inc.

 CTO

 Chief Technology Officer

 CWA

 Federal Clean Water Act

 DERs

 Distribution equivalent rights

 Developed acreage

 Acreage allocated or assignable to productive wells

 Directors' Deferred Compensation Plan

 Alliance Resource Management GP, L.P. Amended & Restated Deferred Compensation Plan for Directors

 DMP

 Division of Mine Permits

 DOL

 U.S. Department of Labor

 EGUs

 Electric generating units

 ELG

 Effluent Limitations Guidelines and Standards

 EPA

 United States Environmental Protection Agency

 EPU

 Earnings per limited partner unit

 ESA

 Endangered Species Act

 EV

 Electric vehicle

 Excel

 Excel Mining, LLC

 Exchange Act

 Securities Exchange Act of 1934

 FASB

 Financial Accounting Standards Board

 FIPs

 Federal Implementation Plans

 FMSHA

 Federal Mine Health and Safety Act of 1977, as amended by the Federal Mine Improvement and New Emergency Response Act of 2006

 Francis Renewable Energy, LLC

 GAAP

 Generally Accepted Accounting Principles

 GFANZ

 Glasgow Financial Alliance for Net Zero

 GHG

 Greenhouse gas

 Gibson

 Our subsidiary, Gibson County Coal, LLC

 Gibson South

 Our subsidiary, Gibson County Coal (South), LLC

 vi

 Grant Thornton

 Grant Thornton LLP

 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.

 Hamilton

 Our subsidiary, Hamilton County Coal, LLC

 Haymaker

 Haymaker Minerals & Royalties II, LLC

 High-sulfur coal

 Based on market expectations, our classification of coal with a sulfur content of greater than 3%

 HLBV

 Hypothetical liquidation at book value

 Indicated mineral resource (coal)

 That part of a mineral resource for which quantity and grade or quality are estimated on the basis of adequate geological evidence and sampling. The level of geological certainty associated with an indicated mineral resource is sufficient to allow a qualified person to apply modifying factors in sufficient detail to support mine planning and evaluation of the economic viability of the deposit. Because an indicated mineral resource has a lower level of confidence than the level of confidence of a measured mineral resource, an indicated mineral resource may only be converted to a probable mineral reserve.

 Inferred mineral resource (coal)

 That part of a mineral resource for which quantity and grade or quality are estimated on the basis of limited geological evidence and sampling. The level of geological uncertainty associated with an inferred mineral resource is too high to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Because an inferred mineral resource has the lowest level of geological confidence of all mineral resources, which prevents the application of the modifying factors in a manner useful for evaluation of economic viability, an inferred mineral resource may not be considered when assessing the economic viability of a mining project, and may not be converted to a mineral reserve.

 Infinitum

 Infinitum Electric, Inc.

 Intermediate Partnership

 Alliance Resource Operating Partners, L.P., the intermediate partnership of Alliance Resource Partners, L.P.

 IRAs

 Individual retirement accounts

 IRS

 Internal Revenue Service

 Island Creek

 Island Creek Coal Company

 Jase

 Jase Minerals, LP

 Jase Acquisition

 On October 26, 2022, AR Midland acquired approximately 3,928 net oil & gas royalty acres in the Permian Basin from Jase.

 Jase Acquisition Date

 October 26, 2022

 JC Land

 JC Land LLC

 JC Resources

 JC Resources LP

 JC Resources Acquisition

 On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources LP.

 vii

 KYDNR

 Kentucky Department of Natural Resources

 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%

 LTIP

 Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan

 MAC

 Our subsidiary, Mid-America Carbonates, LLC

 Matrix Design

 Our subsidiary, Matrix Design Group, LLC

 Matrix Group

 Collectively our subsidiaries, Alliance Design, ASI and its subsidiary, Matrix Design and its subsidiaries Matrix Design International, LLC, Matrix Design Africa (PTY) LTD, and Matrix Design (Australia) PTY, LTD

 MATS

 Mercury and Air Toxics Standards

 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

 MC Mining

 Our subsidiary, MC Mining, LLC

 Mcf

 Thousand cubic feet of natural gas

 Measured mineral resource (coal)

 That part of a mineral resource for which quantity and grade or quality are estimated on the basis of conclusive geological evidence and sampling. The level of geological certainty associated with a measured mineral resource is sufficient to allow a qualified person to apply modifying factors, as defined in this section, in sufficient detail to support detailed mine planning and final evaluation of the economic viability of the deposit. Because a measured mineral resource has a higher level of confidence than the level of confidence of either an indicated mineral resource or an inferred mineral resource, a measured mineral resource may be converted to a proven mineral reserve or to a probable mineral reserve.

 Medium-sulfur coal

 Based on market expectations, our classification of coal with a sulfur content of 1.5% to 3%

 Metallurgical coal

 Coal primarily used in the production of steel

 Mettiki

 Mettiki Complex, including the Mountain View mine operated by our subsidiary, Mettiki (WV) and the preparation plant operated by our subsidiary, Mettiki (MD)

 Mettiki (MD)

 Our subsidiary, Mettiki Coal, LLC

 Mettiki (WV)

 Our subsidiary, Mettiki Coal (WV), LLC

 MGP

 Alliance Resource Management GP, L.P., ARLP's general partner

 MINER Act

 Federal Mine Improvement and New Emergency Response Act of 2006

 viii

 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

 Mineral reserve (coal)

 An estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

 Mineral resource (coal)

 A concentration or occurrence of material of economic interest in or on the Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. It is not merely an inventory of all mineralization drilled or sampled.

 MMBtus

 Million British thermal units

 MMcf

 Million cubic feet of natural gas

 Mr. Craft

 Joseph W. Craft III, the Chairman, President and Chief Executive Officer of MGP

 MSHA

 Mine Safety and Health Administration

 Mt. Vernon

 Our subsidiary, Mt. Vernon Transfer Terminal, LLC

 NAAQS

 National Ambient Air Quality Standards

 Named Executive Officers

 Our 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 2023

 NEPA

 National Environmental Policy Act

 Net acres

 The actual ownership interest within a specified tract expressed in acres. For example, an owner who has a 50 percent interest in 100 acres owns 50 net acres.

 Net royalty acres

 Mineral ownership standardized to a 12.5%, or 1/8 th, royalty interest

 NGFS

 Network for Greening the Financial System

 NGLs

 Natural gas liquids are components of natural gas that are liquid at the surface in field facilities or gas-processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline), and high (liquefied petroleum gas) vapor pressure. Natural gas liquids include propane, butane, pentane, hexane, and heptane, but not methane and ethane since these hydrocarbons need refrigeration to be liquefied. The term is commonly abbreviated as NGL.

 NGP

 NGP Energy Capital Management, LLC

 NGP ET IV

 NGP Energy Transition, L.P.

 NS

 Norfolk Southern Railway Company

 ix

 NSPS

 New Source Performance Standards

 NSR

 New source review

 Oil & gas

 Crude oil, natural gas, and natural gas liquids

 Old Ben

 Old Ben Coal Company

 Old Ben Leases

 Leases originally taken by AMAX Coal Company and Old Ben Coal Company in the mid to late 1970's and early 1980's

 Operator

 The individual or company responsible for the exploration and/or production of a Mineral Interest which, with respect to our Mineral Interests, are unaffiliated third-parties

 OSM

 OWCP

 Federal Office of Surface Mining

 Office of Workers' Compensation Programs

 PADEP

 Pennsylvania Department of Environmental Protection

 PAL

 Paducah & Louisville Railway, Inc.

 Patriot

 Patriot Coal Corporation

 PCAOB

 Public Company Accounting Oversight Board

 Peabody

 Peabody Energy Corporation

 Pension Plan

 Alliance Coal, LLC and Affiliates Pension Plan for Coal Employees

 PM

 Fine particulate matter

 Preparation plant

 A facility used for crushing, sizing, and washing coal to remove impurities and to prepare it for use by a particular customer

 Probable mineral reserve (coal)

 The economically mineable part of an indicated and, in some cases, a measured mineral resource

 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 (oil & gas)

 Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods

 Proved reserves or properties (oil & gas)

 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 (oil & gas)

 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

 x

 Proven mineral reserve (coal)

 The economically mineable part of a measured mineral resource and can only result from conversion of a measured mineral resource

 PSSP

 Profit sharing and savings plan

 PUDs

 Proved undeveloped reserves

 RCRA

 Federal Resource Conservation and Recovery Act

 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 (oil & gas)

 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.

 RESPEC

 RESPEC Company, LLC

 Revolving Credit Facility

 The Credit Agreement provides for a $425 million revolving credit facility, which includes a sublimit of $15.0 million for swingline borrowings and permits the issuance of letters of credit up to the full amount of $425 million

 RGGI

 Regional Greenhouse Gas Initiative agreement

 River View

 Our subsidiary, River View Coal, LLC

 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

 Royalty interest

 An interest that gives the owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations

 Sebree

 Our subsidiary, Sebree Mining, LLC

 SEC

 United States Securities and Exchange Commission

 Securities Act

 Securities Act of 1933

 Securitization Facility

 Certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership are party to a $90.0 million accounts receivable securitization facility.

 Senior Notes

 An aggregate original principal amount of $400.0 million of senior unsecured notes due 2025 issued on April 24, 2017 by the Intermediate Partnership and Alliance Finance.

 SERP

 Alliance Coal, LLC Supplemental Executive Retirement Plan

 SIPs

 State implementation plans

 Skyland

 Skyland Minerals, L.P.

 xi

 Skyland Acquisition

 On December 7, 2023, we acquired approximately 2,372 oil & gas net royalty acres predominantly in the Anadarko Basin, along with acreage in the Williston and Delaware Basins from Skyland Minerals, L.P. and Haymaker Minerals & Royalties II, LLC.

 Skyland Acquisition Date

 December 7, 2023

 SMCRA

 Federal Surface Mining Control and Reclamation Act of 1977

 STIP

 Alliance Resource Management GP, LLC Short-Term Incentive Plan

 Subsidiary Guarantors

 Certain subsidiaries of ARLP, including the Intermediate Partnership and most of the direct and indirect subsidiaries of Alliance Coal, guaranteeing the Credit Agreement.

 Tax Election

 On March 15, 2022, Alliance Minerals changed its federal income tax status from a pass-through entity to a taxable entity via a "check the box" election.

 Term Loan

 The Credit Agreement provides for a term loan in an aggregate principal amount of $75 million.

 Thermal coal

 Coal used primarily in the generation of electricity

 TMDL

 Total Maximum Daily Load

 TRRC

 Texas Railroad Commission

 TRS

 Technical Report Summary

 Tunnel Ridge

 Our subsidiary, Tunnel Ridge, LLC

 UIC

 Underground Injection Control

 Unassigned reserves (coal)

 Reserves that have not yet been designated for mining by a specific operation

 Undeveloped acreage (oil & gas)

 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 (oil & gas)

 Properties with no proved reserves. We also consider unproved reserves or properties to be defined as the estimated quantities of oil & gas determined based on geological and engineering data similar to that used in estimates of proved reserves; but technical, contractual, economic, or regulatory uncertainties preclude such reserves from being classified as proved.

 USEA

 United States Energy Association

 USFWS

 United States Fish and Wildlife Service

 USGA

 United States Geological Survey

 Valley Camp

 Valley Camp Coal Company

 VIE

 Variable interest entity

 VOC

 Volatile organic compound

 Warrior

 Our subsidiary, Warrior Coal, LLC

 xii

 Webster

 Our subsidiary, Webster County Coal, LLC

 Wildcat Insurance

 Our subsidiary, Wildcat Insurance, LLC

 WKY CoalPlay

 WKY CoalPlay, LLC

 WKY11

 West Kentucky No. 11

 WKY6

 West Kentucky No. 6

 WKY7

 West Kentucky No. 7

 WKY9

 West Kentucky No. 9

 WOTUS

 Waters of the United States

 WVDEP

 West Virginia Department of Environmental Protection

 xiii

 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:

 decline in the coal industry's share of electricity generation, including as a result of environmental concerns related to coal mining and combustion, the cost and perceived benefits of other sources of electricity and fuels, such as oil & gas, nuclear energy, and renewable fuels and the planned retirement of coal-fired power plants in the U.S.;

 changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;

 changes in global economic and geo-political conditions or changes in industries in which our customers operate;

 changes in commodity prices, demand and availability which could affect our operating results and cash flows;

 the outcome or escalation of current hostilities in Ukraine and the Israel-Gaza conflict;

 the severity, magnitude, and duration of any future pandemics and impacts of such pandemics and of businesses' and governments' responses to such pandemics on our operations and personnel, and on demand for coal, oil, and natural gas, the financial condition of our customers and suppliers and Operators, available liquidity and capital sources and broader economic disruptions;

 actions of the major oil-producing countries with respect to oil production volumes and prices could have direct and indirect impacts over the near and long term on oil & gas exploration and production operations at the properties in which we hold mineral interests;

 changes in competition in domestic and international coal markets and our ability to respond to such changes;

 potential shut-ins of production by the Operators of the properties in which we hold oil & gas mineral interests due to low commodity 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 and to successfully integrate such acquisitions into our business and achieve the anticipated benefits therefrom;

 our ability to identify and invest in new energy and infrastructure transition ventures;

 the success of our development plans for Matrix Group, and our investments in emerging infrastructure and technology companies;

 dependence on significant customer contracts, including renewing existing contracts upon expiration;

 adjustments made in price, volume, or terms to existing coal supply agreements;

 the effects of and changes in trade, monetary and fiscal policies and laws central bank policy actions including interest rates, bank failures, and associated liquidity risks;

 the effects of and changes in taxes or tariffs and other trade measures adopted by the United States and foreign governments;

 legislation, regulations, and court decisions and interpretations thereof, both domestic and foreign, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, hydraulic fracturing, and health care;

 deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

 investors' and other stakeholders' increasing attention to environmental, social, and governance 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;

 xiv

 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 equipment, raw material, service or labor costs or availability, including due to inflationary pressures;

 changes in our ability to recruit, hire and maintain labor;

 our ability to maintain satisfactory relations with our employees;

 increases in labor costs including costs of health insurance and taxes resulting from the Affordable Care Act, adverse changes in work rules, or cash payments or projections associated with workers' compensation claims;

 increases in transportation costs and risk of transportation delays or interruptions;

 operational interruptions due to geologic, permitting, labor, weather, supply chain shortage of equipment or mine supplies, or other factors;

 risks associated with major mine-related accidents, mine fires, mine floods, or other interruptions;

 results of litigation, including claims not yet asserted;

 foreign currency fluctuations that could adversely affect the competitiveness of our coal abroad;

 difficulty maintaining our surety bonds for mine reclamation as well as workers' compensation and black lung benefits;

 difficulty in making accurate assumptions and projections regarding post-mine reclamation as well as pension, black lung benefits, and other post-retirement benefit liabilities;

 uncertainties in estimating and replacing our coal mineral reserves and resources;

 uncertainties in estimating and replacing our oil & gas reserves;

 uncertainties in the amount of oil & gas production due to the level of drilling and completion activity by the operators of our oil & gas properties;

 uncertainties in the future of the electric vehicle industry and the market for EV charging stations;

 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 SEC; our press releases; our website www.arlp.com; and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

 xv

 ITEM 1. BUSINESS

 Introduction

 We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests located in strategic producing regions across the United States. The primary focus of our business is to maximize the value of our existing mineral assets, both in the production of coal from our mining assets and the leasing and development of our coal and oil & gas mineral ownership. In addition, we are positioning ourselves as a reliable energy provider for the future as we pursue opportunities that support the advancement of energy and related infrastructure. We intend to pursue strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. We believe that our diverse and rich resource base and strategic investments will allow us to continue to create long-term value for unitholders.

 We are the largest coal producer in the eastern United States with seven operating underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia as well as a coal-loading terminal in Indiana on the Ohio River. We manage and report our coal operations under two regions, Illinois Basin and Appalachia. We market our coal production to major domestic and international utilities and industrial users.

 We own mineral and royalty interests in approximately 67,700 net royalty acres, including approximately 4,000 net royalty acres attributable to our equity interest in AllDale III, in premier oil & gas producing regions in the United States, primarily the Permian, Anadarko, and Williston Basins. While we own both oil & gas 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 oil & gas mineral interests for lease to Operators in those regions and generate royalty income from the leasing and development of those mineral interests. Reserve additions and the associated cash flows are expected to increase from the development of our existing mineral interests and through acquisitions of additional mineral interests.

 We have approximately 663.2 million tons of coal mineral reserves and 1.06 billion tons of coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. Substantially, all of our coal mineral resources and 557.7 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties, which are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. We market our coal mineral reserves and resources to the coal mining operations that are able to access them and generate royalty income from the leasing and development of those coal mineral reserves and resources.

 We have invested in energy and infrastructure opportunities including Ascend, Francis, Infinitum, and NGP ET IV as described below.

 In addition, through our technology company, Matrix Group, we develop and market industrial, mining and technology products and services worldwide.

 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.

 Oil & Gas Acquisitions

 The following acquisitions enhance our ownership position in the Permian Basin and further our business strategy to grow our Oil & Gas Royalties segment.

 Acquisition Agreement

 On January 27, 2023, we entered into a one-year collaborative agreement with a third party effective January 1, 2023, committing up to $35.0 million for the acquisition of oil & gas mineral interests in the Midland and Delaware basins. Under the agreement, the third party assisted us in the identification, evaluation, and acquisition of target oil & gas mineral interests. In exchange for these services, the third party received a participation share, partially funded by the third party, and was paid a periodic management fee. We acquired $13.2 million oil & gas mineral interests under the agreement in 2023. On February 19, 2024, we renewed this agreement for an additional one-year term, committing up to $25.0 million.

 JC Resources

 On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources, a related party entity owned by Mr. Craft, for $72.3 million.

 Skyland

 On December 7, 2023, we acquired approximately 2,372 oil & gas net royalty acres predominantly in the Anadarko Basin, along with acreage in the Williston and Delaware Basins from Skyland and Haymaker for a combined purchase price of $14.5 million.

 The following investments in the advancement of energy and related infrastructure further our business strategy to develop strategic relationships and invest in attractive opportunities that leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation. For more information on our acquisitions and investments, please read "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions","—Note 11 – Variable Interest Entities" and "—Note 12 – Equity Investments" of this Annual Report on Form 10-K.

 On April 5, 2022, we made a $20.0 million convertible note investment in Francis which converted to a preferred equity interest on April 1, 2023. Francis currently is active in the installation, management and operation of metered-for-fee, public-access EV charging stations. Francis also develops and constructs EV charging stations for third-party customers.

 Ascend

 On September 6, 2023, we purchased $25.0 million of Series D Preferred Stock in Ascend. Ascend is a U.S.-based manufacturer and recycler of sustainable, closed-loop engineered battery materials for electric vehicles. Ascend is currently constructing North America's first commercial-scale manufacturing facility located near Hopkinsville, Kentucky, that when complete, will produce enough cathode materials for 750,000 electric vehicles per year.

 Infinitum

 On September 8, 2023, we increased our investment in Infinitum to $66.6 million by purchasing $24.6 million of Series E Preferred Stock. Infinitum is a Texas-based startup developer and manufacturer of electric motors featuring printed circuit board stators which have the potential to result in motors that are smaller, lighter, quieter, more efficient and capable of operating at a fraction of the carbon footprint of conventional electric motors.

 Matrix Group

 Matrix Group provides a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties. On January 16, 2024, Matrix Design entered into an agreement with Infinitum to jointly develop and distribute high-efficiency motors and advanced motor controllers designed specifically for the mining industry. Under the agreement, Matrix Design will integrate Infinitum's motor technology into mining equipment of our operating subsidiaries to provide performance validation in production environments for jointly

 developed products and to improve our operational efficiency, and market the jointly developed technology and products to third parties worldwide.

 The following diagram depicts our simplified organization and ownership as of December 31, 2023:

 Our internet address is www.arlp.com, and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, Forms 3, 4 and 5 for our Section 16 filers and other documents (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.

 The SEC maintains a website that contains reports, proxy and information statements, and other information for issuers, including us. The public can obtain any documents that we file with the SEC at www.sec.gov.

 Coal Mining Operations

 Coal is used primarily for the generation of electric power and the production of steel but is also used for chemical, food, and cement processing. We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). We have established long-term relationships with customers through exemplary and consistent performance.

 At December 31, 2023, our mining operations had access to approximately 663.2 million tons of coal mineral reserves and 1.06 billion tons of coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia. Substantially, all of our coal mineral resources and 557.7 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties and are currently leased or subleased or held for lease or sublease to our mining operations or others. We produce a diverse range of thermal and metallurgical coal with varying sulfur and heat contents, which enables us to satisfy the broad range of specifications required by our customers. In 2023, we sold 34.4 million tons of coal and produced 34.9 million tons. Of the 34.4 million tons sold, approximately 60% were leased from Alliance Resource Properties. The coal we sold in 2023 was approximately 3.6% low-sulfur coal, 33.4% medium-sulfur coal, and 63.0% high-sulfur coal. In 2023, approximately 80.9% of our tons sold were purchased by domestic electric utilities and 15.7% were sold into the international markets through brokered transactions. The balance of our tons sold was to third-party resellers and industrial consumers. For tons sold to domestic electric utilities, 100.0% were sold to utility plants with installed pollution control devices. The Btu content of our coal ranges from 11,450 to 13,200.

 The following chart summarizes our coal production by region for the last three years.

 Coal Regions

 2023

 2022

 2021

 (tons in millions)

 25.2

 24.3

 22.2

 Appalachia

 9.7

 11.2

 10.0

 Total

 34.9

 35.5

 32.2

 The following map shows the location of our coal mining operations:

 Illinois Basin Operations:

 D. WARRIOR COMPLEX

 G. METTIKI COMPLEX

 A. GIBSON COMPLEX

 Warrior Mine

 Mountain View Mine

 Gibson South Mine

 Mining Method: Room & Pillar

 Mining Method: Longwall

 Mining Method: Room & Pillar

 Coal Type: Medium/High-Sulfur

 & Continuous Miner

 Coal Type: Low/Medium-Sulfur

 Transportation: Barge, Railroad,

 Coal Type: Low/Medium

 Transportation: Barge, Railroad

 Sulfur - Metallurgical

 Transportation: Railroad

 E. MOUNT VERNON

 B. RIVER VIEW COMPLEX

 TRANSFER TERMINAL

 a) River View Mine

 Rail or Truck to Ohio River Barge

 H. MC MINING COMPLEX

 b) Henderson County Mine

 Transloading Facility

 Excel Mine No. 5

 Appalachian Operations:

 Mining Method: Room & Pillar

 F. TUNNEL RIDGE COMPLEX

 Mining Method: Room & Pillar

 Coal Type: Medium/High-Sulfur

 Tunnel Ridge Mine

 Coal Type: Low-Sulfur

 Transportation: Barge & Truck

 Transportation: Barge, Railroad,

 C. HAMILTON COMPLEX

 Mining Method: Longwall

 Hamilton Mine

 & Continuous Miner

 Coal Type: Medium/High-Sulfur

 Transportation: Barge

 Mining Method: Longwall

 & Continuous Miner

 Coal Type: Medium/High-Sulfur

 Transportation: Barge, Railroad

 We lease most of our coal mineral reserves and resources from Alliance Resource Properties or private parties and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal mineral reserve or resource area. These leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. 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, 2023, we have 2,189 employees and we operate four active mining complexes in the Illinois Basin.

 Gibson Complex

 Our subsidiary, Gibson, 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 or NS railroads from our rail loadout facility directly to customers or various transloading facilities, including our Mt. Vernon transloading facility, for barge delivery. Production from the mine began in April 2014. Gibson production in 2023 was 5.3 million tons.

 River View Complex

 Our subsidiary, River View, operates the River View mine and the Henderson County mine. The River View mine 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 production in 2009 and utilizes continuous mining units to produce medium/high-sulfur coal from multiple seams. The Henderson County mine is located in Henderson County, Kentucky and is currently under development, with full production expected to begin in 2024 from the No. 9 seam.

 Both mines will utilize the existing preparation plant, refuse disposal, and loadout facilities. River View's preparation plant has throughput capacity of 2,700 tons of raw coal per hour. Coal produced from the River View complex is transported by overland belt to a barge loading facility on the Ohio River. River View coal production in 2023 was 9.9 million tons.

 Hamilton Complex

 Our subsidiary, Hamilton, operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois. The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal. Longwall mining began in October 2014 and we acquired complete ownership and control in 2015. Hamilton's preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Hamilton has the ability to ship coal from the Hamilton mine via the CSX, Evansville Western Railway, or NS rail directly to customers or various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries. Hamilton coal production in 2023 was 5.6 million tons.

 Warrior Complex

 Our subsidiary, Warrior, operates an underground mining complex located near the city of Madisonville in Hopkins County, Kentucky. The Warrior complex was opened in 1985, and we acquired it in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques to produce medium/high-sulfur coal. Warrior's preparation plant has throughput capacity of 1,200 tons of raw coal per hour. Warrior's production is shipped via the CSX or PAL railroads or by truck directly to customers or potentially to various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries. Warrior coal production in 2023 was 4.4 million tons.

 Mt. Vernon Transfer Terminal, LLC

 Our subsidiary, Mt. Vernon, leases land and operates a coal-loading terminal on the Ohio River at Mt. Vernon, Indiana. Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 200,000 tons. In 2023, the terminal loaded approximately 3.6 million tons for customers of Gibson and Hamilton.

 Appalachian Operations

 Our Appalachian mining operations are located in eastern Kentucky, Maryland, and West Virginia. As of December 31, 2023, we had 1,014 employees and we operate three mining complexes in Appalachia.

 Tunnel Ridge Complex

 Our subsidiary, Tunnel Ridge, operates the Tunnel Ridge mine, an underground longwall mine in the Pittsburgh No. 8 coal seam, located near Wheeling, West Virginia. Longwall mining operations began at Tunnel Ridge in May 2012. The Tunnel Ridge preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Coal produced from the Tunnel Ridge mine is 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. Tunnel Ridge coal production in 2023 was 7.7 million tons.

 Mettiki Complex

 The Mettiki Complex comprises the Mountain View mine located in Tucker County, West Virginia operated by our subsidiary Mettiki (WV) and a preparation plant located near the city of Oakland in Garrett County, Maryland operated by our subsidiary Mettiki (MD). Mettiki (WV) began longwall mining in November 2006. The Mountain View mine produces low/medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical coal market or otherwise, or directly to the coal blending facility at the Virginia Electric and Power Company Mt. Storm Power Station. The Mettiki (MD) preparation plant has throughput capacity of 1,350 tons of raw coal per hour. Coal processed at the preparation plant can be trucked to the blending facility at Mt. Storm or shipped via the CSX railroad, which provides the opportunity to ship into the domestic and international thermal and metallurgical coal markets. Mettiki WV coal production in 2023 was 0.8 million tons.

 MC Mining Complex

 The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky. We acquired the original mine in 1989. Our subsidiary, MC Mining, through our subsidiary, Excel operates the Excel Mine No. 5. Excel completed the development of Mine No. 5 in May 2020 and transitioned its employees and equipment from Mine No. 4 in July 2020. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The existing preparation plant, which has throughput capacity of 1,000 tons of raw coal per hour, is utilized by Mine No. 5. Substantially all of the coal produced at MC Mining in 2023 met or exceeded the compliance requirements of Phase II of the Federal 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 various transloading facilities on the Ohio River for barge deliveries, or by truck directly to customers or various docks on the Big Sandy River for barge deliveries. MC Mining coal production in 2023 was 1.2 million tons.

 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 2023 approximately 93.4% and 92.0% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2024 to 2029. Our initial 2024 guidance includes 32.5 million priced and committed tons for delivery in 2024. 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 ensure 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. Long-term contracts typically stipulate procedures for the transportation of coal, quality control, sampling, and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility, and other qualities. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits. Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include but are not limited to unexpected significant geological conditions and weather events that may disrupt transportation. Depending on the language of the contract, some contracts may terminate upon an event of force majeure that extends for a certain period.

 The international coal market has been a part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America. Our sales into the international coal market are considered exports and the majority are made through brokered transactions. During the years ended December 31, 2023, 2022, and 2021, export tons represented approximately 15.7%, 12.5%, and 12.5% of tons sold, respectively. Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known.

 Reliance on Major Customers

 In 2023, we derived more than 10% of our total revenue from each of American Electric Power and Tennessee Valley Authority. We did not derive 10% or more of our revenues from any other single customer. For more information about these customers, please read "Item 8. Financial Statement and Supplemental Data—Note 22 – 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 the largest coal producer in the eastern United States. Our principal competitors include American Consolidated Natural Resources Inc., CONSOL Energy, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy LP, and Peabody Energy Corporation. We also compete directly with smaller producers in the Illinois Basin and Appalachian regions. In addition, we seek to export a portion of our coal into the international coal markets and we compete with companies that produce coal from one or more foreign countries.

 The price per ton for our export coal sales is influenced by many factors, such as global economic conditions, weather patterns, and global supply and demand, among others. The price per ton for our domestic coal sales are primarily linked to coal consumption patterns of domestic electricity-generating utilities, which in turn are influenced by economic activity, government regulations, weather, and technological developments, as well as the location, quality, price and availability of competing sources of fuel and alternative energy sources such as natural gas, nuclear energy, petroleum and renewable energy sources for electrical power generation.

 For additional information, please see "Item 1A. Risk Factors."

 Coal Transportation

 Our coal is transported from our mining complexes to our customers by barge, rail, and truck, reflecting important flexibility advantages in supplying our customers. Depending on the proximity of the customer to the mining complex and the transportation available for delivering coal to that customer, transportation costs can be a substantial part of the total delivered cost of a customer's coal. Consequently, the availability and cost of transportation constitute important factors in the marketability of coal. We believe our mines are located in favorable geographic locations that minimize transportation costs for our customers, and in many cases, we can accommodate multiple transportation options. Our customers typically negotiate and pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry. Approximately 50.2% of our 2023 sales volume was initially shipped from the mining complexes by barge, 32.1% was shipped from the mining complexes by rail, and 17.7% was shipped from the mining complexes by truck. The rates set by and available capacity of the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts concerning coal produced from the relevant mining complex. With respect to our export volumes from the United States to other countries, we generally sell coal to our customers at an export terminal in the United States and we are responsible for the cost of transporting coal to the export terminals. Our export customers generally negotiate and pay for ocean vessel transportation.

 Mineral Interest Activities

 Our mineral interest activities include both oil & gas and coal mineral interests. Our oil & gas mineral interest business includes all activities related to the oil & gas mineral interests held directly or indirectly by Alliance Minerals and includes Alliance Minerals' equity interest in AllDale III. 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 more than 67,745 oil & gas net royalty acres, including 3,969 oil & gas net royalty acres owned through our equity interest in AllDale III.

 Our coal mineral interests include substantially all of our coal mineral resources and 557.7 million tons of coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. Our coal mineral interests are located in both the Illinois Basin and the Appalachia Basin.

 When our oil & gas mineral interests are leased, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to receive a fixed percentage of the revenue or production from the oil & gas produced from the acreage underlying our interests, free of lease operating expenses and capital costs. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities, or by making an extension payment. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. As an owner of mineral interests, we incur the initial cost to acquire our interests but thereafter only incur our proportionate share of production and ad valorem taxes. Unlike owners of working interests in oil & gas properties, we are not obligated to fund drilling and completion costs, lease operating expenses, or plugging and abandonment costs associated with oil & gas production.

 The following chart summarizes the production of our oil & gas mineral interests for the year ended December 31, 2023, 2022, and 2021, not including our equity interest in AllDale III:

 2023

 2022*

 2021*

 Production:

 Oil (MBbls)

 1,418

 1,061

 Natural gas (MMcf)

 5,759

 4,814

 3,460

 Natural gas liquids (MBbls)

 BOE (MBbls)

 3,105

 2,404

 1,877

 * Recast to reflect the JC Resources Acquisition as if we, rather than JC Resources, acquired the mineral interests in 2019. Please see "Item 8. Financial Statement and Supplemental Data—Note 1 – Organization and Presentation and Note 3 – Acquisitions" for more information.

 The following map shows the location of our oil & gas mineral interests:

 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 purchases of acreage located entirely in the Permian Basin through the Belvedere, Jase and JC Resources Acquisitions demonstrate 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, 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, and 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.

 Our Coal Royalties segment includes approximately 557.7 million tons of reserves and substantially all of the 1.06 billion tons of our coal mineral resources. Our coal mineral reserves and resources are located in the Appalachia and Illinois Basins in the United States. We lease our reserves and resources to our mining complexes under long-term leases. Approximately 60% of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms.

 Under our standard royalty lease, we grant the lessees the right to mine and sell our reserves and resources in exchange for royalty payments based on a percentage of the sale price or a fixed royalty per ton of coal mined and sold. Lessees calculate royalty payments due to us and are required to report tons of coal mined and sold as well as the sales prices of the extracted coal.

 The following chart summarizes the coal sales associated with our coal mineral interests for the years ended December 31, 2023, 2022 and 2021.

 Coal Regions

 2023

 2022

 2021

 (tons in millions)

 19.9

 21.2

 18.9

 Appalachia

 0.3

 0.6

 1.3

 Total

 20.2

 21.8

 20.2

 The following map shows the location of our coal mineral interests:

 Illinois Basin:

 Appalachian Basin:

 A. GIBSON RESERVES AND RESOURCES

 E. HENDERSON/UNION RESOURCES

 H. TUNNEL RIDGE RESERVES AND RESOURCES

 B. HAMILTON RESERVES AND RESOURCES

 F. DOTIKI RESOURCES

 I. MOUNTAIN VIEW RESERVES AND RESOURCES

 C. RIVER VIEW RESERVES

 G. SEBREE SOUTH RESOURCES

 J. PENN RIDGE RESOURCES

 D. WARRIOR RESERVES

 Alliance Resource Properties, either directly or through its subsidiaries, holds coal mineral reserves and resources in the following counties in the Illinois Basin:

 Hopkins County, Kentucky

 Webster County, Kentucky

 Union County, Kentucky

 Henderson County, Kentucky

 Hamilton County, Illinois

 Gibson County, Indiana

 Alliance Resource Properties leases some of the reserves and resources in Union and Henderson Counties from WKY CoalPlay or its subsidiaries, which are related parties. For more information about our WKY CoalPlay transactions, please read "Item 8. Financial Statements and Supplementary Data—Note 20 – Related-Party Transactions."

 Approximately 477.0 million tons of proven and probable reserves and 977.2 million tons of measured, indicated and inferred coal mineral resources are controlled by Alliance Resource Properties in the Illinois Basin and are leased/subleased to our mining complexes or held for lease/sublease in the future as follows:

 Gibson Reserves and Resources

 Approximately 4.4 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Gibson.

 Hamilton Reserves and Resources

 Approximately 564.5 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Hamilton.

 River View Reserves

 Approximately 303.1 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, River View.

 Warrior Reserves

 Approximately 50.0 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Warrior.

 Henderson/Union Resources

 Approximately 412.7 million tons of the resources are not under lease or currently anticipated to be leased by our operating companies. Leasing of these properties is dependent upon further development by our operating subsidiaries or third-party mining complexes, which is regulatory and market dependent.

 Dotiki Resources

 Approximately 76.0 million tons of the resources are currently leased/subleased or held for lease/sublease to our subsidiary, Webster.

 Sebree South Resources

 Approximately 43.5 million tons of the resources are currently leased/subleased to our subsidiary, Sebree.

 Appalachia Basin

 Alliance Resource Properties, either directly or through its subsidiaries, holds coal mineral reserves and resources in the following counties in the Appalachian Basin:

 Brooke County, West Virginia

 Grant County, West Virginia

 Ohio County, West Virigina

 Tucker County, West Virginia

 Washington County, Pennsylvania

 Approximately 80.7 million tons of reserves and 85.4 million tons of coal mineral resources are controlled by Alliance Resource Properties in the Appalachian Basin and are leased/subleased to our mining complexes or held for lease/sublease in the future as follows:

 Tunnel Ridge Reserves and Resources

 Approximately 75.0 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Tunnel Ridge.

 Mountain View Reserves and Resources

 Approximately 13.1 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Mettiki (WV).

 Penn Ridge Resources

 Approximately 78.0 million tons of the resources are not under a lease. The resources are near our Tunnel Ridge mining complex and leasing of these resources is dependent upon further development by Tunnel Ridge or third-party mining complexes, which is regulatory and market dependent.

 Minerals Interest Competition

 Many companies are engaged in the search for and the acquisition of coal and oil & natural gas interests, and there is a limited supply of desirable coal and oil & natural gas reserves. Our ability to acquire additional oil & gas mineral interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors not only own and acquire oil & gas mineral interests but also explore for and produce oil & gas and, in some cases, conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, because we have fewer financial and human resources than many companies in the oil & gas industry, we may be at a disadvantage in bidding for oil & gas properties. Further, oil & gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternative fuels and other forms of energy, may affect the demand for oil & gas.

 We also face competition from land companies, coal producers, and international steel companies in purchasing coal mineral reserves and resources as well as royalty-producing properties. Our mining complexes in which we lease our reserves compete with coal producers in various regions of the United States for domestic sales on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer, and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by the demand for electricity and steel, as well as government regulations, technological developments, and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar, and hydroelectric power.

 For additional information, please see "Item 1A. Risk Factors".

 Oil & Gas Minerals Interest - Seasonal Nature of Business

 Generally, demand for oil increases during the summer months and decreases during the winter months while demand for natural gas increases during the winter and summer months and decreases during the spring and fall months. Certain buyers of natural gas use natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil & gas operations in a portion of our leasing areas. These seasonal anomalies can pose challenges for the 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

 Matrix Group

 Matrix Group provides a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties around the world. Matrix Group's products and services include data network, communication and tracking systems, mining proximity detection systems, industrial collision avoidance systems, and data and analytics software. In addition, Matrix Design has entered into an agreement with Infinitum to jointly develop and distribute high-efficiency motors and advanced motor controllers designed specifically for the mining industry. Under the agreement, Matrix Design will integrate Infinitum's motor technology into mining equipment of our operating subsidiaries to provide performance validation in production environments for jointly

 developed products and to improve our operational efficiency. Matrix Design will also work with Infinitum to market the jointly developed technology products to third parties worldwide. We acquired Matrix Design in September 2006. Over the past 15 years, Matrix Group has become a leader in collision avoidance and proximity detection technologies, providing safety and productivity solutions for mining companies worldwide, while extending its reach into other industrial applications.

 Our subsidiary, AROP II, LLC, and its subsidiary, AROP II Investments, LLC, makes strategic investments in attractive opportunities that support the advancement of energy and related infrastructure. We intend to pursue opportunities that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. Our strategy is to continue to identify and make strategic investments in the advancement of energy and related infrastructure opportunities that may create new platforms for future lines of business with long-term growth and cash flow generation. As of December 31, 2023, we have made investments of $25 million in Ascend, $20 million in Francis, $66.6 million in Infinitum and $6.6 million (of a $25 million commitment) in NGP ET IV. In 2023, revenues from these investments were immaterial.

 Ascend is a U.S.-based manufacturer and recycler of sustainable, closed-loop engineered battery materials for electric vehicles. Ascend is currently constructing North America's first commercial-scale manufacturing facility located near Hopkinsville, Kentucky, that when complete, will produce enough cathode materials for 750,000 electric vehicles per year.

 Francis is currently active in the installation, management and operation of metered-for-fee, public-access EV charging stations. Francis also develops and contracts EV charging stations for third-party customers.

 Infinitum is a Texas-based developer and manufacturer of electric motors featuring printed circuit board stators that have the potential to result in motors that are smaller, lighter, quieter, more efficient and capable of operating at a fraction of the carbon footprint of conventional electric motors.

 NGP ET IV focuses on investments that are part of the global transition toward a lower carbon economy by partnering with top-tier management teams and investing growth equity in companies that drive or enable the growth of renewable energy, the electrification of our economy, or the efficient use of energy.

 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 MSHA where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to promptly remediate any identified condition. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

 Expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based on 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 the 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 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 MINER Act significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties, and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

 sealing off abandoned areas of underground coal mines;

 mine safety equipment, training, and emergency reporting requirements;

 substantially increased civil penalties for regulatory violations;

 training and availability of mine rescue teams;

 underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;

 flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and

 post-accident two-way communications and electronic tracking systems.

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

 MSHA has finalized a number of rules related to controlling exposure to coal mine dust, which has resulted in progressively stricter exposure limits imposed by MHSA regulations. These requirements impose a number of dust monitoring obligation and mine ventilation requirements on our operations. 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 previously published a request for information regarding engineering controls and best practices to lower miners' exposure to respirable coal mine dust; however, to date no further action has been taken and we cannot predict what actions, if any, MSHA may take in response to this information request.

 MSHA has also published, and may continue to publish, various proposed rules or requests for information, which may result in additional rulemaking. For example:

 In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that closed in November 2016 for this matter, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's 2016 request for information. The comment period for the request for information for the Diesel Exhaust Partnership closed in September 2020 and it is uncertain whether this will result in additional rulemaking.

 In July of 2023, MSHA published a proposed rule on respirable crystalline silica, most commonly found in the mining environment through quartz. The proposed rule would amend the existing MSHA standards to lower the permissible exposure limit of respirable crystalline silica, as well as set forth new or revised standards for

 exposure sampling, corrective actions, medical surveillance for metal and non-metal miners, and respiratory protection requirements. The comment period on the proposed rule ended in August of 2023 and the final rule is expected in April 2024.

 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 and the final rule is expected in August 2024.

 In September 2021, MSHA published a proposed rule requiring that mine operators employing six or more miners develop and implement a written safety program for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface Mobile Equipment). The comment period for the proposed rule closed in November 2021. However, MSHA reopened the rulemaking record for additional public comments. A virtual hearing was held in January 2022 and the comment period closed in February 2022. The final rule was released in December 2023, with an effective date of January 19, 2024. All mines subject to the rule are required to develop, implement, and periodically update a written safety program for surface mobile equipment (excluding belt conveyors) at surface mines and surface areas of underground mines. Compliance with the rule must be achieved by July 17, 2024.

 It is uncertain whether any of the above or other various proposed rules or requests for information would have material impacts on our operations or our costs of operation.

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

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

 Black Lung Benefits Act

 The BLBA requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses under circumstances including where no responsible coal mine operator has been identified for claims. In addition, the BLBA provides that some claims for which coal operators not affiliated with us had previously been responsible are or will become obligations of the government trust funded by the excise tax referenced in this paragraph. The Federal government established such a trust fund and as of January 1, 2022, the trust fund was funded by an excise tax on industry-wide production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable gross sales price. The Inflation Reduction Act of 2022 raised the excise tax, effective October 1, 2022, up to $1.10 per ton of coal from underground mines and up to $0.55 per ton of coal from surface mines, neither amount to exceed 4.4% of the gross sales price. The coal we sell into international markets is generally not subject to the excise tax referenced in this paragraph. The Company recognized expenses related to the BLBA excise tax of $30.5 million for the year ended December 31, 2023.

 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 provide for the potential compensation of 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. The DOL's OWCP is responsible for authorizing coal mine operators to self-insure for federal black lung and for setting applicable security amounts. In January 2023, the OWCP issued a Notice of Proposed Rulemaking to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts, and announced that it plans to solicit public comments for that proposal. A change in requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security for its obligations. 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 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. We may also be liable under various state statutes with respect to black lung claims.

 Surface Mining Control and Reclamation Act

 The 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. We have accrued $150.4 million for 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, the Abandoned Mine Lands Program, which is part of SMCRA and relates to industry-wide operations, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The fee expired on September 30, 2021, and was reauthorized through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021. The fee, as reauthorized, for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30, 2034. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.

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

 Bonding Requirements

 Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers' compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral and in some cases it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire, surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow. For additional information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources— Cash Requirements."

 Air Emissions

 The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining, as well as oil & gas, operations. The CAA imposes permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There has 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 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 GHG issues discussed below, the air emissions programs that may affect our operations or the operations of those on the properties in which we hold mineral interests, directly or indirectly, include but are not limited to the following:

 The EPA's Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility's sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA's Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or "scrubbers," or by reducing electricity-generating levels. In 2023, we sold 80.9% of our total tons to electric utilities in the United States, substantially all of which was sold to utility plants with installed pollution control devices. These requirements would not be supplanted by a replacement rule for the CAIR, discussed below.

 The CAIR called 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 CSAPR, a replacement rule for CAIR, which would have required twenty-eight 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 presently unknown due to the implementation of MATS, discussed below, and the impact of the continuing coal plant retirements.

 In May 2020, EPA issued a final rule that reversed the Agency's prior determination from 2000 to 2016 that it was "appropriate and necessary" to regulate hazardous air pollutants from coal-fueled EGUs under the MATS rule, 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. However, in February 2023, EPA published a final revocation of the May 2020 finding. Then, in April 2023, the EPA issued a proposed rule to amend the MATS rule, to reflect developments in control technologies and plant performance. Although the impacts of the potential final rule are unknown, the MATS rule has forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR updates and MATS and the effects they may have on our business and our results of operations, financial condition, or cash flows.

 The CAA requires the EPA to periodically reevaluate the available health effects information to determine whether the NAAQS should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine 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 filed litigation against one or both of these rulemakings, and the Biden Administration announced that it would reconsider and potentially revise the NAAQS. With respect to ozone, a draft assessment released in April 2022 indicated a preliminary conclusion that the December 2020 decision would stand. However, on August 21, 2023, the EPA announced a new review of the ozone NAAQS to reflect updated ozone science in combination with the reconsideration of the December 2020 decision. The Agency is expected to release its Integrated Review Plan in the fall of 2024. New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments could indirectly reduce the demand for coal. Separately, the implementation of new standards by states has the potential to delay or otherwise impact oil & gas production activities, which could reduce the profitability of our mineral interests.

 The EPA's regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA's FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations. In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs, which was followed by a supplemental memorandum in July 2021 for SIPs for the second implementation period.

 The EPA's 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 been settled, but others remain pending. In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions. The EPA has announced that it will review the NSR program. Depending on the ultimate resolution of the EPA's litigation and review, demand for coal could be affected.

 The EPA's NSPS under the CAA require the reduction of certain pollutants and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions." These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels. Although the Trump Administration revised prior regulations in September 2020 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. In December 2023, EPA issued its final methane rules, known as OOOOb and OOOOc, that establish new source and first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas

 processing plants, and transmission and storage facilities. The final rules include nationwide emissions guidelines for states to limit methane emissions from existing crude oil and natural gas facilities and states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The rules also revise requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys and establishes a "super-emitter" response program to timely mitigate emissions events. It is likely that the final rule and its requirements will be subject to legal challenges. Moreover, compliance with the new rules may effect the amount oil & gas companies owe under the Inflation Reduction Act, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2025 and thereafter. Compliance with the EPA's new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. Oil & gas production on the properties in which we hold mineral interests could be adversely affected to the extent the rules and any of their requirements impose 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 or existing 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 made it clear 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. President Biden recommitted the United States to the Paris Agreement in February 2021 and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy wide net GHG emissions by 2030. The international community gathered again at the COP26 during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. Also at COP26, more than forty countries pledged to phase out coal, although the United States did not sign the pledge. In December 2023, the United Arab Emirates hosted the COP28 where parties signed onto an agreement to transition "away from fossil fuels in energy systems in a just, orderly and equitable manner" and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. The full impact of these actions remains unclear at this time. Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal, and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal and oil & gas could be negatively impacted, which would have an adverse effect on our operations.

 The EPA has begun to regulate GHG emissions from stationary sources, such as coal-fueled power plants, under existing federal CAA. In August 2015, the EPA issued its final CPP Rule, which established carbon pollution standards for power plants. The CPP was subsequently challenged by multiple states and industry participants in the Court of Appeals for the D.C. Circuit and, in February 2016, the implementation of the CPP was stayed by the U.S. Supreme Court. Then, in September 2019, the EPA repealed the CPP and finalized the ACE rule. The ACE rule specified that heat rate improvement measures qualified as the BSER for existing coal-fired power plants, clarified the roles of the EPA and the states in the implementation of the ACE, and revised the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. In January 2021, however, the D.C. Circuit vacated the ACE rule concluding that the EPA's "repeal of the CPP rested critically on a mistaken reading of the CAA." Although the D.C. Circuit ultimately agreed to stay its mandate, such that the CPP remained repealed, in June 2022, the U.S. Supreme Court in West Virginia v. EPA reversed and remanded the D.C. Circuit's decision and found that the EPA had acted outside the bounds of the agency's authority in the promulgation of the CPP. Notwithstanding the litigation, the

 CPP and the ACE 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 yet adopted legislation to restrict carbon dioxide emissions from existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v. EPA, but we cannot predict whether such legislation will be passed in the future or what the potential impacts of such legislation would be.

 Several rulemakings have been issued under the NSPS that constrain the GHG emissions of fossil-fuel-fired power plants. In October 2015, EPA published its final rule on performance standards for GHG emissions from new, modified, and reconstructed EGUs, which required use of efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology and imposed a new emission standard. The October 2015 rule was challenged by several states, industry participants and other parties in the D.C. Circuit and, in April 2017, the Court granted EPA's motion to hold the litigation in abeyance while EPA reviewed the rule. Then, in December 2018, the EPA issued a proposed rule to replace the October 2015 rule, including revising the BSER for newly constructed coal-fired EGUs. Although the EPA has not taken further action on the December 2018 proposed rule, in May 2023, the EPA published a proposed NSPS rule for GHG emissions from new, modified, and reconstructed fossil fuel-fired EGUs and emissions guidelines for existing fossil fuel-fired EGUs. The final rule is expected in 2024.

 There are further uncertainties surrounding the potential impacts and costs associated with the reduction of GHG emissions, such as: protests and challenges to the permitting of new fossil-fuel infrastructure by environmental organizations and state regulators; state tort liability; and state adoption of "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. For example, several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio and, in December 2021, President Biden issued an executive order setting a goal for a carbon pollution-free electricity sector across the country by 2035. To the extent these requirements or similar requirements that may be enacted or adopted in the future affect our current and prospective customers or those of our mineral interest producers, they may reduce the demand for our coal and the oil & gas produced from the properties in which we hold mineral interests. 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 NEPA. These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In April 2022, the CEQ issued a final rule, considered "Phase I" of the Biden Administration's two-phased approach to modifying the NEPA, revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporating the consideration of direct, indirect, and cumulative effects of major federal actions, including GHG emissions. In July 2023, the CEQ announced a "Phase 2" Notice of Proposed Rulemaking, the "Bipartisan Permitting Reform Implementation Rule," which revises the implementing regulations of the procedural provisions of NEPA and implements the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The public comment period for the proposed rule closed in September 2023, and the final rule is expected in the second quarter of 2024. And, in January 2023, the CEQ released guidance, effective upon publication, to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA.

 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, the RGGI calls for the implementation of a cap-and-trade program aimed at reducing carbon dioxide emissions from power plants in participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Similar to RGGI, five western states launched the Western Regional Climate Initiative, although only California, Washington and certain Canadian provinces are currently active participants. We cannot predict what other regional greenhouse gas reduction initiatives may arise in the future.

 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 CWA and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact such wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future "fill" permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. For more information about asset retirement obligations, please read "Item 8. Financial Statements and Supplementary Data—Note 18 - Asset Retirement Obligations." Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

 For us or the operators of the properties in which we hold oil & gas mineral interests to conduct certain activities, an operator may need to obtain a permit for the discharge of fill material from the 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." This authority has been upheld by the D.C. Circuit. Any future use of the EPA's Section 404 "veto" power could create uncertainty 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 a 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.

 States also have the ability to review the Corps of Engineers' Section 404 permitting process, pursuant to CWA Section 401, which is also subject to ongoing litigation. In October 2021, the Northern District of California federal court vacated a 2020 rule revising the Section 401 certification process. The Supreme Court stayed this vacatur and, in September 2023, the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective on November 27, 2023. While the full extent and impact of these actions is unclear at this time, any disruption in the ability to obtain required permits may result in increased costs and project delays.

 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. Although the EPA and Corps of Engineers did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico vacated the 2020 rule in decisions announced during the third quarter of 2021. In January 2023, the EPA and Corps of Engineers published a final revised definition of WOTUS founded upon a pre-2015 definition, including updates to incorporate existing Supreme Court decisions. However, continued uncertainty remains as to the government's

 jurisdictional reach as the rule is likely to be subject to legal challenge. Judicial developments further add to this uncertainty. In October 2022, the Supreme Court heard oral arguments in Sackett v. EPA regarding the scope and authority of the CWA and the definition of WOTUS and in May 2023, issued a ruling invalidating certain parts of the January 2023 rule, and further limiting the federal government's jurisdiction over wetlands and tributaries. A revised WOTUS rule was issued in September 2023. Due to the injunction in certain states, however, the implementation of the September 2023 rule currently varies by state.

 Hazardous Substances and Wastes

 The 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 of 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 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 CCB. On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as "non-hazardous" waste and avoids the stricter, more costly, regulations under RCRA's "hazardous" waste rules. While the classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal. The CCB rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating the closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site-specific circumstances. Certain provisions of the revised CCB rule were vacated by the D.C. Circuit in 2018. The EPA proposed a coal ash rule in May 2023 and the final rule is expected in April 2024. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities that sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA required the remaining facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022. And, in January 2023, the EPA issued six proposed determinations to deny facilities' requests to continue disposal into unlined surface impoundments. The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. The combined effect of the CCB rules and the ELG regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

 On November 3, 2015, the EPA published the final rule ELG, revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technological improvements in the steam electric power industry over the last three decades. The combined effect of the CCB and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards. In November 2019, the EPA proposed revisions to the 2015 ELG

 rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs. In October 2020, EPA published a final rule. In August 2021, EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits. In March 2023, the EPA proposed a rule to establish more stringent ELG regulations and the final rule is expected in April 2024. It is unclear what impact these regulations will have on the market for our products.

 Endangered Species Act

 The federal ESA and counterpart state legislation protect species threatened with possible extinction. The USFWS works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil & gas exploration and production activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. In February 2023, the USFWS published a proposed rule that revised the requirements for an incidental take permit application. A final rule is scheduled for release in the first quarter of 2024. Additionally, in June 2022, the USFWS and the National Marine Fisheries Service published a final rule rescinding the 2020 regulatory definition of "habitat." 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, 2023, we employed 3,595 full-time employees, including 3,038 employees involved in active coal mining operations, 408 employees in other operations, and 193 corporate employees. In 2023 we reviewed the work duties of our employees and reclassified 68 of our technical services employees from corporate employees to employees involved in other operations. Our workforce is entirely union-free. Our typical employee has approximately six years of experience with the Partnership and more than 40% of all employees remain employed for more than five years.

 To attract and retain the most qualified personnel across all functions of our business we offer competitive compensation packages. In making decisions regarding employee compensation, we review current compensation levels for each position within other companies in the coal industry and other peers and use our discretion to determine an appropriate total compensation package, which generally includes some combination of base salary, incentive compensation, health and welfare benefits and participation in our profit sharing and savings plan. Depending on the position and employer, incentive compensation bonuses can be based on production and safety goals at a specific coal operation or broader performance goals across the Partnership, among other factors. We intend for each employee's total compensation to be competitive in the marketplace.

 Workplace safety is fundamental to our culture. By providing a work environment that rewards safety and encourages employee participation in the safety process, we have a demonstrated history as a 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 through various industry-standard metrics. In addition, we collected approximately 13,800 respirable dust samples from the mining environment where our miners regularly work and travel. The average concentration of those samples was 56% below the regulatory standard. We are also regularly inspected by MSHA. For more information about citations or orders for violations of standards under the FMSHA, as amended by the MINER Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.

 We are focused on the health of our employees. In addition to providing medical, dental, and vision benefits for our employees, we also provide on-site medical clinics to provide medical services to our employees and their families. Furthermore, at each of our coal operations and corporate offices, we provide a human resource representative to assist employees with various human resource matters. The Partnership also administers our medical plan, which allows us to control costs and work directly on behalf of our employees with healthcare providers. To date, we have been able to continue providing health and welfare benefits with no out-of-pocket premiums for our employees and 100% coverage with direct contract providers.

 ITEM 1A. RISK FACTORS

 Summary Risk Factors

 Our business is subject to a number of risks, including risks that could prevent us from achieving our business objectives or could adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks are discussed more fully below and include but are not limited to risks related to:

 Risks Inherent in an Investment in Us

 Cash distributions are not guaranteed

 Ownership of limited partner interests could be diluted

 Sales of our common units could cause decline in the market price of our common units

 Increase in interest rates could cause decline in the market price of our common units

 The credit risk of our general partner could adversely impact us

 Our unitholders do not elect the general partner

 The control of our general partner may be transferred to a third party

 Unitholders may be required to sell their units to our general partner

 Cost reimbursements due to our general partner could be substantial

 Your liability as a limited partner may not be limited under certain circumstances

 Our general partner's fiduciary duties are limited

 Our general partner has discretion in determining the level of cash reserves

 Our general partner has potential conflicts of interest

 Some executive officers and directors face potential conflicts of interest

 ESG scores could adversely impact our securities

 Risks Related to Our Business

 Declining global economic conditions could adversely impact us

 Material adverse effects on our financial condition as a result of 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

 Global geopolitical tensions which have caused, and may cause in the future, significant market disputes that may lead to increased volatility in the price of commodities

 Changes in consumption patterns by utilities could affect our ability to sell coal and/or impact the price of our natural gas

 Tort claims based on climate change

 Litigation resulting from disputes with customers could result in costs and liabilities

 Unanticipated mine operating conditions could affect our profitability

 Inability to obtain and renew permits necessary for operations could limit our ability to continue or expand our operations

 Fluctuations in transportation costs and availability could reduce demand for our products

 Unexpected increases in raw material costs could impact the profitability of our operations

 The ability to recruit, hire and retain skilled labor could impact the profitability of our operations

 Disruptions in supply chains could impact the profitability of our operations

 Inflationary pressures could impact the profitability of our operations

 Unavailability of economic coal mineral reserves and resources could limit our ability to continue or expand our operations

 Estimates of our coal mineral reserves and resources could be inaccurate and could result in decreased profitability

 Coal mining in certain areas could be difficult and involve regulatory constraints which could impact our operations

 Extensive environmental laws and regulations could reduce demand for coal as a fuel source

 Legislative and regulatory compliance is costly

 Legislative and regulatory compliance could impact our business

 Legislative and regulatory initiatives relating to hydraulic fracturing could impact our mineral interests

 Legislative and regulatory initiatives relating to seismic activity could impact our business

 Legislative and regulatory initiatives relating to climate change could impact demand for our products

 Mine facilities may be located in a leased portion of the surface properties which introduces a risk of disruption to our operations

 Inability to acquire or failure to maintain surety bonds could limit our ability to continue or expand our operations

 Dependency on unaffiliated operators to explore and drill on our oil & gas properties limits our ability to control the timing and quantity of production

 Delays in royalty payments and optional royalty payments could impact our business

 Suspension of the right to receive royalty payments could impact our business

 Estimates of our oil & gas reserves could be inaccurate and could result in decreased profitability

 Uncertainties involved in drilling for and producing oil & gas could impact our business

 Availability of transportation and facilities for the products could impact our business

 Lack of hedging arrangements exposes us to the impact of commodity prices

 Expansions and acquisitions have inherent risks that could adversely impact us

 Integration of expansions or acquisitions has inherent risks that could adversely impact us

 Inability to obtain commercial insurance at acceptable rates could have a negative impact on our business

 Tax Risks to Our Common Unitholders

 Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the IRS treating us as a corporation or legislative, judicial, or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the Partnership.

 Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder's share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take.

 Tax gain or loss on the disposition of our units could be more than expected and create tax liabilities for our unitholders

 Limitation on unitholders' ability to deduct interest expense incurred by us could create tax liabilities for our unitholders

 Tax Exempt entities and non-U.S. unitholders face unique tax issues from owning our common units that may result in adverse tax consequences for 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

 Unitholders with units subject to securities loans could face adverse tax consequences

 Certain U.S. federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation

 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.

 The payment and amount of any future distribution will be subject to the sole discretion of the Board of Directors and will depend upon many factors, including our financial condition and prospects, our capital requirements and access to financing, covenants associated with our debt obligations, and other factors that our Board of Directors may deem relevant, and there can be no assurance that we will pay a distribution in the future. The amount of cash we can distribute to holders of our common units or other partnership securities each quarter principally depends on the amount of cash we generate from our operations, which fluctuates from quarter to quarter. In addition, the actual amount of cash available for distribution may depend on other factors, including capital allocation decisions, financing availability, restrictions in debt agreements, and the amount of cash reserves, if any, established by the general partner, in its discretion, for the proper conduct of our business.

 Furthermore, since the amount of cash we have available for distribution is not solely a function of profitability, which will be affected by non-cash items, 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.

 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.

 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 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 13. Certain Relationships and Related Transactions, and Director Independence—Related-Party Transactions— Administrative Services. "

 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.

 Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its 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 fossil-fuel industries, 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 valuation of such companies could be materially and adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention to and demands for action related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, reduce demand for our coal and hydrocarbon products, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our unit price and access to capital markets.

 In addition, certain organizations that provide corporate governance and other corporate risk information to investors and unitholders have developed scores and ratings to evaluate companies and investment funds based on 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 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. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

 Public statements with respect to ESG matters, such as emission reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential "greenwashing," i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, emission reduction claims, approaches to accounting for GHG emissions reductions, or other ESG-related goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.

 Risks Related to our Business

 Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets could have material adverse impacts on our business and financial condition that we currently cannot predict.

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

 the demand for electricity in the United States and globally could decline if economic conditions deteriorate, which could negatively impact the revenues, margins, and profitability of our business;

 any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and

 our future ability to access the capital markets could be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including the development of our coal mineral reserves and resources.

 We face various risks related to pandemics and similar outbreaks, which have had and may in the future have material adverse effects on our business, financial position, results of operations, and/or cash flows.

 Pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operations, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) restrictions recommended or imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.

 The extent to which COVID-19 or another future pandemic may adversely impact our results of operations, cash flows and financial condition depends on future developments, which are highly uncertain and unpredictable.

 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 $347.6 million as of December 31, 2023. 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 6 – Long-Term Debt" for further discussion.

 We depend on the leadership and involvement of Joseph W. Craft III and other key personnel for the success of our business.

 We depend on the leadership and involvement of Mr. Craft. Mr. Craft has been integral to our success, due in part to his ability to identify and develop internal growth projects and accretive acquisitions, make strategic decisions, and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, financial condition, and results of operations.

 We and our subsidiaries are subject to various legal proceedings, which could have a material adverse effect on our business.

 We are party to a number of legal proceedings incident to our normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could have an adverse effect on our cash flows, results of operations, or financial position. Please see "Item 3. Legal Proceedings" and "Item 8. Financial Statements and Supplementary Data—Note 21 – 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 2023, we sold approximately 93.4% of our coal sales tonnage under contracts having a term greater than one year, which we refer to as long-term sales contracts. These contracts have historically provided a relatively secure market for the production committed under the terms of the contracts. From time to time industry conditions could make it more difficult for us to enter into long-term sales contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.

 Some of our long-term sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

 Some of our long-term sales contracts contain provisions that allow the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in

 some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term sales contracts may provide only limited protection during adverse market conditions. In some circumstances, the failure of the parties to agree on a price under a reopener provision can also lead to the early termination of a contract.

 Several of our long-term sales contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer's reasonable control. Such events could include labor disputes, mechanical malfunctions, and changes in government regulations, including changes in environmental regulations rendering the use of our coal inconsistent with the customer's environmental compliance strategies. Additionally, most of our long-term sales contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. In the event of early termination of any of our long-term sales contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition, and results of operations could be adversely affected.

 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 2023, we derived more than 10% of our total revenues from each of American Electric Power and Tennessee Valley Authority. If we were to lose this or any of our significant customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or change the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition, and results of operations.

 Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

 Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer's contractual obligations are honored.

 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, process and record financial and operating data, communicate with our business partners, analyze mine and mining information, and estimate quantities of reserves and resources, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, could be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, misdirected wire transfers, 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, cash flows and reputation. 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 on 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 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;

 supply chain and cost of raw materials for coal and oil & gas operations;

 the adverse impact of pandemics, outbreaks and other public health events;

 the proximity to and capacity of transportation facilities;

 competition from other coal suppliers;

 domestic and foreign governmental regulations and taxes;

 the price and availability of alternative fuels;

 the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;

 international developments impacting the supply of coal;

 international developments impacting the supply of oil & gas; and

 the impact of domestic and foreign governmental laws and regulations.

 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. 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 in 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. The prices of and demand for our coal could significantly decline, 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 by the United States and foreign governments could adversely affect our results of operations, financial position, and cash flows.

 We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.

 New tariffs and other trade measures could adversely affect our results of operations, financial position, and cash flows. In response to tariffs imposed by the United States, the European Union, Canada, Mexico, and China have imposed tariffs on United States goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the United States or other potentially adverse economic outcomes. Additionally, we sell coal into the export thermal and metallurgical markets. Accordingly, our international sales could also be impacted by the tariffs and other restrictions on trade between the United States and other countries. While tariffs and other retaliatory trade measures imposed by other countries on United States goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.

 Global geopolitical tensions have caused, and may cause in the future, significant market disruptions that may lead to increased volatility in the price of commodities, including oil & gas, coal, and other sources of energy.

 Volatility in coal and oil & gas prices has been and may continue to be heightened as a result of the ongoing Russian-Ukrainian conflict, continued hostilities in the Middle East between Israel and Hamas and the potential impact to global shipping caused by Houthi rebels in Yemen. Globally, various governments have banned imports from Russia including commodities such as oil & gas and coal. These events have caused volatility in the aforementioned commodity markets. Although we have not experienced any material adverse effect on our results of operations, financial condition or cash flows as a result of such conflicts or the resulting volatility, such volatility, may significantly affect prices for our coal and oil & gas or the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers.

 Global geopolitical conflicts, trade and monetary sanctions, as well as any escalation of the conflict and future developments, could significantly affect worldwide market prices and demand for our coal and oil & gas and cause turmoil in the capital markets and generally in the global financial system. Additionally, the geopolitical and macroeconomic consequences of such conflicts and any associated sanctions cannot be predicted but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for products, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations.

 Changes in consumption patterns by utilities regarding the use of coal, including plans by utilities to shut down or move away from coal-fired generation, have affected our ability to sell the coal we produce and may do so in the future.

 Our business is closely linked to the demand for electricity, and any changes in coal consumption by domestic or international electric power generators would likely impact our business over the long term. The domestic electric power sector accounts for the vast majority of the total domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas, and fuel oil as well as alternative sources of energy. 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. 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. A decrease in coal consumption by the domestic electric utility industry could adversely affect the demand for or the price of coal, which could negatively impact our results of operations and reduce our cash available for distribution.

 Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, could have a material adverse effect on the demand for coal and our business over the long term.

 We, our customers, or the Operators of our oil & gas mineral interests could be subject to litigation related to climate change.

 Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

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

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

 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, 2023, we renewed our property and casualty insurance program through September 30, 2024. 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 $25.0 million overall aggregate deductible. We retained a 7.25% participating interest in our current 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, may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability. Please read "Item 1. Business—Environmental, Health and Safety Regulations— Mining Permits and Approvals."

 The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its "veto" power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA's action was ultimately upheld by a federal court. As a result of these developments, we could be unable to obtain or experience delays in securing, utilizing, or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position. Please read "Item 1. Business—Environmental, Health and Safety Regulations— Water Discharge."

 In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process or even an inability to obtain permits, permit modifications, or permit renewals necessary for our operations.

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

 Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers could face difficulties in the future that could impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions in 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.

 Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID-19 pandemic), labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to participate in the export market for coal sales, which could adversely affect our sales and our results of operations.

 Unexpected increases in raw material costs could significantly impair our operating profitability.

 Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies, and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas, and coking coal consumed in the production of iron and steel fluctuate significantly and could change unexpectedly. Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, and maintenance expenses. There could be acts of nature or terrorist attacks or threats that could also impact the future

 costs of raw materials. Future volatility in the price of steel, petroleum products, or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.

 A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs and could adversely affect our profitability.

 Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs. This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers and attracting new workers to the coal industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

 Disruptions in supply chains could significantly impair our operating profitability.

 We are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability and adversely affect our results of operations.

 Inflationary pressures could significantly impair our operating profitability.

 Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal or oil & gas and could adversely affect our results of operations.

 The unavailability of an adequate supply of coal mineral reserves and resources that can be mined at competitive costs could cause our profitability to decline.

 Our profitability depends substantially on our ability to mine coal mineral reserves and resources that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves and resources as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal mineral reserves and resources that are economically recoverable. Replacement reserves and resources may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves or resources that we acquire, which could adversely affect our profitability and financial condition. Exhaustion of reserves and resources at particular mines also could have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves and resources in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, or the inability to acquire coal properties on commercially reasonable terms.

 The estimates of our coal mineral reserves and resources could prove inaccurate and could result in decreased profitability.

 The estimates of our coal mineral reserves and resources could vary substantially from the actual amounts of coal we are able to economically recover. The reserve and resource data set forth in "Item 2. Properties—Coal Mineral Resources and Reserves" represent engineering estimates. All of the coal mineral reserves presented in this Annual Report on Form 10-K constitute proven and probable mineral reserves. There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond our control. Estimates of coal mineral reserves and

 resources necessarily depend upon a number of variables and assumptions, any one of which could vary considerably from actual results. These factors and assumptions relate to:

 geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;

 the percentage of coal in the ground ultimately recoverable;

 historical production from the area compared with production from other producing areas;

 the assumed effects of regulation and taxes by governmental agencies;

 future improvements in mining technology; and

 assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.

 Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect our actual coal reserves and resources. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in the closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results.

 Coal mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the United States, which could affect the mining operations and cost structures of these areas.

 The geological characteristics of some of our coal mineral reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. In addition, permitting, licensing, and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. Subsidence issues are particularly important to our operations engaged in longwall mining. Failure to timely and economically secure subsidence rights or any associated mitigation agreements could materially affect our results by causing delays or changes in our mining plan. These factors could materially adversely affect the mining operations and cost structures of, and our customers' ability to use coal produced by, our mines.

 Extensive environmental laws and regulations affect coal consumers and could affect 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."

 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 expenses 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 the Operators, and failure to comply could result in the Operators incurring significant liabilities, either of which could impact the Operators' willingness to develop our interests.

 The 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 the Operators, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all of the 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. The 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 the Operators, which in turn could affect profitability on the properties in which we own mineral interests.

 The 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. The 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 the Operators and delay production and could ultimately impact the 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 Safe Drinking Water Act regulates the underground injection of substances through the 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 the Operators conduct operations, the 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 the 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 the Operators' drilling and production activities, as well as their ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.

 State and federal regulatory agencies have recently focused on a possible connection between the hydraulic-fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil & gas activity and induced seismicity.

 In addition, a number of lawsuits have been filed in other states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, both Texas and Oklahoma have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. In September 2021, the TRRC issued a notice to operators in the Midland area to reduce saltwater disposal well activities and provide certain data to the TRRC. Subsequently, the TRRC ordered the indefinite suspension of all deep oil & gas-produced water injection wells in the area, effective December 31, 2021. Relatedly, in March 2022, the TRRC began implementation of its Northern Culberson-Reeves Seismic Response Action Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. In response to continued seismicity in the area, the TRRC issued a notice that it is suspending all disposal wells in the Northern Culberson-Reeves Seismic Response Area, effective January 12, 2024.

 The adoption or implementation of any new laws or regulations that restrict the 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 the 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 coal operations, and the third-party operations related to our oil and gas mineral interests, are subject to a series of risks resulting from climate change.

 Combustion of fossil fuels, such as the coal we produce and the oil & gas produced from our mineral interests, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events. Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.

 In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain sources in the United States, or constrain the emissions of powerplants (though such emissions restraints have been subject to challenge; for more information, see our regulatory disclosure titled "GHG emissions"). Additionally, the U.S. Congress approved, and President Biden signed into law, a resolution under the Congressional Review Act to repeal September 2020 revisions to methane standards, effectively reinstating the more stringent 2016 standards. Furthermore, in December 2023, EPA issued its final methane rules, known as OOOOb and OOOOc, that established new sources and first-time existing source standards of performance for methane and volatile organic compound emissions for oil & gas facilities. The final rules include nationwide emissions guidelines for states to limit methane emissions from existing crude oil and natural gas facilities and states have two years to prepare and submit their plants to impose methane emission controls on existing sources. The rules also revise requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys and establishes a "super-emitter" response program to timely mitigate emissions events. It is likely that the final rule will be subject to legal challenges. Moreover, compliance with the new rules may effect the amount oil and gas companies owe under the Inflation Reduction Act, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. Compliance with the EPA's new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. We cannot predict the scope of any final methane regulatory requirements or the cost for the Operators to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility and may have an impact on drilling operations on our oil & gas mineral interests.

 Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets. These commitments could further reduce demand and prices for fossil fuels. Although the United States had withdrawn from the Paris Agreement, following President Biden's executive order in January 2021, the United States rejoined the Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. In December 2023, the United Arab Emirates hosted COP28 where parties agreed to transition "away from fossil fuels in energy systems in a just, orderly and equitable manner" and increase renewable energy capacity so as to achieve net zero by 2050, although no

 timeline for doing so was set. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on us and the Operators' operations.

 Governmental, scientific, and public concern over climate change has also resulted in increased political risks, including certain climate-related pledges made by certain candidates now in political office. In January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Other actions that may be pursued include restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we, our customers, or operators of our mineral interests could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing. For more information, see our risk factor titled "We, our customers, or the Operators of our oil & gas mineral interests could be subject to litigation related to climate change."

 Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. For example, at COP26, the GFANZ announced that commitments from over 450 firms across forty-five countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. For example, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change on specific assets of the banks' portfolio. Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining or oil & gas production activities.

 Separately, the SEC released a proposed rule in March 2022 that would establish a framework for the reporting of climate risks, targets and metrics. A final rule is anticipated to be released in the second quarter of 2024. The SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege that an issuer's existing climate disclosures are misleading, deceptive, or deficient. Such agency action could also increase the potential for private litigation. Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emission reduction claims. Other states are considering similar laws. Non-compliance with these new laws may result in the imposition of substantial fines or penalties. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.

 The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal and oil & gas, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us or oil & gas operators restricting or canceling mining or oil & gas production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate economically. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources,

 could cause prices and sales of our coal and/or oil & gas to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.

 Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations, as well as those of the Operators and their supply chain. Such physical risks may result in damage to our facilities or the Operators' facilities or otherwise adversely impact operations which could decrease the production attributable to our mineral interests. We may not have insurance to cover these risks and the consequences for our or their operations could have a negative impact on the costs and revenues from operations.

 Some of our operating subsidiaries lease a portion of the surface properties upon which their mining facilities are located.

 Our operating subsidiaries do not, in all instances, own all of the surface properties upon which their mining facilities have been constructed. Certain of the operating companies have constructed and now operate all or some portion of their facilities on properties owned by 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.

 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 maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as "reclaim" or "reclamation"), to pay federal and state workers' compensation and pneumoconiosis (or black lung) benefits, and to satisfy other miscellaneous obligations. These bonds provide assurance that we will perform our statutorily required obligations and are referred to as "surety" bonds. These bonds are typically renewable on a yearly basis. At December 31, 2023, our total of such bonds was $246.9 million. The amount of surety bonding we are required to maintain may be increased by the governmental agencies holding the bond. For example, federal and state regulators are considering making financial assurance requirements more stringent and costly with respect to self-insured coal workers' pneumoconiosis, mine closure and reclamation security amounts.

 We could have difficulty acquiring or maintaining surety bonds for a variety of reasons, including:

 substantial increases in the amount of bonding required;

 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.

 Failure to acquire or maintain the required bonds could subject us to fines and penalties, result in the loss of our mining permits, or imperil our ability to self-insure workers compensation and pneumoconiosis obligations, and could 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 unaffiliated 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 oil & gas mineral interests.

 All of our oil & gas mineral interests may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue the development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the scheduled development plans of the Operators. Our estimate of reserves assumes that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and could result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.

 We could experience delays in the payment of royalties and be unable to replace Operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

 A failure on the part of the Operators of our properties 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 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 to 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 oil & gas 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 the 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 the 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, 2023, were audited by CGA, which conducted a detailed review of all of our properties at that time using the information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. In addition, certain assumptions regarding future oil & gas prices, production levels, and operating costs could prove incorrect. A meaningful portion of our reserve estimates is made without the benefit of lengthy production history, which is less reliable than estimates based on lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil & gas that are ultimately recovered being different from our reserve estimates.

 Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the FASB, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil & gas index prices, calculated as the unweighted arithmetic average for the first day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs could differ materially from those used in the present value estimate, and future net present value estimates using then-current prices and costs could be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil & gas industry in general. Please see "Item 2. Properties—Oil & Gas Reserves" for more information on our reserves.

 Drilling for and producing oil & gas are high-risk activities with many uncertainties that could materially adversely affect our business, financial condition, and results of operations.

 The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive. Drilling for oil & gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or gas to return a profit at then realized prices after deducting drilling, operating, and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or gas is present or that it can be produced economically. The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, the 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, the Operators' operations could be interrupted and our results of operations and cash available for distribution could be materially adversely affected.

 The marketability of the 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 the 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 the Operators' ability to deliver to market or produce oil & gas and thereby cause a significant interruption in the 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 the Operators' control, such as pipeline interruptions due to maintenance, excessive pressure, the 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 the Operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil & gas produced from our acreage, could adversely affect our financial condition, results of operations, and cash available for distribution.

 We do not currently enter into hedging arrangements with respect to commodity production from our properties, and we will be exposed to the impact of decreases in the price of such commodities.

 We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil & gas or the coal produced from our properties, and we may not enter into such arrangements in the future. As a result, although we could realize the benefit of any short-term increase in the price, we will not be protected against decreases in the price or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operation and cash available for distribution.

 In the future, we may enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of oil & gas or coal. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there could be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we could be limited in receiving the full benefit of increases in commodity prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.

 Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

 Since our formation and the acquisition of our predecessor in August 1999, we have expanded our coal operations by adding and developing mines in existing, adjacent, and neighboring properties. Similarly, the profitability of our business depends significantly upon acquisitions to grow our coal and oil & gas reserves, production, and free cash flow. Our future growth could be limited if we are unable to continue to make acquisitions in either our coal operations or our royalties

 segments, or if we are unable to successfully integrate the companies, businesses, or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.

 Competition for acquisitions of coal and oil & gas mineral interests could increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing under acceptable terms. In addition, these acquisitions could be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.

 The process of integrating acquired assets could involve unforeseen difficulties and could require a disproportionate amount of our managerial and financial resources. If we are unable to successfully integrate the companies, businesses, or properties we acquire, our profitability could decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:

 uncertainties in assessing the value, strengths, and potential profitability of expansion and acquisition opportunities;

 uncertainties in identifying the extent of all weaknesses, risks, contingent and other liabilities of, expansion and acquisition opportunities;

 the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;

 problems that could arise from the integration of the new operations; and

 unanticipated changes in business, industry, or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.

 Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and could require us to incur indebtedness, seek equity capital, or both. Future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

 The integration of any expansions or acquisitions that we complete will be subject to substantial risks.

 Even if we make expansions or acquisitions that we believe will increase our coal or mineral revenue, any expansion or acquisition involves potential risks, including, among other things:

 the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, the operating expenses, and costs the 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.

 We may not be able to effectively identify investment opportunities in the advancement of energy and related infrastructure on favorable terms, or at all, and failure to do so may limit our future growth.

 Part of our strategy includes positioning ourselves as a reliable energy provider for the future by pursuing strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. This strategy depends on our ability to successfully identify and evaluate investment opportunities. The number of opportunities may be limited, and we will compete with other investors for these limited opportunities, which could make them more expensive and the returns for our investments less attractive and possibly cause us to refrain from making them at all. Further, certain opportunities will depend on technological and other advancements that may not be within our control and may not come to fruition or be economically feasible in the near term, and we may fail to realize the anticipated benefit of our investments. Any new opportunities also may depend on the viability of new assets or businesses that are contingent on public policy mechanisms including investment tax credits, subsidies, renewable portfolio standards and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable energy, demand-side, and other infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of investments generally, as well as our participation in them.

 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 U.S. federal income tax purposes, and our not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

 The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

 Even though we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available

 for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our units could be negatively impacted.

 The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

 The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

 Any modification to the U.S. federal income tax laws and the interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

 If the IRS were to contest the U.S. federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

 We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

 If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders could be reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

 Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties and interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of

 any such audit adjustment, we are required to pay taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

 Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

 Tax gain or loss on the disposition of our common units could be more or less than expected.

 If a unitholder sells units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder's tax basis in those common units. Because distributions in excess of a unitholder's allocable share of our net taxable income decrease such unitholder's tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to a unitholder if it sells such units at a price greater than its tax basis in those units, even if the price such unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if a unitholder sells its units, a unitholder may incur a tax liability in excess of the amount of cash received from the sale.

 A substantial portion of the amount realized from a unitholder's sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder's 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 a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder 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, 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. If our "business interest" is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

 Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 Investment in our common units by tax-exempt entities, such as employee benefit plans and IRAs raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.

 Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

 Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be "effectively connected" with a U.S. trade or business. As a result, distributions to

 a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

 Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the "amount realized" by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner's "amount realized" generally includes any decrease of a partner's share of the partnership's liabilities, the Treasury regulations provide that the "amount realized" on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner's share of a publicly traded partnership's liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor's broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

 We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

 Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder's tax returns.

 We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on 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 on 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. 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 on ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 A unitholder whose units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged

 to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 Certain U.S. federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

 In past years, members of the U.S. Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. Elimination of those provisions would not impact our financial statements or results of operations. However, elimination of such provisions could result in unfavorable tax consequences for our unitholders and, as a result, could negatively impact our unit price.

 Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

 In addition to U.S. federal income taxes, our unitholders may 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 conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders 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, our unitholders may be subject to penalties for failure to comply with those requirements.

 We currently own assets and conduct business in multiple states that 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 our unitholders' responsibility to file all U.S. federal, foreign, state, and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own 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.

 ITEM 1C. CYBERSECURITY

 Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks

 We operate in an increasingly interconnected digital landscape and we recognize the importance of assessing, identifying, and managing material risks from cybersecurity threats. In the normal course of business, we may collect and store certain sensitive information, including proprietary and confidential business information, intellectual property, sensitive third-party information, employee information and personal information. We rely on information systems for the management of this information in addition to our management of business processes including inventory, payment of obligations, collection of cash, human capital management, financial tools and other processes and procedures. Our ability to manage our business effectively depends on the reliability and capacity of these systems. We seek to address these risks by safeguarding assets, data, and operations through the cybersecurity risk management processes described below:

 Risk Assessment:

 Regular assessments are conducted across our systems, networks, and data infrastructure to identify potential cybersecurity threats and vulnerabilities. These assessments include penetration testing, vulnerability scanning, and red teaming exercises conducted by third-party service providers, which help us to evaluate the likelihood and potential impact of cybersecurity incidents. Feedback from these assessments is incorporated into our systems and procedures through upgrades intended to further improve our security posture.

 Incident Identification and Response:

 A monitoring and detection system has been implemented to help identify cybersecurity incidents. The IT Security Department is tasked with monitoring certain network activities, logs, and system behavior, leveraging threat detection technologies. In the event of any breach or cybersecurity incident, we have an incident response plan that is designed to follow industry best practices and aligns with legal and regulatory requirements. This plan is designed to provide for immediate action to contain the incident, mitigate the impact, and restore normal operations efficiently.

 Cybersecurity Training and Awareness:

 Cybersecurity awareness among our employees is promoted with regular training and awareness programs. Employees receive training on recognizing and reporting potential cybersecurity threats, best practices for data protection, and adhering to cybersecurity policies and procedures. Additionally, periodic simulated phishing exercises are conducted to enhance employee readiness in identifying and mitigating phishing attacks.

 Access Controls:

 Access control policies have been implemented to limit unauthorized access to sensitive information and we seek to maintain and monitor critical systems. Multi-factor authentication is used for remote access, use of privileged accounts and access to critical systems.

 Encryption and Data Protection:

 Encryption methods are used to protect sensitive data in transit and at rest. This includes the encryption of customer data, financial information, and other confidential data.

 The above cybersecurity risk management processes are integrated into the Partnership's overall risk management program. Cybersecurity threats are understood to be dynamic and intersect with various other enterprise risks. As such, cybersecurity is considered as an important component of our enterprise-wide risk management approach. We have assembled a Cybersecurity Steering Committee comprised of IT management, cybersecurity specialists, and representatives of business management, including the CTO and internal legal counsel. The Cybersecurity Steering Committee reviews information security policies and cybersecurity risks in conjunction with other operational, financial, and strategic risks to ensure alignment with our business objectives. The Cybersecurity Steering Committee convenes regularly to review and monitor the Partnership's programs for the prevention, detection, mitigation, and remediation of cybersecurity incidents. The Cybersecurity Steering Committee receives reports on security incidents, threat intelligence, and vulnerability assessments from our IT Security Department.

 The Cybersecurity Steering Committee regularly reports to the CFO through the CTO and reports annually on cybersecurity to the Audit Committee during a scheduled meeting. These reports include, as appropriate, updates on the current cybersecurity landscape, incident trends, and any significant developments that may impact the Partnership's security posture.

 To enhance the effectiveness of our cybersecurity program, we periodically engage external assessors, consultants, and auditors. These third-party service providers conduct independent evaluations of our cybersecurity measures, helping to identify areas for improvement and adherence to industry standards and best practices.

 Our IT Security Department recognizes that third-party service providers may introduce cybersecurity risks to our organization. In an effort to mitigate these risks, we have implemented a process designed to assess and oversee the cybersecurity practices of our vendors. Before engaging with any third-party cybersecurity service provider, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we include cybersecurity requirements in our contracts with these providers, requiring them to adhere to certain cybersecurity standards and protocols.

 Impact of Risks from Cybersecurity Threats

 During 2023 and through the date of this Annual Report on Form 10-K, though the Partnership and our service providers may have experienced cybersecurity incidents, we are not aware of any cybersecurity threats, including as a

 result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect the Partnership, including our business strategy, result of operations, or financial condition. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Our IT Security Department aims to monitor and assess these risks to maintain the security and continuity of our operations. Despite the implementation of our cybersecurity programs, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our IT systems could have significant consequences to our business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. Please see "Item 1A. Risk Factors" for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

 Board of Directors' Oversight of Risks from Cybersecurity Threats

 The Board of Directors oversees risks from cybersecurity threats. Recognizing the importance of cybersecurity to the success and resilience of our business, the Board considers cybersecurity to be an important aspect of corporate governance. To facilitate effective oversight, the Audit Committee and the Board of Directors hold discussions with management, including the CTO on cybersecurity risks, incident trends, and the effectiveness of cybersecurity measures annually and as needed during both scheduled and special meetings. If new material cybersecurity risks arise, the Board of Directors and the Audit Committee are informed through regular discussions between the CFO and both the Chairman of the Board and the Audit Committee Chair. These discussions are then brought to the attention of the Board of Directors and Audit Committee at the next meeting.

 Management's Role and Expertise

 The CTO and the Cybersecurity Steering Committee are responsible for overseeing and executing our cybersecurity strategy, including the assessment and management of cybersecurity risks. The CTO reports directly to the CFO and maintains communication with the Audit Committee, the Board of Directors and the Cybersecurity Steering Committee with respect to information security and cybersecurity matters.

 The CTO holds a Master of Business Administration from the University of Kentucky/University of Louisville's joint executive program and has an extensive background in information security, risk management, and incident response with over twenty years of varying information technology roles with increasing responsibility at both private and public companies. The CTO is supported by a dedicated team of cybersecurity professionals, each bringing diverse expertise in areas such as network security, data protection, and threat intelligence.

 ITEM 2. PROPERTIES

 COAL MINERAL RESOURCES AND RESERVES

 Overview of Coal Properties

 Our coal properties are located in the Illinois Basin and the Appalachia Basin. Our Illinois Basin properties are located in western Kentucky, southern Illinois, and southern Indiana. Our Appalachian properties are located in eastern Kentucky, Maryland, western Pennsylvania, and northern West Virginia. Mining operations on our coal properties consist of underground mines that produce bituminous coal that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). In addition to our coal mining operations, we also hold coal mineral interests that we lease/sublease to our operations or hold for lease/sublease to our operations or others. For a detailed overview of our coal mining operations and our coal royalty activities, please see "Item 1. Business—Coal Mining Operations" and "Item 1. Business—Mineral Interest Activities", respectively.

 Evaluation and Review of Coal Mineral Resources and Reserves

 Numerous uncertainties are inherent in estimating coal mineral resources and reserves, and the estimates are subject to change as additional information becomes available or circumstances change. Significant factors and assumptions related to the uncertainty in estimating coal mineral reserves and resources include:

 geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;

 the percentage of coal in the ground ultimately recoverable;

 historical production from the area compared with production from other producing areas;

 the assumed effects of regulation and taxes by governmental agencies;

 future improvements in mining technology; and

 assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.

 Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect the actual coal reserves and resources. Actual production, revenues and expenditures with respect to the coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in the closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results.

 Under SEC rules, a mineral resource is a concentration or occurrence of material of economic interest in or on the Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into account relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. A mineral reserve is an estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

 The coal mineral resource and reserve estimates included in this Annual Report on Form 10-K were prepared by an independent, qualified engineering firm, RESPEC. We provided RESPEC with property control, mine plans, production, revenue, costs, capital, and other information considered by RESPEC in making their estimates. As part of our internal controls, our geologists and engineers review the integrity, accuracy, and timeliness of the data provided to RESPEC that they considered in calculating their coal mineral resource and reserve estimates. We also review the geologic data, mining assumptions, and methodology used by RESPEC to estimate our coal mineral resources and reserves. Our geologists and engineers also met with RESPEC periodically during the year to discuss the assumptions and methods used in the coal mineral resource and reserve estimation process.

 RESPEC, an independent third-party engineering firm, does not own an interest in any of our properties and is not employed on a contingent basis. RESPEC prepared the initial TRS for each of our material mining properties. The TRSs will be updated when there are material changes to the coal mineral reserve or resource estimates. The most recent TRSs for our material mining operations are included as exhibits to our Annual Report on Form 10-K.

 Summary of Coal Mineral Resources and Reserves

 Coal Mineral Resources

 Most of our coal properties designated as mineral resources are of thickness, quality, and mineability similar to that of the mineral reserves, and all are proximal to existing infrastructure such as power, water, transportation, facilities, etc. However, we have not completed pre-feasibility or feasibility studies with respect to our coal properties designated as mineral resources, as is required to convert the mineral resources into mineral reserves. There is no certainty that all or any part of the mineral resources will be converted into mineral reserves.

 The following table sets forth our coal mineral resources, exclusive of coal mineral reserves, at December 31, 2023:

 Heat

 Content (Btus

 Pounds SO2 per MMBtu

 Resource Classification

 Ownership

 Resources (tons in millions)

 per pound)

 <1.2

 1.2-2.5

 >2.5

 Measured

 Indicated

 Combined

 Inferred

 Owned

 Leased

 Total

 (1)

 Dotiki (KY)

 12,100

 —

 2.3

 73.7

 51.2

 24.8

 76.0

 —

 27.6

 48.4

 76.0

 Henderson/Union (KY)

 11,450

 —

 3.0

 409.7

 127.3

 227.9

 355.2

 57.5

 74.0

 338.7

 412.7

 River View (KY)

 11,450

 —

 —

 0.3

 —

 —

 —

 0.3

 —

 0.3

 0.3

 Sebree South (KY)

 11,750

 —

 —

 43.5

 22.1

 16.8

 38.9

 4.6

 0.3

 43.2

 43.5

 Hamilton County (IL)

 11,650

 5.1

 33.8

 405.8

 191.2

 242.3

 433.5

 11.2

 32.8

 411.9

 444.7

 5.1

 39.1

 933.0

 391.8

 511.8

 903.6

 73.6

 134.7

 842.5

 977.2

 Appalachian Basin

 Mountain View (WV)

 13,200

 —

 0.4

 8.3

 4.1

 4.4

 8.5

 0.2

 1.8

 6.9

 8.7

 Tunnel Ridge (WV)

 12,600

 —

 —

 0.9

 —

 0.2

 0.2

 0.7

 0.7

 0.2

 0.9

 Penn Ridge (PA)

 12,500

 —

 —

 78.0

 21.9

 53.2

 75.1

 2.9

 78.0

 —

 78.0

 —

 0.4

 87.2

 26.0

 57.8

 83.8

 3.8

 80.5

 7.1

 87.6

 Total

 5.1

 39.5

 1,020.2

 417.8

 569.6

 987.4

 77.4

 215.2

 849.6

 1,064.8

 % of Total

 0.5%

 3.7%

 95.8%

 39.2%

 53.5%

 92.7%

 7.3%

 20.2%

 79.8%

 100.0%

 (1)
 Combined resources are defined as measured plus indicated resources.

 At December 31, 2023, we had approximately 1.065 billion tons of coal mineral resources. Tonnages are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2023 in a range from approximately $53 to $59 per short ton in the Illinois Basin and from approximately $62 to $119 per short ton in the Appalachian Basin, which are the prices used by RESPEC to estimate the amount of coal mineral resources. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All resources are classified as underground mineable in the exploration stage.

 Coal Mineral Reserves

 Reserves are assigned to our active operations and are (1) currently in production, (2) economically viable, and (3) meet the other requirements to be considered reserves as defined by the SEC.

 The following table sets forth coal mineral reserve information, exclusive of the coal mineral resources above, at December 31, 2023, about our coal operations:

 Heat

 Content (Btus

 Pounds SO2 per MMBtu

 Classification

 Ownership

 Reserves (tons in millions)

 per pound)

 <1.2

 1.2-2.5

 >2.5

 Proven

 Probable

 Owned

 Leased

 Total

 Illinois Basin Operations

 Warrior (KY)

 12,300

 —

 —

 50.0

 39.5

 10.5

 13.0

 37.0

 50.0

 River View (KY)

 11,450

 —

 —

 310.4

 169.1

 141.3

 58.0

 252.4

 310.4

 Hamilton County (IL)

 11,650

 —

 —

 119.8

 54.5

 65.3

 20.3

 99.5

 119.8

 Gibson South (IN)

 11,500

 0.9

 9.5

 34.8

 35.6

 9.6

 15.3

 29.9

 45.2

 0.9

 9.5

 515.0

 298.7

 226.7

 106.6

 418.8

 525.4

 Appalachian Basin Operations

 MC Mining (KY)

 12,800

 9.6

 0.5

 —

 7.8

 2.3

 —

 10.1

 10.1

 Mountain View (WV)

 13,200

 —

 4.4

 5.1

 9.1

 0.4

 —

 9.5

 9.5

 Tunnel Ridge (WV)

 12,600

 —

 —

 118.2

 64.5

 53.7

 11.7

 106.5

 118.2

 9.6

 4.9

 123.3

 81.4

 56.4

 11.7

 126.1

 137.8

 Total

 10.5

 14.4

 638.3

 380.1

 283.1

 118.3

 544.9

 663.2

 % of Total

 1.6%

 2.2%

 96.2%

 57.3%

 42.7%

 17.8%

 82.2%

 100.0%

 On December 31, 2023, we had approximately 663.2 million tons of coal mineral reserves. Tonnages are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2023 in a range from approximately $53 to $59 per short ton in the Illinois Basin and from approximately $62 to $119 per short ton in the Appalachian Basin, which are the prices used by RESPEC to estimate the amount of coal mineral reserves. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All reserves are classified as underground mineable in the development or production stage.

 Mining Operations

 The following table sets forth production and other data about our mining operations:

 Tons Produced

 Operations

 Location

 2023

 2022

 2021

 Transportation

 Equipment

 Illinois Basin Operations

 Warrior

 Kentucky

 4.4

 4.1

 4.1

 CSX, NS, PAL, truck, barge

 CM

 River View

 Kentucky

 9.9

 10.2

 9.9

 Truck, barge

 CM

 Hamilton County

 Illinois

 5.6

 4.7

 4.9

 CSX, EVW, NS, barge

 LW, CM

 Gibson South

 Indiana

 5.3

 5.3

 3.3

 CSX, NS, truck, barge

 CM

 25.2

 24.3

 22.2

 Appalachian Basin Operations

 MC Mining/Excel

 Kentucky

 1.2

 1.5

 1.3

 CSX, truck, barge

 CM

 Mountain View

 West Virginia

 0.8

 1.4

 1.5

 CSX, truck

 LW, CM

 Tunnel Ridge

 West Virginia

 7.7

 8.3

 7.2

 CSX, NS, barge

 LW, CM

 9.7

 11.2

 10.0

 TOTAL

 34.9

 35.5

 32.2

 CSX

 -

 CSX Railroad

 EVW

 -

 Evansville Western Railroad

 NS

 -

 Norfolk Southern Railroad

 PAL

 -

 Paducah & Louisville Railroad

 CM

 -

 Continuous Miner

 LW

 -

 Longwall

 Individual Property Disclosures

 We consider the following properties to be material based on multiple factors including, but not limited to, the property's contribution to our overall business and financial condition. Please see Coal Mineral Resources and Coal Mineral Reserves above for information about the coal mineral resources and reserves held by these material properties. In addition to the following information, TRSs for these material properties with additional information are included as exhibits to this Annual Report on Form 10-K.

 Henderson/Union Resources

 The Henderson/Union Resources are located in Henderson and Union counties, Kentucky at 37 44'30"N, -87 46'07"W and we currently have control in over 1,600 tracts encompassing over 127,000 acres. The property is controlled through both fee ownership and leases of the coal. The coal mineral resources are controlled by Alliance Resource Properties. The base leases are with private owners and WKY CoalPlay or its subsidiaries, which are related parties. See "Item 8. Financial Statements and Supplementary Data — Note 20 – Related-Party Transactions" for more information about our WKY CoalPlay transactions. These base leases generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:

 Major Roads: Interstates 69 and US-60,
 Railroads: None,
 Airport: Evansville Regional Airport (EVV),
 Town: Morganfield,
 Docks: River View, Hamilton 1, UC Processing, on the Ohio River,
 Water: Local municipalities and mine sources,
 Electricity: Kentucky Utilities (KU),

 The potential underground mine(s) would utilize room-and-pillar methods operating a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill possible permitting and development requirements. Multiple access points are available for development. Access is available from the active River View complex, which began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Access at the Hamilton and UC Coal, LLC sites are considered "brownfield" developments. Though some facilities and permitting are in place, significant upgrades to existing infrastructure and new construction would be needed to bring them into good working order that meets industry standards. The property associated with Henderson/Union has no book value as of December 31, 2023 but does have outstanding advanced royalties with WKY CoalPlay or its subsidiaries. See "Item 8. Financial Statements and Supplementary Data — Note 20 – Related-Party Transactions" for more information about advanced royalties that Henderson/Union has with WKY CoalPlay.

 Though there is geographic overlap between the Henderson/Union and River View properties, the resources and reserves of each are associated with different coal seams or, if in the same seam, are separated by existing mine works or geologic features into distinct areas. There is no overlap in the resource / reserve estimation.

 The Henderson/Union property contains resources in three coal seams, the WKY11, the WKY7, and the WKY6. Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and controlled a portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 mine. Peabody and later Patriot operated the Camp complex and Highland #11 mine to the southeast and east. The WKY11 seam was mined at these locations. No mining has occurred on the property in the

 WKY7 or WKY6 seams. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market.

 Our credit facility is secured by, among other things, liens against certain Henderson/Union surface properties and coal leases. Documentation of such liens is of record in the Offices of the Henderson and Union County Clerks. Please read "Item 8. Financial Statements and Supplementary Data — Note 6 – Long-term Debt" for more information on our credit facility.

 The KYDNR, DMP is responsible for the review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining.

 Henderson/Union contains coal resources in three seams ranging in depths from about 100 to 750 feet. The table below summarizes mineral resources as of December 31, 2023, using a cut off thickness of 4.00 feet:

 Resources (1)

 % Ash

 Btu

 Henderson/Union

 Measured Mineral Resources

 127.3

 4.68

 7.72

 2.88

 13,327

 4.32

 85.48

 Indicated Mineral Resources

 227.9

 4.59

 8.01

 2.74

 13,306

 4.12

 87.07

 Combined Mineral Resources

 355.2

 4.62

 7.90

 2.79

 13,314

 4.19

 86.50

 Inferred Mineral Resources

 57.5

 4.46

 7.97

 2.56

 13,350

 3.84

 90.42

 (1)
 See updated TRS for Henderson/Union at Exhibit 96.1 to this Annual Report 10-K reflecting the material change to resources during 2023.

 River View Complex

 The River View complex is located in Union County, Kentucky at 37 45'37"N, -87 56'42"W and currently has approximately 93,200 underground acres permitted. The complex is composed of the River View and Henderson County mines along with shared preparation, loadout, and other ancillary facilities. The complex is controlled through both fee ownership and leases of the coal. The coal mineral reserves are leased or held for lease to the River View complex almost exclusively by Alliance Resource Properties. The River View complex either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. The base leases are with private owners and generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:

 Major Roads: Interstates 69 and US-60,
 Railroads: None,
 Airport: Evansville Regional Airport (EVV),
 Town: Morganfield,
 Docks: River View on the Ohio River,
 Water: Union and Henderson County water districts and mine sources,
 Electricity: Kentucky Utilities (KU),

 The underground mines are currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The complex began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for the River View Complex as of December 31, 2023 was $312.7 million.

 Though there is geographic overlap between the River View complex and the Henderson/Union properties, the reserves and resources of each are associated with different coal seams or, if in the same seam, are separated by existing mine works or geologic features into distinct areas. There is no overlap in the resource / reserve estimation.

 Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and controlled a smaller portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 and Uniontown #9 mines to the west of River View. Island Creek also operated the Hamilton #1 and #2 mines to the southwest. Peabody and later Patriot operated the Camp mines and Highland mines adjacent to the complex. Both the WKY9 and WKY11 seams were mined at these locations. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market.

 Our credit facility is secured by, among other things, liens against certain River View complex surface properties and coal leases. Documentation of such liens is of record in the Office of the Union County Clerk. Please read "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-term Debt" for more information on our credit facility.

 Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Union County Clerk. Please read "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-term Debt" for more information on our accounts receivable securitization facility.

 The KYDNR, DMP is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities, and other incidental activities have been obtained and remain in good standing.

 The River View complex extracts coal underground from the West Kentucky No. 11 and No. 9 seams with depths ranging from 200 to 500 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2023 using a cut off thickness of 4.00 feet:

 Reserves

 % Ash

 Btu

 River View Complex

 Proven Mineral Reserves

 169.1

 4.69

 8.08

 3.20

 13,191

 4.85

 87.40

 Probable Mineral Reserves

 141.3

 4.56

 8.25

 3.18

 13,141

 4.85

 87.25

 Total Mineral Reserves

 310.4

 4.63

 8.16

 3.19

 13,168

 4.85

 87.33

 Resources associated with the River View complex are included in the Coal Mineral Resources table above.

 The River View complex had 204.7 million tons of coal mineral reserves at the end of 2022. The year over year reconciliation is as follows:

 River View Complex Yearly Reserve Reconciliation

 Tons as of December 31, 2022

 204.7

 (9.9)

 Mineral Acquisition / Deletion (1)

 115.2

 Normal Course Adjustments

 0.4

 Tons as of December 31, 2023

 310.4

 (1)
 See updated TRS for River View complex at Exhibit 96.2 to this Annual Report on Form 10-K reflecting the material change to reserves for 2023.

 Normal course adjustments are associated with numerous slight changes in the geologic model.

 Hamilton Mine

 Hamilton, a longwall mine located in Hamilton County, Illinois at 38 10'12"N, -88 36'47"W, currently has approximately 23,000 underground acres and 1,300 surface acres permitted. The mine property is controlled through both fee ownership and leases of the coal. The coal mineral reserves and resources are leased or held for lease to Hamilton by Alliance WOR Properties, a subsidiary of Alliance Resource Properties. Hamilton either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. The underlying base coal leases are with private owners and are comprised of a large number of leases originally taken by AMAX Coal Company and Old Ben in the mid to late 1970's and early, leases acquired by

 Consolidation Coal Company in the late 1980's, and subsequent leases taken directly by White Oak Resources, LLC or affiliated companies and/or Alliance WOR Properties. Local infrastructure is as follows:

 Major Roads: Interstates 64,
 Railroads: CSX and EVW,
 Airport: Evansville Regional Airport (EVV),
 Towns: McLeansboro and Mt. Vernon,
 Docks: Mount Vernon on the Ohio River,
 Water: Hamilton County Water District and mine sources,
 Electricity: Wayne-White Electric Co-op (WWEC),

 The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Hamilton as of December 31, 2023 was $332.4 million.

 There were no previous operations on the Hamilton reserves property prior to our predecessor, White Oak Resources LLC, who began construction of the mine in 2011. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market for the Herrin and Springfield seams.

 Our credit facility is secured by, among other things, liens against certain Hamilton surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Hamilton County Clerk. Please read "Item 8. Financial Statements and Supplementary Data — Note 6 – Long-term Debt" for more information on our credit facility.

 Certain leases originally acquired by Consolidation Coal Company are encumbered by an overriding royalty payable to Sustainable Conservation, Inc. in the amount of the greater of $0.25 per ton or 0.75% of the average sales realization price received per ton, which sums can be credited against approximately $481,000 previously paid to Sustainable Conservation, Inc. for the assignment of these leases.

 The Illinois Department of Natural Resources, Land Reclamation Division is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities and other incidental activities have been obtained and remain in good standing.

 Hamilton extracts coal underground from the Herrin (Illinois No.6) seam with depths ranging from 900 to 1100 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2023 using a cut off thickness of 4.00 feet:

 Reserves

 % Ash

 Btu

 Hamilton County

 Proven Mineral Reserves

 54.5

 6.38

 8.07

 2.82

 13,414

 4.21

 86.65

 Probable Mineral Reserves

 65.3

 6.60

 7.98

 2.85

 13,422

 4.24

 86.77

 Total Mineral Reserves

 119.8

 6.50

 8.02

 2.83

 13,419

 4.23

 86.71

 Resources associated with Hamilton County are included in the Coal Mineral Resources table above.

 The Hamilton mine had 125.9 million tons of coal mineral reserves at the end of 2022. The year over year reconciliation is as follows:

 Hamilton County Yearly Reserve Reconciliation

 Tons as of December 31, 2022

 125.9

 (5.6)

 Mineral Acquisition / Deletion

 4.1

 Mine Plan Adjustment

 (4.9)

 Normal Course Adjustments

 0.3

 Tons as of December 31, 2023

 119.8

 Normal course adjustments are associated with numerous slight changes in the geologic model.

 Gibson South Mine

 Gibson South is located in Gibson County, Indiana at 38 18'22"N, 87 42'30"W and currently has approximately 23,350 underground acres permitted. The mine property is controlled through both fee ownership and leases of the coal. Leases generally have an initial term with automatic extensions for as long as mining operations are conducted within a described area. Local infrastructure is as follows:

 Major Roads: Interstates 69 and 64,
 Railroads: CSX and NS,
 Airport: Evansville Regional Airport (EVV),
 Town: Princeton,
 Docks: Mount Vernon on the Ohio River,

 Water: Gibson Water, Inc. and well water,
 Electricity: Western Indiana Energy REMC,

 The underground mine is currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Gibson South as of December 31, 2023 was $117.0 million.

 In November 1997, pursuant to (a) Assignment of Underground Coal Leases, (b) Partial Assignment of Underground Coal Leases and (c) Special Corporate Warranty Deed, Old Ben conveyed to MAPCO Land & Development Corporation various coal leases and fee coal interests within a large property boundary located in Gibson County, Indiana. MAPCO Land & Development Corporation changed its name to MAPCO Coal Land & Development Corporation, and MAPCO Coal Land & Development Corporation merged into Alliance Properties effective August 4, 1999.

 After the original Old Ben acquisition, Alliance Properties and Gibson continued to acquire additional coal leases and fee coal interests in the area. In addition, beginning in or around 2006, the leases originally acquired from Old Ben began to expire by their terms, and Alliance Properties/Gibson began a program of either amending the expiring leases or entering into new, direct leases with the coal owners. Alliance Properties merged into Gibson on February 19, 2018.

 The King's Mine operated to the east and the Wabash Mine operated to the west of the reserve area. In general, all drilling has shown a highly consistent coal seam of mineable thickness and quality for the high-sulfur thermal utility market.

 Our credit facility is secured by, among other things, liens against certain Gibson surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Recorder of Gibson County, Indiana. Please read "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-term Debt" for more information on our credit facility.

 Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Recorder of Gibson County, Indiana. Please read "Item 8. Financial Statements and Supplementary Data — Note 6 – Long-term Debt" for more information on our accounts receivable securitization facility.

 The Indiana Department of Natural Resources, Division of Reclamation is responsible for oversight of active coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation, and related facilities and other incidental activities have been obtained and remain in good standing.

 Gibson South extracts coal underground from the Springfield (Indiana No.5) seam with depths ranging from 450 to 650 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2023 using a cut off thickness of 4.00 feet:

 Reserves

 % Ash

 Btu

 Gibson South

 Proven Mineral Reserves

 35.6

 5.96

 7.13

 2.00

 13,477

 2.97

 94.81

 Probable Mineral Reserves

 9.6

 5.33

 8.15

 2.51

 13,322

 3.77

 92.82

 Total Mineral Reserves

 45.2

 5.81

 7.34

 2.11

 13,444

 3.14

 94.37

 Resources associated with Gibson South are included in the Coal Mineral Resources table above.

 The Gibson South mine had 49.0 million tons of coal mineral reserves at the end of 2022. The year over year reconciliation is as follows:

 Gibson South Yearly Reserve Reconciliation

 Tons as of December 31, 2022

 49.0

 (5.3)

 Mineral Acquisition / Deletion

 1.5

 Tons as of December 31, 2023

 45.2

 Normal course adjustments are associated with numerous slight changes in the geologic model.

 Tunnel Ridge Mine

 Tunnel Ridge, located at 40 09'17" N, -80 39'26"W, is an underground longwall mine in the Pittsburgh No. 8 seam of coal, and currently has approximately 22,345 underground acres permitted. The mine property is controlled through both fee ownership and leases of the coal. The coal mined and to be mined by Tunnel Ridge is leased from the Joseph W. Craft III Foundation, the Kathleen S. Craft Foundation, Alliance Resource Properties and third parties. Please read "Item 8. Financial Statements and Supplemental Data - Note 20 – Related-Party Transactions" for additional information on related-party leases. Tunnel Ridge either owns or controls the surface properties upon which its facilities are located, including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. Local infrastructure is as follows:

 Major Roads: Interstate 70,
 Railroads: None,
 Airport: Pittsburgh International Airport (PIT),
 Town: Wheeling,
 Docks: Tunnel Ridge on the Ohio River,
 Water: Municipal water districts and mine sources,
 Electricity: American Electric Power (AEP), West Penn Power (WPP)

 The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2010. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Tunnel Ridge as of December 31, 2023 was $301.7 million.

 Valley Camp Coal Company operated mines on the property prior to Tunnel Ridge's operations. In general, all drilling has shown a highly consistent coal seam of mineable thickness and quality for the high-sulfur thermal utility market.

 Our credit facility is secured by, among other things, liens against certain Tunnel Ridge surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read "Item 8. Financial Statements and Supplementary Data — Note 6 – Long-term Debt" for more information on our credit facility.

 Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read "Item 8. Financial Statements and Supplementary Data — Note 6 – Long-term Debt" for more information on our accounts receivable securitization facility.

 Tunnel Ridge is located on the West Virginia / Pennsylvania State boundary, operating in each state. As such, regulatory requirements must be met pertaining to mining facilities located in each state.

 For operations in West Virginia, the WVDEP is the regulatory authority over mining activities. Within the WVDEP, the Division of Mining and Reclamation is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.

 For operations in Pennsylvania, the PADEP is the regulatory authority over mining activities. Within the PADEP, the Bureau of District Mining Operations is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.

 Tunnel Ridge extracts coal underground from the Pittsburgh No.8 seam with depths ranging from 300 to 975 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2023 using a cut off thickness of 4.00 feet:

 Reserves

 % Ash

 Btu

 Tunnel Ridge

 Proven Mineral Reserves

 64.5

 7.12

 7.92

 3.10

 13,711

 4.52

 67.88

 Probable Mineral Reserves

 53.7

 7.26

 8.30

 3.49

 13,618

 5.13

 68.06

 Total Mineral Reserves

 118.2

 7.18

 8.09

 3.28

 13,669

 4.79

 67.96

 Resources associated with Tunnel Ridge are included in the Coal Mineral Resources table above.

 The Tunnel Ridge mine had 120.0 million tons of coal mineral reserves at the end of 2022. The year over year reconciliation is as follows:

 Tunnel Ridge Yearly Reserve Reconciliation

 Tons as of December 31, 2022

 120.0

 (7.7)

 Mineral Acquisition / Deletion

 (1.2)

 Mine Plan Adjustment

 6.8

 Normal Course Adjustments

 0.3

 Tons as of December 31, 2023

 118.2

 OIL & GAS RESERVES

 Summary of 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, 2023, we had 49,794 developed and undeveloped net acres held at a weighted average royalty of 17.0%. Our net acres standardized to 1/8th royalty equates to 67,745 net royalty acres, including 3,969 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 attributable to our equity interest in AllDale III, as of December 31, 2023 based on the reserve report prepared by our internal engineering team and reserve information provided by AllDale III. The reserve report and reserve information have been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the continental United States.

 As of December 31, 2023

 Crude Oil

 Natural Gas

 Natural Gas Liquids

 Total

 (MMcf)

 (MBOE) (2)

 Estimated proved developed reserves

 7,754

 45,684

 5,485

 20,854

 Estimated proved undeveloped reserves

 1,599

 5,839

 3,440

 Total estimated proved reserves (1)

 9,353

 51,523

 6,353

 24,294

 (1)
 Proved reserves of approximately 1,780 MBOE were attributable to noncontrolling interests as of December 31, 2023.

 (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, 2023 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 2023. The average realized product prices weighted by production over the remaining lives of the properties are $77.61/Bbl for oil, $1.55/Mcf of natural gas and $22.63 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 2023, NGL prices averaged approximately 33% of the posted oil prices during the course of the year with an additional $3.18/Bbl deducted for transportation costs.

 The following table summarizes our changes in proved undeveloped reserves (in MBOE):

 Beginning balance, January 1, 2023*

 3,795

 Acquisitions of proved undeveloped reserves

 Transfers of PUDs to estimated proved developed

 (1,448)

 2,462

 (1,407)

 Ending balance, December 31, 2023

 3,440

 * Recast to reflect the JC Resources Acquisition as if we, rather than JC Resources, acquired the mineral interests in 2019. Please see "Item 8. Financial Statement and Supplemental Data—Note 1 – Organization and Presentation and Note 3 – Acquisitions" for more information.

 As a mineral interest owner we have no transparency into or control over the 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 the Operators. As a result, during the year ended December 31, 2023, we did not have any expenditures to convert PUDs to proved developed producing reserves. PUDs that have not been developed within two years of permitting are reviewed and removed from proved reserves as necessary. As of December 31, 2023, approximately 14.16% 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, 2023 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.

 Excluding our share of proved reserves held by AllDale III, our 2023 year-end estimate of 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. Our proved resource estimates were audited by CGA. Our engineering team met with CGA 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 CGA for our properties, such as oil & gas production, well test data, and realized commodity prices. Our engineering team also provided ownership interest information with respect to our properties. Our internal petroleum engineer, primarily responsible for overseeing the petroleum reserves preparation, has over 20 years of engineering and operations experience in the oil & gas sector and a Bachelor of Science in Petroleum Engineering.

 The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 review and verification of historical data, which is based on actual production as reported by the 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 CGA;

 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.

 CGA, 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 CGA estimates. CGA is satisfied with our methods and procedures used to prepare the December 31, 2023 reserve estimates and future revenue, and noted nothing of an unusual nature that would cause CGA to take exception with the estimates, in the aggregate, prepared by us. CGA's audit report with the respect to our proved reserve estimates as of December 31, 2023 is included as an exhibit to this Annual Report on Form 10-K.

 CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for auditing the estimates meets 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 and is 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, 2023.

 Developed Acreage

 Undeveloped Acreage

 Gross

 Net Mineral

 Net Royalty

 Gross

 Net Mineral

 Net Royalty

 Basin

 Permian Basin

 378,510

 11,114

 14,894

 517,804

 15,204

 20,350

 Anadarko Basin

 179,993

 6,489

 9,199

 295,884

 10,667

 15,112

 Williston Basin

 153,772

 2,541

 3,363

 84,118

 1,390

 1,849

 Other

 28,174

 1,027

 1,296

 37,363

 1,362

 1,682

 Total

 740,449

 21,171

 28,752

 935,169

 28,623

 38,993

 Oil & Gas Production Prices and Production Costs

 For the year ended December 31, 2023, 45.5% of our production and 79.4% of our oil & gas revenues were related to oil production and sales, respectively. The following table sets forth information regarding production of oil & gas including our equity investment in AllDale III and certain price and cost information for each of the periods indicated:

 2023

 2022*

 2021*

 Production:

 Oil (MBbls)

 1,462

 1,104

 Natural gas (MMcf)

 6,161

 5,226

 3,881

 Natural gas liquids (MBbls)

 BOE (MBbls)

 3,215

 2,516

 1,978

 Average Realized Prices:

 Oil (per Bbl)

 $

 77.40

 $

 94.76

 $

 66.19

 Natural gas (per Mcf)

 $

 2.03

 $

 6.29

 $

 3.86

 Natural gas liquids (per Bbl)

 $

 23.15

 $

 38.53

 $

 28.58

 BOE (MBbls)

 $

 44.32

 $

 62.94

 $

 44.47

 Unit cost per BOE:

 Production and ad valorem taxes

 $

 4.37

 $

 5.61

 $

 4.54

 * Recast to reflect the JC Resources Acquisition as if we, rather than JC Resources, acquired the mineral interests in 2019. Please see "Item 8. Financial Statement and Supplemental Data—Note 1 – Organization and Presentation and Note 3 – Acquisitions" for more information.

 Productive Wells

 As of December 31, 2023, 10,795 gross productive horizontal wells and 5,769 gross productive vertical wells were located on the acreage in which we have a mineral interest. Of our productive horizontal wells, 992 are considered natural gas wells, while the remaining 9,803 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 21 – Commitments and Contingencies" is incorporated herein by this reference.

 Litigation was initiated in November 2019 in the U.S. District Court for the Western District of Kentucky (Branson v. Webster County Coal, LLC et al.) against certain of our subsidiaries in which the plaintiffs allege violations of the Fair Labor Standards Act and state law 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. 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.). Subsequently, four additional lawsuits making similar allegations were initiated against certain of our subsidiaries: filed March 4, 2021 in the Circuit Court for Hopkins County, Kentucky (Johnson v. Hopkins County Coal, LLC, et al.); filed April 6, 2021 in the U.S. District Court for the Northern District of West Virginia (Rettig v. Mettiki Coal WV, LLC, et al.); filed April 9, 2021 in the U.S. District Court for the Southern District of Illinois (Cates v. Hamilton County Coal, LLC, et al.); and filed April 13, 2021 in the U.S. District Court for the Southern District of Indiana (Prater v. Gibson County Coal, LLC, et al.). The plaintiffs in these cases seek class and collective action certification, which we oppose, and the courts have not yet made

 definitive final rulings on these issues. The plaintiffs seek to recover alleged compensatory, liquidated and/or exemplary damages for the alleged underpayment, and costs and fees that potentially may be recoverable under applicable law. We believe our ultimate exposure, if any, will not be material to our results of operations or financial position; however, if our current belief as to the merit of the claims in these lawsuits is not upheld, it is reasonably possible that the ultimate resolution of these matters could result in a potential loss that may be material to our results of operations.

 ITEM 4. MINE SAFETY DISCLOSURES

 Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 to this Annual Report on Form 10-K.

 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 53,108 record holders of common units at December 31, 2023.

 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. In January 2023, the Board of Directors authorized a $93.5 million increase to the unit purchase program, which had $6.5 million of available capacity at the time. 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 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, 2023, we did not repurchase and retire any units. Since the inception of the unit repurchase program, we have repurchased and retired 6,390,446 units at an average unit price of $17.67 for an aggregate purchase price of $112.9 million. The remaining authorized amount for unit repurchases under this program was $80.6 million at December 31, 2023.

 ITEM 6. [Reserved]

 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 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

 Organization

 We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic utilities, industrial users and international customers, as well as royalty income from oil & gas mineral interests located in strategic producing regions across the United States. In addition, we continue to position ourselves as a reliable energy provider for the future as we pursue opportunities that support the advancement of energy and related infrastructure. We intend to pursue strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments.

 We are currently the largest coal producer in the eastern United States with seven operating underground mining complexes near many of the major eastern utility generating plants and on major coal hauling railroads in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia, as well as a coal-loading terminal in Indiana. Two of our mines also have loading facilities located on the Ohio River.

 In addition to our mining operations, Alliance Resource Properties owns or leases substantially all of our coal mineral resources and the majority of our coal mineral reserves in the Illinois and Appalachia Basins that are (a) leased to our internal mining complexes or (b) near our coal mining operations but not yet leased.

 We currently own minerals interests in approximately 67,700 net royalty acres in premier oil & gas producing regions of the United States, primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins providing us with diversified exposure to industry-leading operators consistent with our general strategy to grow our oil & gas mineral interest business.

 We have invested in energy and infrastructure opportunities including our investments in Francis, Infinitum, NGP ET IV, and Ascend which are in the businesses of, respectively, electric vehicle charging stations, electric motor manufacturing, private equity investments in renewable energy, the electrification of our economy or the efficient use of energy, and the manufacturing and recycling of sustainable, engineered battery materials for electric vehicles.

 Please see "Item 1. Business and Item 2. Properties" in our Annual Report on Form 10-K for the year ended December 31, 2023 for a more detailed discussion of our various businesses.

 As of December 31, 2023, we had four reportable segments: Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an "all other" category referred to as Other, Corporate and Elimination. Our two coal operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. Our Oil & Gas Royalties reportable segment includes our oil & gas mineral interests. Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties.

 The Illinois Basin Coal Operations reportable segment includes (a) the Gibson mining complex, (b) the Warrior mining complex, (c) the River View mining complex and (d) the Hamilton mining complex. The segment also includes our Mt. Vernon coal-loading terminal in Indiana which operates on the Ohio River, MAC and other support services, and our idled or closed mining complexes.

 The Appalachia Coal Operations reportable segment includes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining mining complex.

 The Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by Alliance Minerals as well as our equity interests in AllDale III.

 The Coal Royalties reportable segment includes substantially all of our coal mineral resources and the majority of our coal mineral reserves owned or leased by Alliance Resource Properties. Approximately 60% of the coal sold by our coal operations' mines was leased from our Coal Royalties entities.

 Other, Corporate and Elimination includes marketing and administrative activities, the Matrix Group, our investments in Francis, Infinitum, NGP ET IV and Ascend, Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding and Alliance Resource Finance Corporation (both discussed in "Item 8. Financial Statements and Supplementary Data – Note 6 – Long-Term Debt") and other miscellaneous activities. The eliminations included in Other, Corporate and Elimination primarily represent the intercompany coal royalty transactions described above between our Coal Royalties reportable segment and our coal operations' mines.

 Oil & Gas Acquisitions

 During 2023, through the JC Resources and Skyland Acquisitions and other ground game acquisitions, we acquired approximately 6,443 oil & gas net royalty acres in the Delaware, Anadarko and Williston basins. These acquisitions enhanced our ownership position in these basins and furthered our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions. See "Item 8. Financial Statements and Supplementary Data – Note 3 – Acquisitions" for more information.

 During 2023, we invested $49.6 million in Infinitum and Ascend. This brings our total investment in Francis, Infinitum, NGP ET IV and Ascend to $119.1 million with a remaining commitment of $18.4 million to NGP ET IV. See "Item 8. Financial Statements and Supplementary Data – Note 12 – Equity Investments" for additional information on Francis, Infinitum, NGP ET IV and Ascend.

 Risks and Uncertainties

 We face a variety of risks and uncertainties that management considers in the operation and planning of our businesses, which could affect our financial position and results of operations. For additional information regarding our risks and uncertainties that affect our business and the industries in which we operate, see "Item 1A. Risk Factors".

 Business Strategy

 Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize unitholder returns by:

 expanding our coal operations by adding and developing mines and coal mineral reserves and resources in existing, adjacent or neighboring properties;

 extending the lives of our current mining operations through the acquisition and development of coal mineral reserves and resources using our existing infrastructure;

 continuing to make productivity improvements to remain a low-cost coal producer in each region in which we operate;

 strengthening our position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services;

 developing strategic relationships to take advantage of opportunities within the coal and oil & gas industries and in other industries inside and outside of the Master Limited Partnership sector;

 continuing to make investments in oil & gas mineral interests in various geographic locations within producing basins in the continental United States;

 strengthen and expand our technology company, Matrix Group, as we continue to develop and market industrial, mining and technology products and services worldwide; and

 continuing to identify and make strategic investments in the advancement of energy and related infrastructure opportunities to leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation.

 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) coal sales price per ton; (2) BOE sold; (3) price per BOE; (4) coal royalty tons sold; (5) coal royalty revenue per ton; (6) Segment Adjusted EBITDA Expense per ton; (7) EBITDA; and (8) Segment Adjusted EBITDA.

 Coal Sales Price per Ton

 We define coal sales price per ton as total coal sales divided by tons sold. We review coal sales price per ton to evaluate marketing efforts and for market demand and trend analysis.

 Oil & gas BOE sold

 We monitor and analyze our BOE sales volumes from the various basins that comprise our portfolio of mineral interests. We also regularly compare projected volumes to actual volumes reported and investigate unexpected variances.

 Price per BOE

 We define price per BOE as total oil & gas royalties divided by BOE produced. We review price per BOE to evaluate performance against budget and for trend analysis.

 Coal Royalty Tons sold

 We monitor and analyze our coal royalty sales volumes from our various mining subsidiaries for coal leased by Alliance Resource Properties for consistency with our coal operations segments and for trend analysis.

 Coal Royalty Revenue per Ton

 We define coal royalty revenue per ton as total coal royalties divided by royalty tons sold. We review coal royalty revenue per ton to evaluate consistency with our coal operations segments and for trend analysis.

 Segment Adjusted EBITDA Expense per Ton

 We define Segment Adjusted EBITDA Expense per ton (a non-GAAP financial measure) as the sum of operating expenses, coal purchases and other expense divided by total tons sold. We review Segment Adjusted EBITDA Expense per ton for cost trends.

 EBITDA

 We define EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes and depreciation, depletion and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We believe that the presentation of EBITDA provides useful information to investors regarding our performance and results of operations because EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.

 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 and general and administrative expense. 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 – 2023 Compared with 2022

 Consolidated Information

 Total Revenues

 Total revenues increased 6.1% to a record $2.57 billion in 2023 compared to $2.42 billion in 2022 primarily due to higher coal sales revenues.

 Total operating expenses

 Total operating expenses increased to $1.89 billion in 2023 compared to $1.72 billion in 2022 due primarily to the sale of higher cost purchased coal and increased per ton costs on certain expense items discussed in more detail below.

 Increased revenues and lower income tax expense more than offset higher total operating expenses in 2023, resulting in record net income attributable to ARLP of $630.1 million, or $4.81 per basic and diluted limited partner unit for 2023, compared to $586.2 million, or $4.39 per basic and diluted limited partner unit, for 2022.

 Coal sales increased $108.0 million or 5.1% to $2.21 billion for 2023 from $2.10 billion for 2022. The increase reflects the benefit of higher average coal sales prices, which contributed $175.7 million in additional coal sales, partially offset by lower tons sold, which reduced coal sales by $67.7 million. Higher price realizations in domestic markets drove coal sales prices higher by 8.6% in 2023 to $64.17 per ton sold, compared to $59.07 per ton sold during 2022.

 Coal - Segment Adjusted EBITDA Expense

 Beginning in 2023, we redefined Coal - Segment Adjusted EBITDA Expense to reflect the activity of Alliance Coal, which is the holding company for our coal mining operations. We have retrospectively adjusted Coal - Segment Adjusted EBITDA Expense in prior periods to be on the same basis.

 Segment Adjusted EBITDA Expense for our coal operations increased 8.8% to $1.39 billion, as a result of higher per ton costs. On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations increased 12.4% to $40.38 per ton sold in 2023 compared to $35.91 per ton in 2022, primarily due to certain cost increases, which are discussed below by category:

 Labor and benefit expenses per ton produced, excluding workers' compensation, increased 14.6% to $12.20 per ton in 2023 from $10.65 per ton in 2022. The increase of $1.55 per ton was primarily due to higher incentive benefits and direct labor costs at several mines.

 Material and supplies expenses per ton produced increased 2.6% to $14.02 per ton in 2023 from $13.67 per ton in 2022. The increase of $0.35 per ton produced primarily reflects increases of $0.13 per ton for safety related materials and supplies, $0.11 per ton for various preparation plant expenses and $0.09 per ton for ventilation related expenses, partially offset by a decrease of $0.12 per ton for environmental and reclamation expenses other than longwall subsidence.

 Maintenance expenses per ton produced increased 27.6% to $4.62 per ton in 2023 from $3.62 per ton in 2022. The increase of $1.00 per ton produced was primarily as a result of inflationary cost pressures.

 Production taxes and royalty expenses per ton incurred as a percentage of coal sales prices and volumes increased $0.64 per produced ton sold in 2023 compared to 2022 primarily as a result of higher price realizations and higher federal black lung excise tax as a result of the tax rate increasing effective October 1, 2022, partially offset by a favorable mix of tons sold mined in states without severance taxes.

 Outside coal purchases increased $36.0 million in 2023 as a result of increased sales from purchased coal to meet contractual commitments at our Mettiki longwall operation which experienced challenging geological conditions that delayed development of a new district. Purchased coal generally costs more on a per ton basis than our produced coal.

 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 Financial Measures."

 Oil & gas royalty revenues decreased to $137.8 million in 2023 compared to $151.1 million for 2022. The decrease of $13.3 million was primarily due to lower average sales price per BOE, which decreased by 29.4%, partially offset by higher BOE volumes.

 Other revenues principally comprised Matrix Design sales, Mt. Vernon transloading revenues, oil & gas lease bonus revenues, and other miscellaneous sales and revenue activities. Other revenues increased to $76.5 million in 2023 from $52.8 million in 2022. The increase of $23.7 million was primarily due to increased sales of mining technology products by our Matrix Design subsidiary.

 Income tax expense decreased to $8.3 million for 2023 compared to $54.0 million for 2022 primarily as a result of our recognition of a one-time non-cash income tax charge of $37.3 million during 2022 in connection with the Tax Election.

 Transportation revenues and expenses

 Transportation revenues and expenses were $142.3 million and $113.9 million for 2023 and 2022, respectively. The increase of $28.4 million was primarily attributable to increased average third-party transportation rates in 2023 and increased coal shipments for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.

 Our 2023 Segment Adjusted EBITDA decreased $20.4 million, or 2.0%, to $1.01 billion from 2022 Segment Adjusted EBITDA of $1.03 billion primarily as a result of higher operating expenses and outside coal purchases, partially offset by increased revenues.

 For a definition of Segment Adjusted EBITDA and related reconciliation to its comparable GAAP financial measure, please see below under "—Reconciliation of Non-GAAP Financial Measures."

 Segment Information

 2023

 2022 (1)

 Increase (Decrease)

 $

 514,118

 $

 420,684

 $

 93,434

 22.2

 %

 330,723

 426,402

 (95,679)

 (22.4)

 %

 121,508

 143,179

 (21,671)

 (15.1)

 %

 41,163

 38,809

 2,354

 6.1

 %

 Other, Corporate and Elimination (2)

 4,661

 3,495

 1,166

 33.4

 %

 Total Segment Adjusted EBITDA (3)

 $

 1,012,173

 $

 $

 (20,396)

 (2.0)

 %

 Coal - Tons sold

 24,724

 24,110

 2.5

 %

 9,718

 11,479

 (1,761)

 (15.3)

 %

 Total tons sold

 34,442

 35,589

 (1,147)

 (3.2)

 %

 $

 1,364,901

 $

 1,219,943

 $

 144,958

 11.9

 %

 845,309

 882,286

 (36,977)

 (4.2)

 %

 Total coal sales

 $

 2,210,210

 $

 2,102,229

 $

 107,981

 5.1

 %

 $

 10,505

 $

 6,822

 $

 3,683

 54.0

 %

 1,885

 1,481

 27.3

 %

 3,774

 3,837

 (63)

 (1.6)

 %

 (14)

 (25.0)

 %

 Other, Corporate and Elimination

 60,244

 40,622

 19,622

 48.3

 %

 Total other revenues

 $

 76,450

 $

 52,818

 $

 23,632

 44.7

 %

 Segment Adjusted EBITDA Expense

 $

 861,288

 $

 806,080

 $

 55,208

 6.8

 %

 516,471

 464,029

 52,442

 11.3

 %

 16,532

 15,395

 1,137

 7.4

 %

 24,451

 21,871

 2,580

 11.8

 %

 Other, Corporate and Elimination (2)

 (14,024)

 (23,497)

 9,473

 40.3

 %

 Total Segment Adjusted EBITDA Expense (3)

 $

 1,404,718

 $

 $

 120,840

 9.4

 %

 Volume - BOE (4)

 3,105

 2,405

 29.1

 %

 $

 $

 $

 (13,309)

 (8.8)

 %

 Volume - Tons sold (5)

 $

 20,186

 21,780

 $

 (1,594)

 (7.3)

 %

 Intercompany coal royalties

 65,572

 $

 60,624

 4,948

 8.2

 %

 (1)
 Recast for the JC Resources Acquisition. For more information, please read "Item 8. Financial Statements and Supplementary Data— Note 1 – Organization and Presentation."

 (2)
 Other, Corporate and Elimination includes the elimination of intercompany coal royalty revenues and expenses between our Coal Royalties Segment and our coal operations segments in addition to the expenses for the other miscellaneous activities included in this category.

 (3)
 For definitions of Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense and related reconciliations to their respective comparable GAAP financial measures, please see below under "— Reconciliation of Non-GAAP Financial Measures."

 (4)
 BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

 (5)
 Represents tons sold by our coal operations segments associated with coal reserves leased from our Coal Royalties Segment.

 Illinois Basin Coal Operations – Segment Adjusted EBITDA increased 22.2% to $514.1 million in 2023 from $420.7 million in 2022. The increase of $93.4 million was primarily attributable to higher coal sales, which increased 11.9% to $1.36 billion in 2023 from $1.22 billion in 2022, partially offset by increased operating expenses. The increase in coal sales reflects higher coal sales price per ton, which increased by 9.1% compared to 2022 reflecting increased domestic prices, and increased tons sold, which rose 2.5% in 2023 as a result of increased sales volumes at the Warrior, Hamilton and Gibson South mines. Segment Adjusted EBITDA Expense increased 6.8% to $861.3 million in 2023 from $806.1 million in 2022 primarily as a result of increased sales volumes and higher operating expenses per ton. Segment Adjusted EBITDA Expense per ton increased 4.2% or $1.41 per ton sold to $34.84 from $33.43 per ton sold in 2022 primarily as a result of inflationary pressures on numerous expense items, including labor-related expenses and maintenance costs, and increased sales-related expenses due to higher price realizations, partially offset by lower expenses at our Hamilton mine, that experienced an unexpected outage during 2022.

 Appalachia Coal Operations – Segment Adjusted EBITDA decreased 22.4% to $330.7 million for 2023 from $426.2 million in 2022. The decrease of $95.5 million was primarily attributable to increased operating expenses and lower coal sales volumes. Coal sales volumes decreased 15.3% compared to 2022 as a result of lower production across the region due to lock outages, customer plant maintenance, reduced operating units at MC Mining, challenging geologic conditions that delayed development of a new district at our Mettiki longwall operation and increased longwall move days at our Tunnel Ridge mine. Coal sales prices increased by 13.2% compared to 2022 primarily due to increased domestic price realizations in the region. Segment Adjusted EBITDA Expense increased 11.3% to $516.5 million in 2023 from $464.0 million in 2022 due to higher per ton operating expenses, partially offset by lower volumes. Segment Adjusted EBITDA Expense per ton increased 31.5% to $53.15 compared to $40.42 per ton sold in 2022, as a result of lower volumes previously discussed, purchased coal and inflationary pressures on certain expense items, most notably labor-related expenses and materials and maintenance costs, and increased sales-related expenses due to higher price realizations.

 Oil & Gas Royalties – Segment Adjusted EBITDA decreased to $121.5 million for 2023 from $143.2 million in 2022. The decrease of $21.7 million was primarily due to lower average sales price per BOE, which decreased 29.4% to $44.37 per BOE, partially offset by increased volumes in 2023, which increased by 29.1%. Higher BOE volumes during 2023 resulted from increased drilling and completion activities on our properties and additional volumes from oil & gas mineral interest acquisitions.

 Coal Royalties – Segment Adjusted EBITDA increased 6.1% to $41.2 million for 2023 from $38.8 million in 2022. The $2.4 million increase was a result of higher average royalty rates per ton, partially offset by reduced royalty tons sold.

 Analysis of Historical Results of Operations – 2022 Compared with 2021

 Consolidated Information

 Total Revenues

 Total revenues increased 53.2% to a record $2.42 billion in 2022 compared to $1.58 billion in 2021 primarily due to substantial increases in prices and volumes from coal operations and royalties and oil & gas royalties.

 Total operating expenses

 Total operating expenses increased to $1.75 billion in 2022 compared to $1.36 billion in 2021 due primarily to increased coal sales volumes and ongoing inflationary cost pressures.

 Higher revenues, partially offset by increased total operating expenses and income tax expense, led to significantly higher net income attributable to ARLP, which rose 220.7% to a record $586.2 million for 2022, or $4.39 per basic and diluted limited partner unit, compared to $182.8 million, or $1.36 per basic and diluted limited partner unit, for 2021.

 Coal sales increased $715.3 million or 51.6% to $2.10 billion for 2022 from $1.39 billion for 2021. The increase was attributable to a price variance of $572.6 million due to higher average coal sales prices and a volume variance of $142.7 million resulting from increased tons sold. Coal sales price realizations increased by 37.4% in 2022 to $59.07 per ton sold, compared to $42.98 per ton sold during 2021, due to favorable market conditions. Improved coal demand in both the domestic and export markets during 2022 drove coal sales volumes higher by 10.3% to 35.6 million tons sold compared to 32.3 million tons sold in 2021.

 Coal - Segment Adjusted EBITDA Expense

 Segment Adjusted EBITDA Expense for our coal operations increased 33.2% to $1.28 billion, as a result of higher coal sales volumes and inflationary cost pressures. On a per ton basis, Segment Adjusted EBITDA Expense for our coal operations increased 20.8% to $35.91 per ton sold in 2022 compared to $29.73 per ton in 2021, primarily due to certain cost increases, which are discussed below by category:

 Labor and benefit expenses per ton produced, excluding workers' compensation, increased 14.6% to $10.65 per ton in 2022 from $9.29 per ton in 2021. The increase of $1.36 per ton was primarily due to higher labor costs at several mines.

 Material and supplies expenses per ton produced increased 32.8% to $13.67 per ton in 2022 from $10.29 per ton in 2021. The increase of $3.38 per ton produced primarily reflects inflationary cost pressures including increases of $1.11 per ton for roof support, $0.47 per ton for ventilation related expenses, $0.43 per ton for power and fuel, $0.39 per ton for contract labor used in the mining process, $0.37 per ton for various preparation plant expenses and $0.26 per ton for environmental and reclamation expenses other than longwall subsidence.

 Maintenance expenses per ton produced increased 30.7% to $3.62 per ton in 2022 from $2.77 per ton in 2021. The increase of $0.85 per ton produced was primarily as a result of inflationary cost pressures.

 Production taxes and royalty expenses per ton incurred as a percentage of coal sales prices and volumes increased $0.68 per produced ton sold in 2022 compared to 2021 primarily as a result of higher price realizations, partially offset by a temporary decrease in the federal black lung excise tax, from January 1, 2022 to September 30, 2022, a favorable mix of tons sold mined in states with severance taxes and decreased excise taxes per ton resulting from a greater mix of export shipments.

 Oil & gas royalty revenues increased to $151.1 million in 2022 compared to $84.2 million for 2021. The increase of $66.9 million was primarily due to significantly higher sales price realizations per BOE and volumes in 2022.

 Other revenues principally comprised Matrix Design sales, Mt. Vernon transloading revenues and other miscellaneous sales and revenue activities. Other revenues increased to $52.8 million in 2022 from $38.5 million in 2021. The increase of $14.3 million was primarily due to increased sales of mining technology products by our Matrix Design subsidiary.

 Income tax expense increased to $54.0 million for 2022 compared to $0.4 million for 2021 as a result of Alliance Minerals' election during 2022 to be treated as a taxable entity for federal and state income tax purposes. We recognized a one-time non-cash income tax charge of $37.3 million and income tax expense of $17.5 million during 2022 related to Alliance Minerals. Please read "Item 8. Financial Statements and Supplementary Data—Note 7 – Income Taxes."

 Transportation revenues and expenses

 Transportation revenues and expenses were $113.9 million and $69.6 million for 2022 and 2021, respectively. The increase of $44.3 million was primarily attributable to increased average third-party transportation rates in 2022 and increased coal shipments for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.

 Our 2022 Segment Adjusted EBITDA increased $475.2 million, or 85.2%, to $1.03 billion from 2021 Segment Adjusted EBITDA of $557.4 million primarily as a result of increased revenues, partially offset by higher operating expenses.

 Segment Information

 2022 (1)

 2021 (1)

 Increase (Decrease)

 $

 420,684

 $

 265,292

 $

 155,392

 58.6

 %

 426,402

 172,601

 253,801

 147.0

 %

 143,179

 76,920

 66,259

 86.1

 %

 38,809

 33,202

 5,607

 16.9

 %

 Other, Corporate and Elimination (2)

 3,495

 9,383

 (5,888)

 (62.8)

 %

 Total Segment Adjusted EBITDA (3)

 $

 $

 557,398

 $

 475,171

 85.2

 %

 Coal - Tons sold

 24,110

 22,264

 1,846

 8.3

 %

 11,479

 10,004

 1,475

 14.7

 %

 Total tons sold

 35,589

 32,268

 3,321

 10.3

 %

 $

 1,219,943

 $

 873,930

 $

 346,013

 39.6

 %

 882,286

 512,993

 369,293

 72.0

 %

 Total coal sales

 $

 2,102,229

 $

 1,386,923

 $

 715,306

 51.6

 %

 $

 6,822

 $

 4,666

 $

 2,156

 46.2

 %

 1,481

 3,940

 (2,459)

 (62.4)

 %

 3,837

 2,256

 1,581

 70.1

 %

 (13)

 (18.8)

 %

 Other, Corporate and Elimination

 40,622

 27,586

 13,036

 47.3

 %

 Total other revenues

 $

 52,818

 $

 38,517

 $

 14,301

 37.1

 %

 Segment Adjusted EBITDA Expense

 $

 806,080

 $

 613,303

 $

 192,777

 31.4

 %

 464,029

 344,332

 119,697

 34.8

 %

 15,395

 11,051

 4,344

 39.3

 %

 21,871

 18,269

 3,602

 19.7

 %

 Other, Corporate and Elimination (2)

 (23,497)

 (33,198)

 9,701

 29.2

 %

 Total Segment Adjusted EBITDA Expense (3)

 $

 $

 953,757

 $

 330,121

 34.6

 %

 Volume - BOE (4)

 2,405

 1,877

 28.1

 %

 $

 $

 $

 66,877

 79.4

 %

 Volume - Tons sold (5)

 21,780

 20,247

 1,533

 7.6

 %

 Intercompany coal royalties

 $

 60,624

 $

 51,402

 $

 9,222

 17.9

 %

 (1)
 Recast for the JC Resources Acquisition. For more information, please read "Item 8. Financial Statements and Supplementary Data— Note 1 – Organization and Presentation."

 (2)
 Other, Corporate and Elimination includes the elimination of intercompany coal royalty revenues and expenses between our Coal Royalties Segment and our coal operations segments in addition to the expenses for the other miscellaneous activities included in this category.

 (3)
 For definitions of Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense and related reconciliations to their respective comparable GAAP financial measures, please see below under "—Reconciliation of Non-GAAP Financial Measures.'"

 (4)
 BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

 (5)
 Represents tons sold by our coal operations segments associated with coal reserves leased from our Coal Royalties Segment.

 Illinois Basin Coal Operations – Segment Adjusted EBITDA increased 58.6% to $420.7 million in 2022 from $265.3 million in 2021. The increase of $155.4 million was primarily attributable to higher coal sales, which increased 39.6% to $1.22 billion in 2022 from $873.9 million in 2021, partially offset by increased operating expenses. The increase in coal sales reflects higher coal sales price per ton, which increased by 28.9% compared to 2021 due to increased domestic prices and significantly higher export prices and increased tons sold, which rose 8.3% in 2022 as a result of increased sales volumes primarily at our Gibson South mine. Segment Adjusted EBITDA Expense increased 31.4% to $806.1 million in 2022 from $613.3 million in 2021 primarily as a result of increased sales volumes and higher expenses per ton. Segment Adjusted EBITDA Expense per ton increased 21.3% or $5.88 per ton sold to $33.43 from $27.55 per ton sold in 2021 primarily as a result of inflationary pressures on numerous expense items, including labor-related expenses and supply and maintenance costs, increased sales-related expenses due to higher price realizations, reduced recoveries across the region and lost production due to an unexpected outage caused by a thermal event which lasted approximately four weeks in addition to increased longwall move days at our Hamilton mine during 2022. There were no injuries and no damages to equipment as a result of the thermal event at Hamilton, and mining operations returned to normal production levels in December 2022.

 Appalachia Coal Operations – Segment Adjusted EBITDA increased 147.0% to $426.4 million for 2022 from $172.6 million in 2021. The increase of $253.8 million was primarily attributable to higher coal sales, which increased 72.0% to $882.3 million in 2022 from $513.0 million in 2021, due to increased prices and volumes. Coal sales prices increased by 49.9% compared to 2021 primarily due to substantially higher export price realizations and increased domestic pricing in the region. Coal sales volumes increased 14.7% compared to 2021 as a result of higher sales volumes from our Tunnel Ridge and MC Mining operations. Segment Adjusted EBITDA Expense increased 34.8% to $464.0 million in 2022 from $344.3 million in 2021 due to increased sales volumes and per ton expenses. Segment Adjusted EBITDA Expense per ton increased 17.4% to $40.42 compared to $34.42 per ton sold in 2021, as a result of inflationary pressures on numerous expense items, including labor-related expenses and supply and maintenance costs, increased sales-related expenses due to higher price realizations, reduced recoveries at our Mettiki and MC Mining operations and increased longwall move days at our Tunnel Ridge and Mettiki mines during 2022.

 Oil & Gas Royalties – Segment Adjusted EBITDA increased to $143.2 million for 2022 from $76.9 million in 2021. The increase of $66.3 million was primarily due to higher sales price realizations, which increased 40.1% to $62.83 per BOE, and increased volumes in 2022. Volumes increased by 28.1% to 2.4 million BOE sold in 2022 compared to 1.9 million BOE sold in 2021 as a result of increased drilling and completion activities and additional volumes from oil & gas mineral interest acquisitions completed during 2022.

 Coal Royalties – Segment Adjusted EBITDA increased 16.9% to $38.8 million for 2022 from $33.2 million in 2021. The increase of $5.6 million was a result of increased royalty tons sold and higher average royalty rates per ton.

 Reconciliation of Non-GAAP Financial Measures

 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 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 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.

 The following is a reconciliation of net income, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA:

 2023

 2022

 2021

 $

 $

 $

 Noncontrolling interest

 (6,052)

 (1,958)

 (598)

 $

 $

 $

 General and administrative

 79,096

 80,425

 70,275

 267,982

 276,670

 264,794

 Interest expense, net

 26,697

 35,296

 39,141

 8,280

 Consolidated Segment Adjusted EBITDA

 $

 1,012,173

 $

 $

 557,398

 Segment Adjusted EBITDA Expense (a non-GAAP financial measure) includes operating expenses, coal purchases and other expense (income). 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 operating expenses, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA Expense:

 2023

 2022

 2021

 Operating expenses (excluding depreciation, depletion and amortization)

 $

 1,368,787

 $

 1,288,082

 $

 944,419

 Outside coal purchases

 36,149

 6,372

 Other expense (income)

 (218)

 (4,355)

 2,966

 Segment Adjusted EBITDA Expense

 $

 1,404,718

 $

 $

 953,757

 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 1 – Organization and Presentation" and "—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, contractual obligations 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, contractual obligations, commitments and distribution payments. Nevertheless, our ability to satisfy our working capital requirements and additional investments, to satisfy our contractual obligations, 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. 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 being 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."

 Oil & Gas Acquisitions

 During 2023, through the JC Resources and Skyland Acquisitions and other ground game acquisitions we acquired approximately 6,443 oil & gas net royalty acres in the Anadarko, Williston and Delaware Basins for an aggregate purchase price of $110.9 million. We funded these acquisitions with cash on hand. For additional information about our acquisitions of oil & gas assets, please see "Business — Oil & Gas Acquisitions."

 During 2023, we invested $49.6 million in Infinitum and Ascend with cash on hand. These investments are aligned with our strategy of furthering the development of energy and related infrastructure and investing in attractive opportunities that leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation. Also, as of December 31, 2023, we have funded $6.6 million of a $25 million commitment in NGP ET IV with cash on hand. For additional information about our energy and infrastructure investments, please see "Business — Growth Investments and Opportunities."

 Unit Repurchase Program

 In January 2023, the Board of Directors authorized a $93.5 million increase to the unit repurchase program. As a result, we were authorized to repurchase up to a total of $100.0 million of ARLP's limited partner common units. During the year ended December 31, 2023, we repurchased and retired 929,842 units at an average price of $20.90 for an aggregate purchase price of $19.4 million, leaving $80.6 million authorized. 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.

 Revolving Credit Facility

 On January 13, 2023, Alliance Coal entered into the Credit Agreement with various financial institutions. The Credit Agreement provides for a $425 million revolving credit facility, which includes a sublimit of $15.0 million for swingline

 borrowings and permits the issuance of letters of credit of up to the full amount of $425 million, and for a term loan in an aggregate principal amount of $75 million. The Credit Agreement matures on March 9, 2027, at which time the aggregate outstanding principal amount of all Revolving Credit Facility advances and all Term Loan advances are required to be repaid in full. The Credit Agreement will instead mature on January 30, 2025, if on that date our Senior Notes are still outstanding and Alliance Coal does not have liquidity of at least $200 million. Interest is payable quarterly, with principal of the Term Loan due in quarterly installments equal to 6.25% of the original principal amount beginning with the quarter ending June 30, 2023 and the balance payable at maturity. The Credit Agreement is guaranteed by ARLP and certain of its subsidiaries, including the Intermediate Partnership and most of the direct and indirect subsidiaries of Alliance Coal. The Credit Agreement also is secured by substantially all of the assets of the Subsidiary Guarantors and Alliance Coal. For additional information on the Credit Agreement, please see "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt".

 Securitization Facility

 In January 2024, we extended the term of our Securitization Facility to January 2025 and increased the borrowing availability under the facility to $90.0 million. For additional information on the Securitization Facility please read "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt".

 Mine Development Project

 In 2022, we began development of the Henderson County mine which continued through 2023 and into 2024. We have deployed capital of $69.3 million through 2023 and currently anticipate deploying capital of approximately $36.5 million in 2024 to complete the project. We have funded our capital expenditures and expect to fund our remaining capital expenditures for the project with cash from operations or borrowings under our credit facilities. We anticipate the new mine will enable us to access an additional 109.5 million clean recoverable tons of coal.

 Cash Flows

 Cash provided by operating activities was $830.6 million for 2023 compared to $802.3 million for 2022. The increase in cash provided by operating activities was primarily due to increases in net income adjusted for non-cash items and favorable working capital changes primarily related to trade receivables. These increases were partially offset by unfavorable working capital changes primarily related to inventories, as well as miscellaneous other changes.

 Net cash used in investing activities was $559.7 million for 2023 compared to $403.3 million for 2022. The increase in cash used in investing activities was primarily attributable to increases in capital expenditures, acquisitions of oil & gas reserves including the JC Resources and Skyland Acquisitions, and changes in accounts payable and accrued liabilities. These increases were partially offset by payments for the Belvedere and Jase Acquisitions, and contributions to equity method investments in 2022. See "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions" for more information on the Belvedere, Jase, JC Resources and Skyland Acquisitions.

 Net cash used in financing activities was $507.1 million for 2023 compared to $225.4 million for 2022. The increase in cash used in financing activities was primarily attributable to increased cash distributions paid to unitholders, increased net payments on long-term debt, purchases of units under our unit repurchase program, debt issuance costs, and payments for purchase of units and tax withholdings related to settlements under deferred compensation plans.

 Cash Requirements

 We currently estimate our 2024 annual cash requirements, including capital expenditures, scheduled payments on long-term debt, lease obligations, asset retirement obligation costs and workers' compensation and pneumoconiosis, to be in a range of $728.0 million to $778.0 million. Management anticipates having sufficient cash flow to meet 2024 cash requirements with our December 31, 2023 cash and cash equivalents of $59.8 million and cash flows from operations, or borrowings under revolving credit and securitization facilities or other sources of financing that we expect to have available if necessary. We currently project average estimated annual maintenance capital expenditures over the next five years of approximately $7.76 per ton produced. For additional information on our future cash requirements other than capital expenditures, please see "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt," "—Note 8 – Leases," "—Note 15 – Employee Benefit Plans," "—Note 18 – Asset Retirement Obligations," "—Note 19 – Accrued Workers' Compensation and Pneumoconiosis Benefits" and "—Note 21 – Commitments and Contingencies." We will

 continue to have significant cash 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.

 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, 2023:

 Workers'

 Reclamation

 Obligation

 Obligation

 Other

 Total

 Surety bonds

 $

 173.5

 $

 58.4

 $

 15.0

 $

 246.9

 Letters of credit

 —

 41.0

 16.8

 57.8

 Insurance

 Effective October 1, 2023, we renewed our property and casualty insurance program through September 30, 2024. 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 $25.0 million overall aggregate deductible. We retained a 7.25% participating interest in our current 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

 See "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt" for a discussion of our debt obligations.

 Critical Accounting Policies and Estimates

 Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on 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 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

 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 Belvedere, Jase and Skyland 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, if any, 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 Belvedere, Jase and Skyland Acquisitions, we determined a fair value for the acquired mineral interests using an income approach consisting of discounted cash flow models. The assumptions used in the discounted cash flow models included estimated production, projected cash flows, forward oil & gas prices and risk adjusted discount rates.

 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:

 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.

 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 19 – Accrued Workers' Compensation and Pneumoconiosis Benefits" for additional discussion. We had accrued liabilities for workers' compensation of $48.0 million and $49.5 million for these costs at December 31, 2023 and 2022, respectively. A one-percentage-point reduction in the discount rate would have increased operating expense by approximately $2.4 million at December 31, 2023. 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, 2023 and 2022 were $4.1 million.

 Coal mining companies are subject to FMSHA 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 $132.4 million and $104.3 million for the pneumoconiosis benefits at December 31, 2023 and 2022, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2023 by approximately $1.4 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 on 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.

 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 $150.4 million and $149.8 million for these costs are recorded at December 31, 2023 and 2022, respectively. See "Item 8. Financial Statements and Supplementary Data—Note 18 – 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.

 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 $1.5 million for the year ended December 31, 2023. Adjustments to the liability associated with these assumptions resulted in an increase of $17.4 million for the year ended December 31, 2022.

 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 $116.2 million and $110.4 million at December 31, 2023 and 2022. We estimate that the aggregate undiscounted cost of final mine closure is approximately $266.6 million and $260.2 million at December 31, 2023 and 2022, 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 2022, we filed with the SEC a universal shelf registration statement which allows us to issue from time to time an indeterminate amount of debt or equity securities. As of February 23, 2024, we had not issued any debt or equity under the 2022 Registration Statement.

 Related – Party Transactions

 See "Item 8. Financial Statements and Supplementary Data—Note 20 – 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 $398.4 million and $395.3 million at December 31, 2023 and 2022, 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 18 – Asset Retirement Obligations" and "—Note 19 – Accrued Workers' Compensation and Pneumoconiosis Benefits."

 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 93.4% of our sales tonnage being sold under long-term sales contracts in 2023. Many 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 Supplementary Data—Note 22 – Concentration of Credit Risk and Major Customers." Our initial 2024 guidance includes 32.5 million priced and committed tons for delivery in 2024.

 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. Also, a significant decline in oil & gas prices would have a significant impact on our oil & gas royalty revenues.

 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 2023, approximately 80.9% of our tons sold were purchased by U.S. electric utilities and 15.7% 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. 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 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt" for more information on our Securitization Facility.

 Exchange Rate Risk

 The vast majority 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, Term Loan 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 $60.9 million in borrowings under Term Loan at December 31, 2023. We did not have any outstanding borrowings on either the Revolving Credit Facility or the Securitization Facility at December 31, 2023. A one percentage point increase in the interest rates related to the Term Loan would result in an annualized increase in interest expense of $0.6 million, based on borrowing levels at December 31, 2023. With respect to our fixed-rate borrowings, we had $284.6 million in borrowings under our Senior Notes and $2.0 million in borrowings under our equipment financings at December 31, 2023. A one percentage point increase in interest rates would result in a decrease of approximately $3.7 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 on our incremental borrowing rates for similar types of borrowing arrangements as of December 31, 2023 and 2022.

 The carrying amounts and fair values of financial instruments are as follows:

 Fair Value

 Expected Maturity Dates

 as of December 31, 2023

 2024

 2025

 2026

 2027

 2028

 Total

 2023

 (dollars in thousands)

 Fixed rate debt

 $

 2,039

 $

 284,607

 $

 —

 $

 —

 $

 —

 $

 286,646

 $

 286,179

 Weighted-average interest rate

 7.50

 %

 7.50

 %

 —

 %

 —

 %

 —

 %

 Variable rate debt

 $

 18,750

 $

 18,750

 $

 18,750

 $

 4,688

 $

 —

 $

 60,938

 $

 60,938

 Weighted-average interest rate (1)

 8.50

 %

 8.50

 %

 8.50

 %

 8.50

 %

 —

 Fair Value

 Expected Maturity Dates

 as of December 31, 2022

 2023

 2024

 2025

 2026

 2027

 Total

 2022

 (dollars in thousands)

 Fixed rate debt

 $

 24,970

 $

 2,039

 $

 400,000

 $

 —

 $

 —

 $

 427,009

 $

 424,420

 Weighted-average interest rate

 7.40

 %

 7.50

 %

 7.50

 %

 —

 %

 —

 %

 (1)
 Interest rate of variable rate debt equal to the rate effective at December 31, 2023, held constant for the remaining term of the outstanding borrowing.

 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 Page

 Report of Independent Registered Public Accounting Firm-Grant Thornton LLP (PCAOB ID Number 248)

 Consolidated Balance Sheets

 Consolidated Statements of Income

 Consolidated Statements of Comprehensive Income

 Consolidated Statements of Cash Flows

 Consolidated Statement of Partners' Capital

 1. Organization and Presentation

 2. Summary of Significant Accounting Policies

 3. Acquisitions

 4. Inventories

 5. Property, Plant and Equipment

 6. Long-Term Debt

 7. Income Taxes

 8. Leases

 9. Fair Value Measurements

 10. Partners' Capital

 11. Variable Interest Entities

 12. Equity Investments

 13. Revenue From Contracts With Customers

 14. Earnings Per Limited Partner Unit

 15. Employee Benefit Plans

 16. Common Unit-Based Compensation Plans

 17. Supplemental Cash Flow Information

 18. Asset Retirement Obligations

 19. Accrued Workers' Compensation and Pneumoconiosis Benefits

 20. Related-Party Transactions

 21. Commitments and Contingencies

 22. Concentration of Credit Risk and Major Customers

 23. Segment Information

 Supplemental Oil & Gas Reserve Information (Unaudited)

 Schedule I – Condensed Financial Information of Registrant

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 Board of Directors of Alliance Resource Management GP, LLC and
 Unitholders 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. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, cash flows and partners' capital for each of the three years in the period ended December 31, 2023, and the related notes and financial statement schedule included under Item 15(a)(2) (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America.

 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, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and our report dated February 23, 2024 expressed an unqualified opinion.

 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 matter
 The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates 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 financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

 Valuation of workers' compensation and pneumoconiosis benefit obligations

 As described further in Note 19 to the financial statements, the Partnership provides income replacement and medical treatment for work-related traumatic injury claims and compensation to survivors of workers who suffer employment-related deaths. The Partnership is also liable to pay benefits for black lung disease (or pneumoconiosis) to eligible employees and former employees and their dependents. As of December 31, 2023, the Partnership's aggregate workers' compensation and pneumoconiosis benefit obligations were approximately $180 million. We identified valuation of workers' compensation and pneumoconiosis benefit obligations as a critical audit matter.

 The principal considerations for our determination that the valuation of workers' compensation and pneumoconiosis benefit obligations is a critical audit matter are the high level of estimation uncertainty related to determining the frequency and severity of these types of claims, as well as the inherent subjectivity in management's judgment in estimating eligible benefits and the total cost to settle or dispose of these claims. Workers' compensation and pneumoconiosis benefit obligations are determined using actuarial projection methods and numerous assumptions including claim development

 patterns, costs, and mortality. The estimates rely on the assumption that historical claim patterns are an accurate representation for future claims.

 Our audit procedures related to the valuation of workers' compensation and pneumoconiosis benefit obligations included the following, among others.

 We tested the design and operating effectiveness of controls relating to the workers' compensation and pneumoconiosis benefit obligations process including testing controls over management's review of actuarial specialists' liability calculations and the completeness and accuracy of the underlying data.

 We tested management's process for determining the worker's compensation and pneumoconiosis benefit obligation accruals, including evaluating the reasonableness of the methods and significant assumptions used in the calculations with the assistance of actuarial specialists.

 We tested the claims data used in the actuarial calculations by inspecting source documents to test key attributes of the claims data.

 We compared claim development patterns and cost assumptions used in the actuarial calculations for consistency with historical experience and current trends.

 We compared the mortality tables used in the actuarial calculations to publicly available information.

 /s/ GRANT THORNTON LLP

 We have served as the Partnership's auditor since 2021.

 Tulsa, Oklahoma

 CONSOLIDATED BALANCE SHEETS
 DECEMBER 31, 2023 AND 2022
 (In thousands, except unit data)

 2023

 2022*

 ASSETS

 CURRENT ASSETS:

 Cash and cash equivalents

 $

 59,813

 $

 296,023

 Trade receivables

 282,622

 241,412

 Other receivables

 9,678

 8,601

 Inventories, net

 127,556

 77,326

 Advance royalties

 7,780

 7,556

 Prepaid expenses and other assets

 28,672

 26,675

 Total current assets

 516,121

 657,593

 PROPERTY, PLANT AND EQUIPMENT:

 Property, plant and equipment, at cost

 4,172,544

 3,931,422

 Less accumulated depreciation, depletion and amortization

 ( 2,149,881)

 ( 2,050,754)

 Total property, plant and equipment, net

 2,022,663

 1,880,668

 OTHER ASSETS:

 Advance royalties

 71,125

 67,713

 Equity method investments

 46,503

 49,371

 Equity securities

 92,541

 42,000

 Operating lease right-of-use assets

 16,569

 14,950

 Other long-term assets

 22,904

 15,726

 Total other assets

 249,642

 189,760

 TOTAL ASSETS

 $

 2,788,426

 $

 2,728,021

 LIABILITIES AND PARTNERS' CAPITAL

 CURRENT LIABILITIES:

 Accounts payable

 $

 108,269

 $

 95,122

 Accrued taxes other than income taxes

 21,007

 22,967

 Accrued payroll and related expenses

 29,884

 39,623

 Accrued interest

 3,558

 5,000

 Workers' compensation and pneumoconiosis benefits

 15,913

 14,099

 Other current liabilities

 28,498

 53,790

 Current maturities, long-term debt, net

 20,338

 24,970

 Total current liabilities

 227,467

 255,571

 LONG-TERM LIABILITIES:

 Long-term debt, excluding current maturities, net

 316,821

 397,203

 Pneumoconiosis benefits

 127,249

 100,089

 Accrued pension benefit

 8,618

 12,553

 Workers' compensation

 37,257

 39,551

 Asset retirement obligations

 146,925

 142,254

 Long-term operating lease obligations

 13,661

 12,132

 Deferred income tax liabilities

 33,450

 35,814

 Other liabilities

 18,381

 24,828

 Total long-term liabilities

 702,362

 764,424

 Total liabilities

 929,829

 1,019,995

 COMMITMENTS AND CONTINGENCIES - (Note 21)

 PARTNERS' CAPITAL:

 ARLP Partners' Capital:

 Limited Partners - Common Unitholders 127,125,437 and 127,195,219 units outstanding, respectively

 1,896,027

 1,656,025

 General Partner's interest

 —

 66,548

 Accumulated other comprehensive loss

 ( 61,525)

 ( 41,054)

 Total ARLP Partners' Capital

 1,834,502

 1,681,519

 Noncontrolling interest

 24,095

 26,507

 Total Partners' Capital

 1,858,597

 1,708,026

 TOTAL LIABILITIES AND PARTNERS' CAPITAL

 $

 2,788,426

 $

 2,728,021

 CONSOLIDATED STATEMENTS OF INCOME
 (In thousands, except unit and per unit data)

 c

 2023

 2022*

 2021*

 SALES AND OPERATING REVENUES:

 $

 2,210,210

 $

 2,102,229

 $

 1,386,923

 Transportation revenues

 142,290

 113,860

 69,607

 76,450

 52,818

 38,517

 Total revenues

 2,566,701

 2,419,967

 1,579,230

 EXPENSES:

 Operating expenses (excluding depreciation, depletion and amortization)

 1,368,787

 1,288,082

 944,419

 Transportation expenses

 142,290

 113,860

 69,607

 Outside coal purchases

 36,149

 6,372

 General and administrative

 79,096

 80,425

 70,275

 267,982

 276,670

 264,794

 Settlement gain

 —

 ( 6,664)

 —

 Total operating expenses

 1,894,304

 1,752,524

 1,355,467

 INCOME FROM OPERATIONS

 672,397

 667,443

 223,763

 Interest expense (net of interest capitalized of $ 6,706, $ 922 and $ 396, respectively)

 ( 36,091)

 ( 37,331)

 ( 39,229)

 Interest income

 9,394

 2,035

 Equity method investment income (loss)

 ( 1,468)

 5,634

 2,130

 Other income (expense)

 4,355

 ( 2,966)

 INCOME BEFORE INCOME TAXES

 644,450

 642,136

 183,786

 INCOME TAX EXPENSE

 8,280

 NET INCOME

 LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST

 ( 6,052)

 ( 1,958)

 ( 598)

 NET INCOME ATTRIBUTABLE TO ARLP

 $

 $

 $

 NET INCOME ATTRIBUTABLE TO ARLP

 GENERAL PARTNER

 $

 1,384

 $

 9,010

 $

 4,614

 LIMITED PARTNERS

 $

 628,734

 $

 577,190

 $

 178,157

 EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED

 $

 4.81

 $

 4.39

 $

 1.36

 WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED

 127,180,312

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 (In thousands)

 2023

 2022*

 2021*

 NET INCOME

 $

 $

 $

 OTHER COMPREHENSIVE INCOME (LOSS):

 Defined benefit pension plan

 Amortization of prior service cost (1)

 Net actuarial gain

 2,894

 10,148

 14,921

 Amortization of net actuarial loss (1)

 1,963

 4,327

 Total defined benefit pension plan adjustments

 3,762

 12,297

 19,434

 Pneumoconiosis benefits

 Net actuarial gain (loss)

 ( 25,615)

 9,840

 ( 161)

 Amortization of net actuarial loss (1)

 1,382

 1,038

 4,172

 Total pneumoconiosis benefits adjustments

 ( 24,233)

 10,878

 4,011

 OTHER COMPREHENSIVE INCOME (LOSS)

 ( 20,471)

 23,175

 23,445

 COMPREHENSIVE INCOME

 615,699

 611,333

 206,814

 Less: Comprehensive income attributable to noncontrolling interest

 ( 6,052)

 ( 1,958)

 ( 598)

 COMPREHENSIVE INCOME ATTRIBUTABLE TO ARLP

 $

 609,647

 $

 609,375

 $

 206,216

 (1)
 Amortization of prior service cost and actuarial gain or loss is included in the computation of net periodic benefit cost (see Notes 15 and 19 for additional details).

 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (In thousands)

 2023

 2022*

 2021*

 CASH FLOWS FROM OPERATING ACTIVITIES:

 $

 $

 $

 Adjustments to reconcile net income to net cash provided by operating activities:

 267,982

 276,670

 264,794

 Non-cash compensation expense

 12,864

 11,029

 5,709

 Coal inventory adjustment to market

 33,296

 Equity method investment loss (income)

 1,468

 ( 5,634)

 ( 2,130)

 Distributions from equity method investments

 2,567

 5,634

 2,130

 Net gain on sale of property, plant and equipment

 ( 3,230)

 ( 3,665)

 ( 6,592)

 Change in deferred income tax

 ( 8,973)

 34,775

 Other

 11,259

 5,313

 3,900

 Changes in operating assets and liabilities:

 Trade receivables

 ( 41,210)

 ( 108,893)

 ( 25,931)

 Other receivables

 ( 1,077)

 ( 7,921)

 3,109

 Inventories, net

 ( 78,004)

 ( 20,138)

 ( 4,673)

 Prepaid expenses and other assets

 ( 2,940)

 ( 9,179)

 Advance royalties

 ( 3,636)

 ( 6,787)

 ( 7,523)

 Accounts payable

 17,842

 14,580

 19,481

 Accrued taxes other than income taxes

 ( 1,960)

 5,180

 ( 7,267)

 Accrued payroll and related benefits

 ( 9,739)

 2,818

 8,281

 Pneumoconiosis benefits

 3,924

 3,849

 6,832

 Workers' compensation

 ( 1,477)

 ( 3,996)

 ( 1,292)

 Other

 ( 4,484)

 20,192

 ( 10,654)

 Total net adjustments

 194,472

 214,191

 248,804

 Net cash provided by operating activities

 830,642

 802,349

 432,173

 CASH FLOWS FROM INVESTING ACTIVITIES:

 Property, plant and equipment:

 Capital expenditures

 ( 379,338)

 ( 286,394)

 ( 122,984)

 Change in accounts payable and accrued liabilities

 ( 29,695)

 35,956

 2,594

 Proceeds from sale of property, plant and equipment

 3,710

 7,468

 7,719

 Contributions to equity method investments

 ( 2,518)

 ( 24,087)

 —

 Purchase of equity securities

 ( 49,560)

 ( 42,000)

 —

 JC Resources acquisition

 ( 64,999)

 —

 —

 Oil & gas reserve business combinations

 ( 14,459)

 ( 92,618)

 —

 Oil & gas reserve asset acquisitions

 ( 24,225)

 —

 ( 30,960)

 Other

 1,351

 ( 1,663)

 Net cash used in investing activities

 ( 559,733)

 ( 403,338)

 ( 142,688)

 CASH FLOWS FROM FINANCING ACTIVITIES:

 Borrowings under securitization facility

 —

 27,500

 35,000

 Payments under securitization facility

 —

 ( 27,500)

 ( 90,900)

 Payments on equipment financings

 ( 24,970)

 ( 16,071)

 ( 17,299)

 Borrowings under revolving credit facilities

 —

 —

 15,000

 Payments under revolving credit facilities

 —

 —

 ( 102,500)

 Borrowings from line of credit

 —

 —

 5,340

 Payment on line of credit

 —

 —

 ( 5,340)

 Borrowing under long-term debt

 75,000

 —

 —

 Payments on long-term debt

 ( 129,455)

 —

 —

 Payment of debt issuance costs

 ( 12,376)

 —

 ( 113)

 Payments for purchases of units under unit repurchase program

 ( 19,432)

 —

 —

 Payments for tax withholdings related to settlements under deferred compensation plans

 ( 10,334)

 —

 ( 1,090)

 Excess purchase price over the contributed basis from JC Resources acquisition

 ( 7,251)

 —

 —

 Cash retained by JC Resources in acquisition

 ( 2,933)

 ( 10,537)

 ( 6,971)

 Distributions paid to Partners

 ( 364,579)

 ( 196,347)

 ( 52,158)

 Other

 ( 10,789)

 ( 2,436)

 ( 1,625)

 Net cash used in financing activities

 ( 507,119)

 ( 225,391)

 ( 222,656)

 NET CHANGE IN CASH AND CASH EQUIVALENTS

 ( 236,210)

 173,620

 66,829

 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 296,023

 122,403

 55,574

 CASH AND CASH EQUIVALENTS AT END OF PERIOD

 $

 59,813

 $

 296,023

 $

 122,403

 CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
 (In thousands, except unit data)

 Number of

 Accumulated

 Limited

 Limited

 General

 Other

 Partner

 Partners'

 Partner's

 Comprehensive

 Noncontrolling

 Total Partners'

 Units

 Capital

 Capital *

 Income (Loss)

 Interest

 Capital *

 Balance at January 1, 2021

 $

 1,148,565

 $

 70,432

 $

 ( 87,674)

 $

 11,376

 $

 1,142,699

 Comprehensive income:

 —

 178,157

 4,614

 —

 Actuarially determined long-term liability adjustments

 —

 —

 —

 23,445

 —

 23,445

 Total comprehensive income

 206,814

 Settlement of deferred common unit- based compensation plans

 —

 ( 1,090)

 —

 —

 —

 ( 1,090)

 Common unit-based compensation

 —

 5,709

 —

 —

 —

 5,709

 Distributions on deferred common unit-based compensation

 —

 ( 1,280)

 —

 —

 —

 ( 1,280)

 Distributions from consolidated company to noncontrolling interest

 —

 —

 —

 —

 ( 859)

 ( 859)

 Cash retained by JC Resources in acquisition - See Note 1

 —

 —

 ( 6,971)

 —

 —

 ( 6,971)

 Distributions to Partners

 —

 ( 50,878)

 —

 —

 —

 ( 50,878)

 Balance at December 31, 2021

 1,279,183

 68,075

 ( 64,229)

 11,115

 1,294,144

 Comprehensive income:

 —

 577,190

 9,010

 —

 1,958

 Actuarially determined long-term liability adjustments

 —

 —

 —

 23,175

 —

 23,175

 Total comprehensive income

 611,333

 Common unit-based compensation

 —

 11,029

 —

 —

 —

 11,029

 Distributions on deferred common unit-based compensation

 —

 ( 5,553)

 —

 —

 —

 ( 5,553)

 Distributions from consolidated company to noncontrolling interest

 —

 —

 —

 —

 ( 1,596)

 ( 1,596)

 Profits interest adjustment for noncontrolling interest

 —

 ( 15,030)

 —

 —

 15,030

 —

 Cash retained by JC Resources in acquisition - See Note 1

 —

 —

 ( 10,537)

 —

 —

 ( 10,537)

 Distributions to Partners

 —

 ( 190,794)

 —

 —

 —

 ( 190,794)

 Balance at December 31, 2022

 1,656,025

 66,548

 ( 41,054)

 26,507

 1,708,026

 Comprehensive income:

 —

 628,734

 1,384

 —

 6,052

 Actuarially determined long-term liability adjustments

 —

 —

 —

 ( 20,471)

 —

 ( 20,471)

 Total comprehensive income

 615,699

 Settlement of deferred common unit- based compensation plans

 860,060

 ( 10,334)

 —

 —

 —

 ( 10,334)

 Purchase of units under unit repurchase program

 ( 929,842)

 ( 19,432)

 —

 —

 —

 ( 19,432)

 Common unit-based compensation

 —

 12,864

 —

 —

 —

 12,864

 Distributions on deferred common unit-based compensation

 —

 ( 8,530)

 —

 —

 —

 ( 8,530)

 Distributions from consolidated company to noncontrolling interest

 —

 —

 —

 —

 ( 8,464)

 ( 8,464)

 JC Resources acquisition - See Note 1

 —

 ( 7,251)

 ( 64,999)

 —

 —

 ( 72,250)

 Cash retained by JC Resources in acquisition - See Note 1

 —

 —

 ( 2,933)

 —

 —

 ( 2,933)

 Distributions to Partners

 —

 ( 356,049)

 —

 —

 —

 ( 356,049)

 Balance at December 31, 2023

 127,125,437

 $

 1,896,027

 $

 —

 $

 ( 61,525)

 $

 24,095

 $

 1,858,597

 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 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 "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, an indirect wholly owned subsidiary of ARLP.

 References to "Alliance Minerals" mean Alliance Minerals, LLC, an indirect wholly owned subsidiary of ARLP.

 References to "Alliance Resource Properties" mean Alliance Resource Properties, LLC, an indirect wholly owned subsidiary of ARLP.

 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. Alliance GP, LLC ("AGP"), which is indirectly wholly owned by Mr. Craft, is the direct owner of MGP.

 Oil & Gas Acquisitions

 Boulders

 On October 13, 2021, we acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders Royalty Corp. ("Boulders") for a purchase price of $ 31.0 million (the "Boulders Acquisition").

 Belvedere

 On September 9, 2022, we acquired approximately 394 oil & gas net royalty acres in the Delaware Basin from Belvedere Operating, LLC ("Belvedere") for a purchase price of $ 11.4 million (the "Belvedere Acquisition").

 Jase

 On October 26, 2022, we acquired approximately 3,928 oil & gas net royalty acres in the Midland and Delaware Basins from Jase Minerals, LP ("Jase") for a purchase price of $ 81.2 million (the "Jase Acquisition").

 JC Resources

 On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources LP ("JC Resources"), an entity owned by Mr. Craft, for $ 72.3 million, which was funded with cash on hand ("JC Resources Acquisition"). Because JC Resources is owned by Mr. Craft, the JC Resources Acquisition is accounted for as a reorganization of entities under common control, whereby the assets and liabilities acquired from JC Resources are combined with the ARLP Partnership at their historical amounts for all periods presented. Recasting for the JC Resources Acquisition increased revenues by $ 13.5 million and $ 9.3 million for the years ended December 31, 2022 and

 2021, respectively, and increased income from operations, net income and comprehensive income by $ 9.0 million and $ 4.6 million for the years ended December 31, 2022 and 2021, respectively. We did not recast historical earnings per limited partner unit as pre-acquisition earnings from the JC Resources Acquisition were allocated to our general partner.

 Skyland

 On December 7, 2023, we acquired approximately 2,372 oil & gas net royalty acres in the Anadarko, Williston and Delaware Basins from Skyland Minerals, L.P. ("Skyland") and Haymaker Minerals & Royalties II, LLC ("Haymaker") for a purchase price of $ 14.5 million which was funded with cash on hand ("Skyland Acquisition").

 The Boulders, Belvedere, Jase, JC Resources and Skyland Acquisitions enhanced our ownership position in various basins and furthered our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions. See Note 3 – Acquisitions for more information. We now hold approximately 67,700 net royalty acres in premier oil & gas resource plays including previous acquisitions and our investment in AllDale Minerals III, LP ("AllDale III").

 On April 5, 2022, we invested $ 20 million in Francis Renewable Energy, LLC ("Francis"), in the form of a convertible note. Our convertible note matured on April 1, 2023 and was converted into a preferred equity interest in Francis. Francis currently is active in the installation, management and operation of metered-for-fee, public-access electric vehicle ("EV") charging stations. Francis also develops and constructs EV charging stations for third-party customers. For more information on this investment, please see Note 11 – Variable Interest Entities.

 Infinitum

 During 2022, we purchased $ 42.0 million of Series D Preferred Stock in Infinitum Electric, Inc. ("Infinitum"), a Texas-based startup developer and manufacturer of electric motors featuring printed circuit board stators which have the potential to result in motors that are smaller, lighter, quieter, more efficient and capable of operating at a fraction of the carbon footprint of conventional electric motors. On September 8, 2023, we purchased $ 24.6 million of Series E Preferred Stock ("Series E Preferred Stock" and, together with the "Series D Preferred Stock," the "Infinitum Preferred Stock") in Infinitum. The Infinitum Preferred Stock provides for non-cumulative dividends when and if declared by Infinitum's board of directors. Each share of Infinitum Preferred Stock is convertible, at any time, at our option, into shares of common stock of Infinitum. For more information on this investment, please see Note 12 – Equity Investments.

 NGP ET IV

 On June 2, 2022, we committed to purchase $ 25.0 million of limited partner interests in NGP Energy Transition, L.P. ("NGP ET IV"), a private equity fund sponsored by NGP Energy Capital Management, LLC ("NGP"). NGP ET IV focuses on investments that are part of the global transition toward a lower carbon economy by partnering with top-tier management teams and investing growth equity in companies that drive or enable the growth of renewable energy, the electrification of our economy or the efficient use of energy. For more information on this investment, please see Note 11 – Variable Interest Entities.

 Ascend

 On August 22, 2023, we purchased $ 25.0 million of Series D Preferred Stock (the "Ascend Preferred Stock") in Ascend Elements, Inc. ("Ascend"), a U.S.-based manufacturer and recycler of sustainable, engineered battery materials for electric vehicles. The Ascend Preferred Stock provides for non-cumulative dividends when and if declared by Ascend's board of directors. Each share is convertible, at any time, at our option, into shares of common stock of Ascend. For more information on this investment please see Note 12 – Equity Investments.

 The Francis, Infinitum, NGP ET IV and Ascend investments further our business strategy to pursue opportunities that support the advancement of energy and related infrastructure and leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation.

 Change in Tax Status

 On March 15, 2022, Alliance Minerals changed its federal income tax status from a pass-through entity to a taxable entity via a "check the box" election (the "Tax Election"), which became effective January 1, 2022. This election for Alliance Minerals reduced the total income tax burden on our oil & gas royalties, as Alliance Minerals now pays entity-level taxes at corporate tax rates which are favorable to our unitholders. For more information on the Tax Election please see Note 7 – Income Taxes.

 Presentation

 The consolidated financial statements include the accounts and operations of the ARLP Partnership and present our financial position as of December 31, 2023 and 2022, 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, 2023. All of our intercompany transactions and accounts have been eliminated.

 2.

 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 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.

 Business Combinations

 A business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. We account for the acquisition of a business as a business combination, where 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. However, if substantially all the fair value of the assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets with the same risk profile, the acquisition is accounted for as an asset acquisition and recorded at cost.

 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:

 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

 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 on 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 on 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. At times the ARLP Partnership maintains deposits in federally insured financial institutions in excess of stated federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. Based on this monitoring and other diligence, including discussions with representatives of the financial institutions, we have no reason to believe that any of the financial institutions in which we have deposits in excess of stated federally insured limits are facing financial difficulties, defaults or limited liquidity situations that would cause us to be unable to access our deposits.

 Cash Management

 The cash flows from operating activities section of our consolidated statements of cash flows reflects an adjustment for $ 6.7 million representing book overdrafts at December 31, 2023. We did not have material book overdrafts at December 31, 2022 and 2021.

 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.

 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:

 2023

 2022

 Advance royalties, affiliates (see Note 20 – Related-Party Transactions)

 $

 64,599

 $

 60,608

 Advance royalties, third-parties

 14,306

 14,661

 Total advance royalties

 $

 78,905

 $

 75,269

 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. Processing facilities and mineral rights, assuming current production estimates, are depreciated or depleted using the units-of-production method. Mining equipment and other plant and equipment assets are depreciated principally using the straight-line method over the remaining estimated life of each mine. Buildings, office equipment and improvements are amortized straight line over their estimated useful lives. 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 coal mineral reserves. Therefore, our coal mineral rights are depleted based on only proven and probable coal mineral 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 coal mineral reserves. Mine development costs represent costs incurred in establishing access to coal 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.

 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 the Operators' existing wells with existing equipment, infrastructure and operating methods.

 We evaluate impairment of our oil & gas 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 oil & gas mineral interests in unproved properties are also assessed for impairment periodically but at least annually when facts and circumstances indicate that the unproved property will not be transferred to proved properties. 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 if we determine that the unproved property will not be transferred to proved properties. 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.

 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.

 Equity 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 account for our ownership interests in Infinitum and Ascend as equity securities without readily determinable fair values. See Note 12 – Equity Investments for further discussion of these investments.

 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.

 In the event our ownership requires a disproportionate sharing of income or loss, we use the hypothetical liquidation at book value ("HLBV") method to determine the appropriate allocation of income or loss. Under the HLBV method, income or loss of the investee is allocated based on hypothetical amounts that each investor would be entitled to receive if the net assets held were liquidated at book value at the end of each period, adjusted for any contributions made and distributions received during the period.

 We hold equity method investments in AllDale III, Francis and NGP ET IV. See Note 11 – Variable Interest Entities and Note 12 – Equity Investments for further discussion of our equity method investments.

 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.

 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 1 to 19 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 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.

 Common Unit-Based Compensation

 We maintain the Long-Term Incentive Plan ("LTIP") for certain key employees and executive officers. Pursuant to 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. Certain awards may also contain a minimum-value guarantee payable in ARLP common units or cash that would be paid regardless of whether or not the awards vest, as long as service requirements are met. Annual grant levels, vesting provisions and minimum-value guarantees of restricted units for designated participants are recommended by Mr. Craft, subject to review and approval by the compensation committee of our general partner ("Compensation Committee"). The vesting of all restricted units is subject to the satisfaction of certain financial tests. If it is not probable that the financial tests will be achieved for a particular grant of restricted units, 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, restricted units issued to LTIP participants generally cliff vest on January 1st of the third year following the issuance of such restricted units. We expect to settle restricted unit grants by issuing ARLP common units, except for the portion of the restricted units that will satisfy our tax withholding obligations. We account for forfeitures of non-vested restricted unit grants as they occur. As provided under the distribution equivalent rights ("DERs") provisions of the LTIP and the terms of the restricted unit awards, all currently outstanding 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 a 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 have utilized the Supplemental Executive Retirement Plan ("SERP") to provide deferred compensation benefits for certain executive officers. All allocations made to participants under the SERP have been made in the form of "phantom" ARLP units. We intend to settle any distributions from the SERP in the form of ARLP common units. The SERP has been 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. We intend to settle any distributions from the Directors' Deferred Compensation Plan 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 and recorded as compensation expense. All grants of phantom units under the SERP and Directors' Deferred Compensation Plan vest immediately.

 On December 14, 2023, the Compensation Committee and the Board of Directors approved the termination of the SERP and Directors' Deferred Compensation Plan, and authorized distribution of accounts on December 15, 2024 or as soon thereafter as practical. The accounts will continue to accrue benefits in accordance with plan terms until distributed.

 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.

 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.

 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.

 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.

 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.

 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. 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 anticipated timing 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 renewed on an annual basis.

 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 on prevailing market prices 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. 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.

 Income Taxes

 We are not a taxable entity for federal or state income tax purposes; the tax effect of our activities accrues to our unitholders. Although publicly traded partnerships as a general rule are 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.

 Our subsidiary Alliance Minerals within our Oil & Gas Royalties segment and certain other subsidiaries within our Other, Corporate and Elimination category are subject to federal and state income taxes. We use the liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (ii) operating losses and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax status or a change in tax rates on deferred tax assets and liabilities is recognized in the period the change in status is elected or rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

 New Accounting Standards Issued and Not Yet Adopted

 In November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"). ASU 2023-07 primarily requires enhanced disclosures about significant segment expenses regularly provided to the chief operating decision maker ("CODM"), the amount and composition of other segment items, and the title and position of the CODM. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-07, but do not expect it to have a material effect on our consolidated financial statements.

 In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income

 (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.

 3. ACQUISITIONS

 Boulders

 On October 13, 2021, we acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders for a purchase price of $ 31.0 million, which was funded with cash on hand. This acquisition gives us increased exposure to a prolific area of the Delaware Basin and is within close proximity to reserves acquired in previous acquisitions. The acreage acquired in the Boulders Acquisition was mostly undeveloped. Because more than 90% of the mineral interests acquired in the acquisition represent undeveloped properties with a similar risk profile, including proved undeveloped, we have determined that the Boulders Acquisition should be accounted for as an asset acquisition.

 The following table summarizes the purchase price allocation of the assets acquired in the Boulders Acquisition:

 Mineral interests in proved properties

 $

 12,542

 Mineral interests in unproved properties

 18,418

 $

 30,960

 Belvedere

 On September 9, 2022 (the "Belvedere Acquisition Date"), we acquired approximately 394 oil & gas net royalty acres in the Delaware Basin from Belvedere for a cash purchase price of $ 11.4 million, which was funded with cash on hand. This acquisition gives us additional exposure to a productive area of the Delaware Basin and is within close proximity to reserves that we currently own. Because the mineral interests acquired in the Belvedere Acquisition include royalty interests in both developed properties and undeveloped properties with different risk profiles, 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 Belvedere Acquisition Date on our consolidated balance sheet.

 The following table summarizes the fair value allocation of assets acquired as of the Belvedere Acquisition Date:

 Mineral interests in proved properties

 $

 7,724

 Mineral interests in unproved properties

 3,667

 $

 11,391

 The fair value of the mineral interests was determined using an income approach consisting 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 risk adjusted discount rates. Certain assumptions used are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.

 The amounts of revenue and earnings from the mineral interests acquired in the Belvedere Acquisition included in our consolidated statements of income from the Belvedere Acquisition Date through December 31, 2022 are as follows:

 2022

 Revenue

 $

 The following represents our supplemental pro forma consolidated revenues and net income for the years ended December 31, 2022 and 2021 as if the mineral interests acquired in the Belvedere Acquisition had been included in our consolidated results since January 1, 2021. These amounts have been calculated after applying our accounting policies.

 2022

 2021

 (unaudited)

 Revenues

 $

 2,420,824

 $

 1,580,373

 588,916

 184,361

 Jase

 On October 26, 2022 (the "Jase Acquisition Date"), we acquired approximately 3,928 oil & gas net royalty acres in the Midland and Delaware Basins from Jase for a cash purchase price of $ 81.2 million which was funded with cash on hand. This acquisition further enhanced our ownership position in the Permian Basin. Because the mineral interests acquired in the Jase Acquisition include royalty interests in both developed properties and undeveloped properties with different risk profiles, 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 Jase Acquisition Date on our consolidated balance sheet.

 The following table summarizes the fair value allocation of assets acquired as of the Jase Acquisition Date:

 Mineral interests in proved properties

 $

 35,918

 Mineral interests in unproved properties

 43,740

 Receivables

 1,569

 Net assets acquired

 $

 81,227

 The fair value of the mineral interests was determined using an income approach consisting 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 risk adjusted discount rates. The fair value of the receivables was determined using estimated production during the period between the Jase Acquisition Date and the effective date of the agreement and observable sales prices during the period. Certain assumptions used are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.

 The amounts of revenue and earnings from the mineral interests acquired in the Jase Acquisition included in our consolidated statements of income from the Jase Acquisition Date through December 31, 2022 are as follows:

 2022

 Revenue

 $

 1,689

 The following represents our supplemental pro forma consolidated revenues and net income for the years ended December 31, 2022 and 2021 as if the mineral interests acquired in the Jase Acquisition had been included in our consolidated results since January 1, 2021. These amounts have been calculated after applying our accounting policies.

 2022

 2021

 (unaudited)

 Revenues

 $

 2,430,734

 $

 1,588,914

 596,759

 190,765

 JC Resources

 On February 22, 2023, we completed the JC Resources Acquisition, which gives us increased exposure to a prolific area of the Delaware Basin that is within close proximity to reserves that we currently own. This acquisition was approved by the conflicts committee of MGP's board of directors, which is comprised entirely of independent directors. Because JC Resources is under common control with us, we recorded the acquisition at JC Resources' carrying value for each period presented. The carrying value of the mineral interests as well as related receivables and payables at February 22, 2023 was $ 65.0 million inclusive of $ 25.4 million and $ 37.8 million of mineral interests in proved and unproved properties, respectively. The JC Resources Acquisition increased revenues included in our consolidated statements of income by $ 10.6 million for the year ended December 31, 2023.

 Acquisition Agreement

 On January 27, 2023, we entered into a one-year collaborative agreement with a third party, effective January 1, 2023, committing up to $ 35.0 million for the acquisition of oil & gas mineral interests in the Midland and Delaware Basins. Under the agreement, the third party assists us in the identification, evaluation, and acquisition of target oil & gas mineral interests. In exchange for these services, the third party receives a participation share, partially funded by the third party, and is paid a periodic management fee. As of December 31, 2023, we have purchased $ 6.5 million and $ 6.7 million of oil & gas mineral interests in proved and unproved properties, respectively, pursuant to this agreement. Management fees paid under this agreement have been immaterial. On February 19, 2024, we renewed this agreement for an additional one-year term, committing up to $ 25.0 million.

 Skyland Acquisition

 On December 7, 2023 (the "Skyland Acquisition Date"), we acquired approximately 2,372 oil & gas net royalty acres in the Anadarko, Williston and Delaware Basins from Skyland and Haymaker for a cash purchase price of $ 14.5 million which was funded with cash on hand. This acquisition further enhanced our ownership position in these basins. Because the mineral interests acquired in the Skyland Acquisition include royalty interests in both developed properties and undeveloped properties with different risk profiles, 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 Skyland Acquisition Date on our consolidated balance sheet.

 The following table summarizes the fair value allocation of assets acquired as of the Skyland Acquisition Date:

 Mineral interests in proved properties

 $

 8,694

 Mineral interests in unproved properties

 5,765

 Net assets acquired

 $

 14,459

 The fair value of the mineral interests was determined using an income approach consisting 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 risk adjusted discount rates. Certain assumptions used are not observable in active markets; therefore, the fair value measurements represent Level 3 fair value measurements.

 The amounts of revenue and earnings from the mineral interests acquired in the Skyland Acquisition included in our consolidated statements of income from the Skyland Acquisition Date through December 31, 2023 are immaterial.

 The following represents our supplemental pro forma consolidated revenues and net income for the years ended December 31, 2023 and 2022 as if the mineral interests acquired in the Skyland Acquisition had been included in our consolidated results since January 1, 2022. These amounts have been calculated after applying our accounting policies.

 2023

 2022

 (unaudited)

 Revenues

 $

 2,568,516

 $

 2,423,313

 637,757

 591,140

 Miscellaneous Acquisitions

 In addition to the acquisitions discussed above, we purchased $ 6.8 million and $ 4.3 million of oil & gas mineral interests in proved and unproved properties, respectively, during the year ended December 31, 2023 and $ 1.3 million and $ 0.4 million in proved and unproved properties, respectively, during the year ended December 31, 2022.

 4.

 INVENTORIES

 Inventories consist of the following:

 2023

 2022

 Coal

 $

 56,549

 $

 23,553

 Supplies (net of reserve for obsolescence of $ 8,167 and $ 6,601, respectively)

 71,007

 53,773

 Total inventories, net

 $

 127,556

 $

 77,326

 The table above includes lower of cost or net realizable value adjustments of $ 33.3 million. These adjustments are a result of lower coal sale prices and higher cost per ton primarily due to the impact of Mettiki's longwall being idle most of the second half of 2023 due to delayed development of a new longwall district, Hamilton experiencing disruptions in production due to a longwall move, and continuing development of the Henderson County mine at our River View complex.

 5. PROPERTY, PLANT AND EQUIPMENT

 Property, plant and equipment consist of the following:

 2023

 2022

 Mining equipment and processing facilities

 $

 1,989,541

 $

 1,927,603

 Land and coal mineral rights

 504,736

 499,950

 Oil & gas mineral interests

 853,350

 814,667

 Buildings, office equipment, improvements and other miscellaneous equipment

 310,876

 300,436

 Construction, mine development and other projects in progress

 184,895

 99,042

 Mine development costs

 329,146

 289,724

 Property, plant and equipment, at cost

 4,172,544

 3,931,422

 Less accumulated depreciation, depletion and amortization

 ( 2,149,881)

 ( 2,050,754)

 Total property, plant and equipment, net

 $

 2,022,663

 $

 1,880,668

 All of our property, plant and equipment have depreciable lives of 1 to 20 years. Depreciation, depletion and amortization expense related to property, plant and equipment was $ 276.4 million, $ 273.8 million and $ 260.3 million for the years ended December 31, 2023, 2022 and 2021, respectively.

 At December 31, 2023 and 2022, land and coal mineral rights above include $ 13.4 million and $ 29.9 million, respectively, of carrying value associated with coal mineral reserves and resources attributable to properties where we or a third party to which we lease coal mineral reserves and resources are not currently engaged in mining operations or leasing to third parties, and therefore, the coal mineral reserves are not currently being depleted. We believe that the carrying value of these coal mineral reserves will be recovered.

 At December 31, 2023 and 2022, our oil & gas mineral interests noted in the table above include the carrying value of our unproved oil & gas mineral interests totaling $ 411.6 million and $ 422.7 million, respectively. 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 2023, we incurred $ 44.4 million in mine development costs, primarily related to Tunnel Ridge and the Henderson County mine at River View Coal, LLC ("River View"). During 2022, we incurred $ 11.3 million in mine development costs, primarily related to Hamilton and River View mine. 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.

 6. LONG-TERM DEBT

 Long-term debt consists of the following:

 Unamortized Discount and

 Principal

 Debt Issuance Costs

 2023

 2022

 2023

 2022

 Revolving credit facility

 $

 —

 $

 —

 $

 ( 8,118)

 $

 ( 2,702)

 Term loan

 60,938

 —

 ( 1,416)

 —

 Senior notes

 284,607

 400,000

 ( 891)

 ( 2,134)

 Securitization facility

 —

 —

 —

 —

 November 2019 equipment financing

 —

 21,072

 —

 —

 June 2020 equipment financing

 2,039

 5,937

 —

 —

 347,584

 427,009

 ( 10,425)

 ( 4,836)

 Less current maturities

 ( 20,789)

 ( 24,970)

 —

 Total long-term debt

 $

 326,795

 $

 402,039

 $

 ( 9,974)

 $

 ( 4,836)

 Credit Facility

 On January 13, 2023, Alliance Coal, as borrower, entered into a Credit Agreement (the "Credit Agreement") with various financial institutions. The Credit Agreement provides for a $ 425 million revolving credit facility, which includes a sublimit of $ 15.0 million for swingline borrowings and permits the issuance of letters of credit up to the full amount of $ 425 million (the "Revolving Credit Facility"), and for a term loan in an aggregate principal amount of $ 75 million (the "Term Loan"). The Credit Agreement matures on March 9, 2027, at which time the aggregate outstanding principal amount of all Revolving Credit Facility advances and all Term Loan advances are required to be repaid in full. The Credit Agreement will instead mature on January 30, 2025, if on that date our Senior Notes, as discussed below, are still outstanding and Alliance Coal does not have liquidity of at least $ 200 million. Interest is payable quarterly, with principal of the Term Loan due in quarterly installments equal to 6.25 % of the original principal amount of the Term Loan beginning with the quarter ending June 30, 2023 and the balance payable at maturity. The Revolving Credit Facility replaces the $ 459.5 million revolving credit facility extended to the Intermediate Partnership under its Fifth Amended and Restated Credit Agreement, dated as of March 9, 2020. We incurred debt issuance costs during the year ended December 31, 2023 of $ 12.4 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 Revolving Credit Facility is underwritten by a syndicate of eighteen financial institutions and the obligations of the lenders are individual obligations, which means the failure of one or more lenders to be able to fund its obligation does not relieve the remaining lenders from funding their obligations. Based on our diligence, including discussions with representatives of certain of these financial institutions, as of December 31, 2023 we have no reason to believe that the banks within our syndicate are facing financial difficulties, defaults or limited liquidity situations that would cause them to be unable to fund their obligations under the Credit Agreement. However, should any of the banks in our syndicate experience conditions in the future that limit their ability to fund their obligations, the amount available under the Revolving Credit Facility could be reduced.

 The Credit Agreement is guaranteed by ARLP and certain of its subsidiaries, including the Intermediate Partnership and most of the direct and indirect subsidiaries of Alliance Coal (the "Subsidiary Guarantors"). The Credit Agreement also is secured by substantially all of the assets of the Subsidiary Guarantors and Alliance Coal. Borrowings under the Credit Agreement bear interest, at our option, at either (i) an adjusted one-month, three-month or six-month term rate based on the secured overnight financing rate published by the Federal Reserve Bank of New York, plus the applicable margin or (ii) the base rate plus the applicable margin. The base rate is the highest of (i) the Overnight Bank Funding Rate plus 0.50 %, (ii) the Administrative Agent's prime rate, and (iii) the Daily Simple Secured Overnight Financing Rate plus 100 basis points. The applicable margin for borrowings under the Credit Agreement are determined by reference to the Consolidated Debt to Consolidated Cash Flow Ratio. For borrowings under the Term Loan, we elected the three-month term rate, with applicable margin, which was 8.50 % as of December 31, 2023. At December 31, 2023, we had $ 41.0 million of letters of credit outstanding with $ 384.0 million available for borrowing under the Revolving Credit Facility. We incurred an annual

 commitment fee of 0.50 % on the undrawn portion of the Revolving Credit Facility. We utilize the Credit Agreement, as appropriate, for working capital requirements, capital expenditures and investments, scheduled debt payments and distribution payments.

 The Credit Agreement contains various restrictions affecting Alliance Coal and its subsidiaries, including, among other things, restrictions on incurrence of additional indebtedness and liens, sale of assets, investments, mergers and consolidations and transactions with affiliates. In each case, these restrictions are subject to various exceptions. In addition, restrictions apply to cash distributions by Alliance Coal to the Intermediate Partnership if such distribution would result in exceeding a minimum fixed charge coverage ratio (as determined in the Credit Agreement) or in Alliance Coal having liquidity of less than $ 200 million. The Credit Agreement requires us to maintain (a) a debt of Alliance Coal to cash flow ratio of not more than 1.5 to 1.0, (b) a consolidated debt of Alliance Coal and the Intermediate Partnership to cash flow ratio of not more than 2.5 to 1.0 and (c) an interest coverage ratio of not less than 3.0 to 1.0, in each case, during the four most recently ended fiscal quarters. The debt of Alliance Coal to cash flow ratio, consolidated debt of Alliance Coal and the Intermediate Partnership to cash flow ratio, and interest coverage ratio were 0.08 to 1.0, 0.46 to 1.0 and 63.86 to 1.0, respectively, for the trailing twelve months ended December 31, 2023. We were in compliance with the covenants of the Credit Agreement as of December 31, 2023 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 Facility and its associated compliance ratios, the amount of our net restricted assets at December 31, 2023 was $ 797.2 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 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. During the year ended December 31, 2023, we repurchased or redeemed $ 115.4 million of our Senior Notes. The gain on extinguishment of the Senior Notes is immaterial.

 Accounts Receivable Securitization

 Certain direct and indirect wholly owned subsidiaries of our Intermediate Partnership were party to a $ 60.0 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 $ 60.0 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 short-term bank yield index. On December 31, 2023, we had $ 11.7 million of letters of credit outstanding with $ 48.3 million available for borrowing under the Securitization Facility. The agreement governing the Securitization Facility contains customary terms and conditions, including limitations with regards to certain customer credit ratings. In January 2024, we extended the term of the Securitization Facility to January 2025 and increased the borrowing availability under the facility to $ 90.0 million. The Securitization Facility was previously scheduled to mature in January 2024. At December 31, 2023, we did no t have any outstanding borrowings under the Securitization Facility.

 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 contained customary terms and events of default and an implicit interest rate of 4.75 % and matured on November 6, 2023. Upon maturity, the equipment reverted 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 month ly payments with an implicit interest rate of 6.1 %, maturing on June 5, 2024. Upon maturity, the equipment will revert 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, 2023, we had $ 5.0 million in letters of credit outstanding under this agreement.

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

 2024

 $

 20,789

 2025

 303,357

 2026

 18,750

 2027

 4,688

 $

 347,584

 7. INCOME TAXES

 Components of income tax expense are as follows:

 2023

 2022

 2021

 Current:

 Federal

 $

 15,917

 $

 17,572

 $

 ( 1)

 State

 1,336

 1,605

 17,253

 19,177

 Deferred:

 Federal

 ( 7,235)

 33,038

 State

 ( 1,738)

 1,763

 ( 8)

 ( 8,973)

 34,801

 $

 8,280

 $

 $

 Alliance Minerals' Tax Election resulted in the recognition of an initial deferred tax liability of $ 37.3 million with a corresponding increase to income tax expense and reduction of net income for the year ended December 31, 2022. This reduction of net income equates to approximately $ 0.29 per basic and diluted limited partner unit. Recognition of the initial deferred tax liability and expense is primarily the result of the $ 177.0 million non-cash acquisition gain recognized in 2019 related to the acquisition of the remaining interests in AllDale Minerals LP ("AllDale I") and AllDale Minerals II, LP ("AllDale II", and collectively with AllDale I, "AllDale I & II") (the "Acquisition Gain"). The Acquisition Gain was

 recognized to step up to fair value the financial reporting basis of the interests we already owned at the time of acquisition. The tax basis of the underlying properties of AllDale I & II did not include the Acquisition Gain.

 Reconciliations of income taxes at the U.S. federal statutory tax rate to income taxes at our effective tax rate are as follows:

 2023

 2022

 2021

 Income taxes at statutory rate

 $

 135,335

 $

 134,849

 $

 38,595

 Less: Income taxes at statutory rate on Partnership income not subject to income taxes

 ( 119,556)

 ( 113,925)

 ( 37,546)

 Increase (decrease) resulting from:

 State taxes, net of federal income tax

 1,492

 Change in valuation allowance of deferred tax assets

 —

 ( 317)

 ( 834)

 Deferred taxes related to tax election

 —

 37,253

 —

 Tax effect of noncontrolling interest income not subject to income taxes

 ( 1,361)

 ( 5,399)

 —

 Return to accrual adjustments

 ( 7,008)

 ( 1)

 Other

 ( 44)

 ( 72)

 $

 8,280

 $

 $

 The effective income tax rates for our income tax expense for the year ended December 31, 2023 and 2021 are less than the federal statutory rate, primarily due to the portion of income not subject to income taxes. The effective income tax rate for our income tax expense for the year ended December 31, 2022 is less than the federal statutory rate, primarily due to the portion of income not subject to income taxes, partially offset by the effect of the Tax Election previously discussed.

 Significant components of deferred tax liabilities and deferred tax assets are as follows:

 2023

 2022

 Deferred tax liabilities:

 Property, plant and equipment

 $

 ( 36,453)

 $

 ( 38,349)

 Total deferred tax liabilities

 ( 36,453)

 ( 38,349)

 Deferred tax assets:

 Federal loss carryovers and credits

 4,508

 2,139

 State loss carryovers and credits

 2,126

 Capitalized research and development

 2,567

 —

 Other

 1,098

 Total deferred tax assets

 10,299

 3,223

 Overall net deferred tax liabilities

 $

 ( 26,154)

 $

 ( 35,126)

 Deferred tax liabilities for property, plant and equipment are primarily the result of the Alliance Minerals' Tax Election and associated impact of the Acquisition Gain discussed above.

 Federal and state loss carryovers and credits are primarily due to net operating losses and research and development credits associated with the operations of other subsidiaries that are taxable for federal income tax purposes.

 Research and development expenses are required to be capitalized and amortized for U.S. tax purposes, resulting in a deferred tax asset. These expenses are primarily associated with the operations of other subsidiaries that are taxable for federal income tax purposes.

 Our 2020 through 2022 tax years remain open to examination by tax authorities, and lower-tier partnership income tax returns for the tax years ended December 31, 2020 and 2021 are being audited by the Internal Revenue Service.

 8. LEASES

 The components of lease expense were as follows:

 2023

 2022

 2021

 Finance lease cost:

 Amortization of right-of-use assets

 $

 $

 $

 Interest on lease liabilities

 Operating lease cost

 3,572

 2,884

 2,404

 Short-term lease cost

 —

 —

 Variable lease cost

 1,680

 1,665

 1,306

 Total lease cost

 $

 5,375

 $

 5,219

 $

 4,654

 Rental expense was $ 5.7 million, $ 5.1 million and $ 3.3 million for the years ended December 31, 2023, 2022 and 2021 respectively.

 Supplemental cash flow information related to leases was as follows:

 2023

 2022

 2021

 Cash paid for amounts included in the measurement of lease liabilities:

 Operating cash flows for operating leases

 $

 3,720

 $

 2,880

 $

 2,367

 Operating cash flows for finance leases

 $

 $

 $

 Financing cash flows for finance leases

 $

 $

 $

 Right-of-use assets obtained in exchange for lease obligations:

 Operating leases

 $

 2,596

 $

 1,315

 $

 Supplemental balance sheet information related to leases was as follows:

 2023

 2022

 Finance leases:

 Property and equipment finance lease assets, gross

 $

 1,085

 $

 5,485

 Accumulated depreciation

 ( 507)

 ( 5,061)

 Property and equipment finance lease assets, net

 $

 $

 2023

 2022

 Weighted average remaining lease term

 Operating leases

 11.7 years

 13.4 years

 Finance leases

 4.0 years

 5.0 years

 Weighted average discount rate

 Operating leases

 6.0 %

 6.0 %

 Finance leases

 4.8 %

 4.8 %

 Maturities of lease liabilities as of December 31, 2023 were as follows:

 Operating leases

 Finance leases

 2024

 $

 3,437

 $

 2025

 2,403

 2026

 1,923

 2027

 1,930

 2028

 1,646

 —

 Thereafter

 12,122

 —

 Total lease payments

 23,461

 Less imputed interest

 ( 6,869)

 ( 55)

 Total

 $

 16,592

 $

 The current portion of our operating and finance lease obligations are included in Other current liabilities line item in our consolidated balance sheets. The long-term portion of our finance lease obligation is included in the Other liabilities line item in our consolidated balance sheets.

 9. FAIR VALUE MEASUREMENTS

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

 December 31, 2022

 Level 1

 Level 2

 Level 3

 Level 1

 Level 2

 Level 3

 Long-term debt

 $

 —

 $

 347,116

 $

 —

 $

 —

 $

 424,420

 $

 —

 The carrying amounts for cash equivalents, accounts receivable, accounts payable, accrued and other liabilities, 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 6 – Long-Term Debt for additional information on our long-term debt.

 10. 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 2021 through 2023:

 2023

 2022

 2021

 First Quarter

 $

 0.700

 $

 0.250

 $

 —

 Second Quarter

 $

 0.700

 $

 0.350

 $

 0.100

 Third Quarter

 $

 0.700

 $

 0.400

 $

 0.100

 Fourth Quarter

 $

 0.700

 $

 0.500

 $

 0.200

 On January 26, 2024, we declared a quarterly distribution of $ 0.70 per unit, totaling approximately $ 89.0 million, on all our common units outstanding, which was paid on February 14, 2024 to all unitholders of record on February 7, 2024.

 Unit Repurchase Program

 In January 2023, the board of directors of MGP authorized a $ 93.5 million increase to the unit repurchase program, which had $ 6.5 million of available capacity as of December 31, 2022. As a result, we were authorized to repurchase up to a total of $ 100.0 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. During the year ended December 31, 2023, we repurchased and retired 929,842 units at an average unit price of $ 20.90 for an aggregate purchase price of $ 19.4 million, leaving $ 80.6 million remaining under the current authorization. Since inception of the unit repurchase program, we have repurchased and retired 6,390,446 units at an average unit price of $ 17.67 for an aggregate purchase price of $ 112.9 million.

 Other

 The noncontrolling interest in our consolidated balance sheets represents Bluegrass Minerals Management, LLC's ("Bluegrass Minerals") ownership interest in Cavalier Minerals JV, LLC ("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 11 – Variable Interest Entities, Note 15 – Employee Benefit Plans and Note 19 – Accrued Workers' Compensation and Pneumoconiosis Benefits for further information.

 11. VARIABLE INTEREST ENTITIES

 AllDale I & II and Cavalier Minerals

 We own the general partner interests and, including the limited partner interests we hold through our ownership in Cavalier Minerals, approximately 97 % of the limited partner interests in AllDale I & II. As the general partner of AllDale I & II, we are entitled to receive 20.0 % of all distributions from AllDale I & II with the remaining 80.0 % allocated to limited partners based upon ownership percentages.

 Cavalier Minerals owns approximately 72 % of the limited partner interests in AllDale I & II. We own the managing member interest and a 96 % member interest in Cavalier Minerals. 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. All members have recovered their investment and Bluegrass Minerals began receiving its profits interest distributions in late 2022.

 We have concluded that AllDale I, AllDale II and Cavalier Minerals are VIEs which we consolidate as the primary beneficiary because we have the power to direct the activities that most significantly impact the economic performance of AllDale I, AllDale II and Cavalier Minerals in addition to having substantial equity ownership.

 Our share of Cavalier Minerals' investment in AllDale I & II is eliminated in consolidation and Bluegrass Minerals' investment in Cavalier Minerals is accounted for as noncontrolling ownership interest in our consolidated balance sheets. Additionally, earnings attributable to Bluegrass Minerals are recognized as noncontrolling interest in our consolidated statements of income.

 The following table presents the carrying amounts and classification of AllDale I & II's assets and liabilities included in our consolidated balance sheets:

 2023

 2022

 Assets (liabilities):

 Cash and cash equivalents

 $

 4,690

 $

 4,698

 Trade receivables

 16,058

 13,933

 Total property, plant and equipment, net

 389,767

 406,135

 Accounts payable

 ( 175)

 ( 257)

 Due to affiliates

 —

 ( 24)

 Accrued taxes other than income taxes

 ( 958)

 ( 206)

 AllDale III

 AllDale III owns oil & gas mineral interests in areas around the oil & gas mineral interests we own. Alliance Minerals owns a 13.9 % limited partner interest in AllDale III. Alliance Minerals' investment in AllDale III is subject to a 25 % profits interest for the general partner that is 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.

 We have concluded that AllDale III is a VIE that we do not consolidate because we are not the primary beneficiary and 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 are not the primary beneficiary of AllDale III because we do not have the power to direct the activities that most significantly impact AllDale III's economic performance. See Note 12 – Equity Investments for more information about the accounting for our investment in AllDale III.

 On April 5, 2022, we invested $ 20 million in Francis, in the form of a convertible note. Our convertible note matured on April 1, 2023 and was converted into a preferred equity interest in Francis. Prior to conversion, we had determined the note more closely represented equity as opposed to debt. Therefore, we accounted for the convertible note as an equity contribution even though we did not participate in Francis' earnings or losses and were not eligible to receive distributions during the term of the note. Subsequent to the conversion on April 1, 2023, we participate in earnings and losses and are eligible to receive distributions. As of December 31, 2023, we held approximately 17.0 % of Francis' equity.

 We have concluded that Francis is a VIE that we do not consolidate because we are not the primary beneficiary and Francis' management structure is similar to a limited partnership with the non-managing members (i) not having the ability to remove the managing member and (ii) not participating significantly in the operational decisions. We are not the primary beneficiary of Francis because we do not have the power to direct the activities that most significantly impact Francis's economic performance. See Note 12 – Equity Investments for more information about the accounting for our investment in Francis.

 NGP ET IV

 On June 2, 2022, we committed to purchase $ 25.0 million of limited partner interests in NGP ET IV, a private equity fund sponsored by NGP and focused on investments that are part of the global transition toward a lower carbon economy. This commitment represents a 3.6 % interest in NGP ET IV. As of December 31, 2023, we have funded $ 6.6 million of this commitment.

 We have concluded that NGP ET IV is a VIE that we do not consolidate because we are not the primary beneficiary and NGP ET IV is structured as a limited partnership with limited partners (i) not having the ability to remove the general partner and (ii) not participating significantly in the operational decisions. We are not the primary beneficiary of NGP ET IV because we do not have the power to direct the activities that most significantly impact NGP ET IV's economic performance. See Note 12 – Equity Investments for more information about the accounting for our investment in NGP ET IV.

 12. EQUITY INVESTMENTS

 AllDale III

 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 were as follows:

 2023

 2022

 2021

 $

 25,284

 $

 26,325

 $

 27,268

 Equity method investment income

 2,567

 5,634

 2,130

 Distributions received

 ( 3,918)

 ( 6,675)

 ( 3,073)

 $

 23,933

 $

 25,284

 $

 26,325

 We account for our ownership interest in the income or loss of Francis as an equity method investment. Prior to the conversion of our convertible note, we did not participate in Francis' earnings or losses; however, upon conversion on April 1, 2023 we began participating. As a development stage company, Francis depends primarily on capital contributions to meet its operating and debt obligations. We currently believe that the carrying value of our investment is recoverable; however, if Francis is unable to raise sufficient funds to continue its operations and meet its debt obligations, it could have an adverse effect on our investment. The changes in our equity method investment in Francis were as follows:

 2023

 2022

 $

 20,000

 $

 —

 Contributions

 —

 20,000

 Equity method investment loss

 ( 3,513)

 —

 $

 16,487

 $

 20,000

 NGP ET IV

 We account for our ownership interest in the income or loss of NGP ET IV as an equity method investment. The changes in our equity method investment in NGP ET IV were as follows:

 2023

 2022

 $

 4,087

 $

 —

 Contributions

 2,518

 4,087

 Equity method investment loss

 ( 522)

 —

 $

 6,083

 $

 4,087

 Infinitum

 During 2022, we purchased $ 42.0 million of Series D Preferred Stock in Infinitum, a Texas-based startup developer and manufacturer of electric motors featuring printed circuit board stators. On September 8, 2023, we purchased $ 24.6 million of Series E Preferred Stock in Infinitum. The Infinitum Preferred Stock provides for non-cumulative dividends when and if declared by Infinitum's board of directors. Each share of Infinitum Preferred Stock is convertible, at any time, at our option, into shares of common stock of Infinitum. We account for our ownership interest in Infinitum as an equity investment without a readily determinable fair value. Absent an observable price change, it is not practicable to estimate the fair value of our investment in Infinitum because of the lack of a quoted market price for our ownership interests. Therefore, we use a measurement alternative other than fair value to account for our investment.

 Ascend

 On August 22, 2023, we purchased $ 25.0 million of Ascend Preferred Stock in Ascend, a U.S.-based manufacturer and recycler of sustainable, engineered battery materials for electric vehicles. The Ascend Preferred Stock provides for non-cumulative dividends when and if declared by Ascend's board of directors. Each share is convertible, at any time, at our option, into shares of common stock of Ascend. We account for our ownership interest in Ascend as an equity investment without a readily determinable fair value. Absent an observable price change, it is not practicable to estimate the fair value of our investment in Ascend because of the lack of a quoted market price for our ownership interests. Therefore, we use a measurement alternative other than fair value to account for our investment.

 13. 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 23 – Segment Information.

 Coal Operations

 Royalties

 Other,

 Illinois

 Corporate and

 Basin

 Appalachia

 Oil & Gas

 Coal

 Elimination

 Year Ended December 31, 2023

 $

 1,364,901

 $

 845,309

 $

 —

 $

 —

 $

 —

 $

 2,210,210

 —

 —

 —

 —

 Coal royalties

 —

 —

 —

 65,572

 ( 65,572)

 —

 Transportation revenues

 106,150

 36,140

 —

 —

 —

 142,290

 10,505

 1,885

 3,774

 60,244

 76,450

 Total revenues

 $

 1,481,556

 $

 883,334

 $

 141,525

 $

 65,614

 $

 ( 5,328)

 $

 2,566,701

 Year Ended December 31, 2022

 $

 1,219,943

 $

 882,286

 $

 —

 $

 —

 $

 —

 $

 2,102,229

 —

 —

 —

 —

 Coal royalties

 —

 —

 —

 60,624

 ( 60,624)

 —

 Transportation revenues

 69,540

 44,320

 —

 —

 —

 113,860

 6,822

 1,481

 3,837

 40,622

 52,818

 Total revenues

 $

 1,296,305

 $

 928,087

 $

 154,897

 $

 60,680

 $

 ( 20,002)

 $

 2,419,967

 Year Ended December 31, 2021

 $

 873,930

 $

 512,993

 $

 —

 $

 —

 $

 —

 $

 1,386,923

 —

 —

 —

 —

 Coal royalties

 —

 —

 —

 51,402

 ( 51,402)

 —

 Transportation revenues

 41,001

 28,606

 —

 —

 —

 69,607

 4,666

 3,940

 2,256

 27,586

 38,517

 Total revenues

 $

 919,597

 $

 545,539

 $

 86,439

 $

 51,471

 $

 ( 23,816)

 $

 1,579,230

 The following table illustrates the projected revenue for all current coal supply contracts allocated to performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2023 and disaggregated by segment and contract duration.

 2027 and

 2024

 2025

 2026

 Thereafter

 Total

 Illinois Basin Coal Operations coal revenues

 $

 1,291,152

 $

 494,386

 $

 253,465

 $

 238,500

 $

 2,277,503

 Appalachia Coal Operations coal revenues

 754,183

 325,425

 1,600

 —

 1,081,208

 Total coal revenues (1)

 $

 2,045,335

 $

 819,811

 $

 255,065

 $

 238,500

 $

 3,358,711

 (1) Coal revenues generally consists of consolidated revenues excluding our Oil & Gas Royalties segment as well as intercompany revenues from our Coal Royalties segment.

 14. 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 JC Resources Acquisition, which is discussed in more detail in Note 1 – Organization and Presentation, net income attributable to ARLP is allocated to limited partners and participating securities with nonforfeitable distributions or distribution equivalents, while net losses attributable to ARLP are allocated only to limited partners but not to participating securities. Prior to the JC Resources Acquisition, in addition to limited partners and participating securities allocations, amounts are also allocated to our general partner for historical earnings from the mineral interests acquired in the JC Resources Acquisition. Our participating securities are outstanding restricted unit 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 attributable to ARLP used for calculating basic and diluted earnings per unit and the weighted-average units used in computing EPU.

 2023

 2022

 2021

 (in thousands, except per unit data)

 $

 $

 $

 Less:

 General partner's interest in net income attributable to ARLP

 ( 1,384)

 ( 9,010)

 ( 4,614)

 Limited partners' interest in net income attributable to ARLP

 628,734

 577,190

 178,157

 Less:

 Distributions to participating securities

 ( 9,688)

 ( 8,527)

 ( 2,334)

 Undistributed earnings attributable to participating securities

 ( 7,203)

 ( 10,576)

 ( 2,403)

 Net income attributable to ARLP available to limited partners

 $

 611,843

 $

 558,087

 $

 173,420

 Weighted-average limited partner units outstanding – basic and diluted

 127,180

 127,195

 127,195

 Earnings per limited partner unit - basic and diluted (1)

 $

 4.81

 $

 4.39

 $

 1.36

 (1)
 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, 2023, 2022 and 2021, the combined total of LTIP, SERP and Directors' Deferred Compensation Plan units of 2,922,384, 3,540,385 and 1,967,672, respectively, were considered anti-dilutive under the treasury stock method.

 15. EMPLOYEE BENEFIT PLANS

 Defined Contribution Plans

 All regular full-time employees are eligible to participate in a defined contribution profit sharing and savings plan ("PSSP") that we sponsor. 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 $ 21.8 million, $ 19.4 million and $ 17.7 million for the years ended December 31, 2023, 2022 and 2021, 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. 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, 2023 and 2022 and the funded status of the Pension Plan reconciled with the amounts reported in our consolidated financial statements:

 2023

 2022

 (dollars in thousands)

 Change in benefit obligations:

 Benefit obligations at beginning of year

 $

 104,682

 $

 139,566

 Interest cost

 5,180

 3,749

 Actuarial loss (gain)

 2,446

 ( 32,996)

 Benefits paid

 ( 6,438)

 ( 5,637)

 Benefit obligations at end of year

 105,870

 104,682

 Change in plan assets:

 Fair value of plan assets at beginning of year

 92,129

 113,976

 Actual return on plan assets

 11,561

 ( 16,210)

 Benefits paid

 ( 6,438)

 ( 5,637)

 Fair value of plan assets at end of year

 97,252

 92,129

 Funded status at the end of year

 $

 ( 8,618)

 $

 ( 12,553)

 Amounts recognized in balance sheet:

 Non-current liability

 $

 ( 8,618)

 $

 ( 12,553)

 Amounts recognized in accumulated other comprehensive income consists of:

 Prior service cost

 $

 ( 196)

 $

 ( 382)

 Net actuarial loss

 ( 11,584)

 ( 15,160)

 $

 ( 11,780)

 $

 ( 15,542)

 Weighted-average assumption to determine benefit obligations as of December 31,

 Discount rate

 4.90 %

 5.10 %

 Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31,

 Discount rate

 5.10 %

 2.73 %

 Expected return on plan assets

 7.00 %

 6.00 %

 The actuarial loss component of the change in benefit obligations in 2023 was primarily attributable to a decrease in the discount rate compared to the prior year end. The actuarial gain component of the change in benefit obligations in 2022 was primarily attributable to an increase in the discount rate compared to the prior year end.

 The expected long-term rate of return used to determine our pension liability is based on an asset allocation assumption of:

 Asset allocation

 As of December 31, 2023

 assumption

 Equity securities

 75 %

 Fixed income securities

 25 %

 100 %

 The actual return on plan assets was 12.5 % and ( 14.6)% for the years ended December 31, 2023 and 2022, respectively.

 2023

 2022

 2021

 Components of net periodic benefit cost (credit):

 Interest cost

 $

 5,180

 $

 3,749

 $

 3,438

 Expected return on plan assets

 ( 6,220)

 ( 6,638)

 ( 6,580)

 Amortization of prior service cost

 Amortization of net loss

 1,963

 4,327

 Net periodic benefit cost (credit) (1)

 $

 ( 172)

 $

 ( 740)

 $

 1,371

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

 2023

 2022

 Other changes in plan assets and benefit obligation recognized in accumulated other comprehensive loss:

 Net actuarial gain

 $

 2,894

 $

 10,148

 Reversal of amortization item:

 Prior service cost

 Net actuarial loss

 1,963

 Total recognized in accumulated other comprehensive loss

 3,762

 12,297

 Net periodic benefit cost

 Total recognized in net periodic benefit cost and accumulated other comprehensive loss

 $

 3,934

 $

 13,037

 Estimated future benefit payments as of December 31, 2023 are as follows:

 2024

 $

 6,331

 2025

 6,490

 2026

 6,688

 2027

 6,820

 2028

 6,899

 2029-2033

 35,204

 $

 68,432

 We do no t expect to make material contributions to the Pension Plan during 2024.

 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 Employee Retirement Income Security Act of 1974 or other applicable laws. The investment manager employs an asset allocation strategy through investment in certain investment types such as equity securities and fixed income securities. The asset allocation process provides that the total portfolio allocation will be adjusted as the funded ratio of the plan changes and market conditions warrant, consistent with managing risks in accordance with plan objectives and time horizon. As the funded ratio improves, more assets may be allocated to the core fixed income portfolio to reduce volatility. The objective of the allocation policy is to achieve an average annual return greater than the actuarial discount rate over the specified time horizon. General asset allocation guidelines at December 31, 2023 are as follows:

 Percentage of Total Portfolio

 Minimum

 Maximum

 Equity securities

 50 %

 85 %

 Fixed income securities

 15 %

 50 %

 Equity securities include domestic and international common stocks, convertible notes and bonds, convertible preferred stocks, American Depository Receipts of non-U.S. companies and Real Estate Investment Trusts. Fixed income securities include debt securities issued by the federal government as well as state and local governments, banker's acceptances, repurchase agreements, asset-backed securities, collateralized mortgage-backed securities, corporate debt securities, inflation-index bonds and structured notes.

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

 2023

 2022

 Level 1

 Level 2

 Level 3

 Total

 Level 1

 Level 2

 Level 3

 Total

 Cash and cash equivalents

 $

 1,665

 $

 —

 $

 —

 $

 1,665

 $

 5,422

 $

 —

 $

 —

 $

 5,422

 Equity investments - Individual securities (a):

 Consumer discretionary

 2,605

 —

 —

 2,605

 —

 —

 —

 —

 Consumer durables

 2,088

 —

 —

 2,088

 —

 —

 —

 —

 Energy

 —

 —

 —

 —

 —

 —

 Financials

 4,852

 —

 —

 4,852

 —

 —

 —

 —

 Health Care

 4,296

 —

 —

 4,296

 —

 —

 —

 —

 Industrials & materials

 4,507

 —

 —

 4,507

 —

 —

 —

 —

 Information technology & communication

 8,102

 —

 —

 8,102

 —

 —

 —

 —

 Fixed income investments - Individual securities (b):

 Preferred stocks non-convertible

 —

 —

 —

 —

 —

 —

 Equity investments - Mutual funds (c):

 Mid-cap stock funds

 11,847

 —

 —

 11,847

 —

 —

 —

 —

 Small-cap stock funds

 4,007

 —

 —

 4,007

 —

 —

 —

 —

 International stock funds

 7,849

 —

 —

 7,849

 —

 —

 —

 —

 Equity investments - Exchange traded funds (d):

 Large-cap blend - S&P 500 index

 18,044

 —

 —

 18,044

 —

 —

 —

 —

 International - Developed markets

 3,138

 —

 —

 3,138

 —

 —

 —

 —

 International - Emerging markets

 1,894

 —

 —

 1,894

 —

 —

 —

 —

 Accrued income (e)

 —

 —

 —

 —

 —

 —

 $

 75,883

 $

 $

 —

 $

 75,912

 $

 5,422

 $

 —

 $

 —

 $

 5,422

 Commingled investment funds measured at net asset value (f):

 Equities - United States

 —

 36,259

 Equities - United States futures

 —

 ( 697)

 Equities - International developed markets

 —

 14,214

 Equities - International developed markets futures

 —

 ( 1,693)

 Equities - International emerging markets

 —

 Equities - International emerging markets futures

 —

 3,289

 Fixed income - Investment grade

 21,340

 13,856

 Fixed income - High yield

 —

 Fixed income - Futures

 —

 8,590

 Alternatives

 —

 11,951

 Total

 $

 97,252

 $

 92,129

 (a)
 Equity investments - Individual securities include investments in publicly traded common stock and American Depository Receipts. Publicly traded common stocks are traded on a national securities exchange and investments in common stocks are valued using quoted market prices multiplied by the number of shares owned. American Depository Receipts are negotiable securities issued by a bank representing shares in a foreign company and traded on a national securities exchange.

 (b)
 Fixed income investments - Individual securities include investments in preferred stock that are traded on a national securities exchange and valued using quoted market prices multiplied by the number of shares owned.

 (c)
 Equity investments - Mutual funds are valued daily in actively traded markets. For purposes of calculating the value, portfolio securities and other assets for which market quotes are readily available are valued at market value. Investments initially valued in currencies other than the U.S. dollars are converted to the U.S. dollar using exchange rates obtained from pricing services.

 (d)
 Equity investments – Exchange traded funds are funds that own financial assets and trade on exchanges, generally tracking a specific index. Investments in exchange traded funds are valued using a market approach based on the quoted market prices.

 (e)
 Accrued income represents dividends or interest declared, but not received, on equity securities owned at December 31, 2023.

 (f)
 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.

 16. COMMON UNIT-BASED COMPENSATION PLANS

 Long-Term Incentive Plan

 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

 Non-vested grants at January 1, 2021

 1,430,489

 $

 5.02

 $

 6,409

 Granted (1)

 1,818,190

 6.03

 Forfeited

 ( 118,204)

 5.48

 Non-vested grants at December 31, 2021

 3,130,475

 5.59

 39,569

 Granted (1)

 769,907

 14.65

 Forfeited

 ( 203,249)

 6.93

 Non-vested grants at December 31, 2022

 3,697,133

 7.40

 75,126

 Granted (1)

 450,125

 21.54

 Vested (2)

 ( 1,291,330)

 5.02

 Forfeited

 ( 145,584)

 6.86

 Non-vested grants at December 31, 2023

 2,710,344

 10.91

 57,405

 (1)
 Restricted units granted have certain minimum-value guarantees per unit, regardless of whether or not the awards vest.

 (2)
 During the year ended December 31, 2023, we issued 860,060 unrestricted common units to the LTIP participants. The remaining vested units were settled in cash to satisfy our tax withholding obligations.

 For the years ended December 31, 2023, 2022 and 2021, our LTIP expense for grants of restricted units was $ 10.4 million, $ 9.4 million and $ 5.4 million, respectively. The total obligation associated with LTIP grants of restricted units as of December 31, 2023 and 2022 was $ 19.5 million and $ 16.0 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets. As of December 31, 2023, there was $ 10.0 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 1.4 years.

 On January 24, 2024, the Compensation Committee authorized additional grants of 440,470 restricted units, of which 425,470 units were granted. These restricted units have certain minimum-value guarantees, regardless of whether or not the awards vest.

 Supplemental Executive Retirement Plan and Directors' Deferred Compensation Plan

 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

 Phantom units outstanding as of January 1, 2021

 760,630

 $

 22.04

 $

 3,408

 Granted

 46,638

 9.45

 Settled (1)

 ( 138,570)

 25.86

 Phantom units outstanding as of December 31, 2021

 668,698

 20.37

 8,452

 Granted

 73,842

 19.44

 Phantom units outstanding as of December 31, 2022

 742,540

 20.28

 15,088

 Granted

 118,737

 20.46

 Settled (1)

 ( 49,331)

 20.27

 Phantom units outstanding as of December 31, 2023

 811,946

 20.44

 17,197

 (1)
 During the years ended December 31, 2023 and 2021, we purchased 27,576 ARLP common units and 102,962 ARLP common units on the open market to settle the accounts of participants under the SERP. Units purchased were net of units settled in cash to satisfy tax-withholding obligations.

 Total SERP and Directors' Deferred Compensation Plan expense was $ 2.4 million, $ 1.4 million and $ 0.4 million for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023 and 2022, the total obligation associated with the SERP and Directors' Deferred Compensation Plan was $ 16.6 million and $ 15.1 million, respectively, and is included in the partners' capital Limited partners-common unitholders line item in our consolidated balance sheets.

 17. SUPPLEMENTAL CASH FLOW INFORMATION

 2023

 2022

 2021

 Cash Paid For:

 Interest

 $

 37,126

 $

 34,844

 $

 36,402

 Income taxes

 $

 13,615

 $

 23,794

 $

 Non-Cash Activity:

 Accounts payable for purchase of property, plant and equipment

 $

 14,586

 $

 44,281

 $

 8,325

 Right-of-use assets acquired by operating lease

 $

 2,596

 $

 1,315

 $

 Market value of common units distributed under deferred compensation plans before tax withholding requirements

 $

 28,906

 $

 —

 $

 1,082

 18. ASSET RETIREMENT OBLIGATIONS

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

 2023

 2022

 $

 149,813

 $

 131,099

 Accretion expense

 4,433

 3,731

 ( 2,317)

 ( 2,445)

 Allocation of liability associated with mine development and change in assumptions

 ( 1,486)

 17,428

 $

 150,443

 $

 149,813

 For the year ended December 31, 2023, the allocation of liability associated with mine development and change in assumptions decreased by $ 1.5 million. The decrease was largely attributable to lower cost assumptions.

 For the year ended December 31, 2022, the allocation of liability associated with mine development and change in assumptions increased by $ 17.4 million. The increase was largely attributable to higher cost assumptions as well as the expansion of refuse disposal facilities at certain mines.

 The impact of discounting our estimated cash flows resulted in reducing the accrual for asset retirement obligations by $ 116.2 million and $ 110.4 million at December 31, 2023 and 2022, respectively. Estimated payments of asset retirement obligations as of December 31, 2023 are as follows:

 2024

 $

 3,518

 2025

 5,557

 2026

 4,063

 2027

 7,038

 2028

 4,291

 Thereafter

 242,134

 Aggregate undiscounted asset retirement obligations

 266,601

 Less: effect of discounting

 ( 116,158)

 Total asset retirement obligations

 150,443

 Less: current portion

 ( 3,518)

 Non-current asset retirement obligations

 $

 146,925

 As of December 31, 2023 and 2022, we had approximately $ 173.5 million and $ 174.3 million, respectively, in surety bonds outstanding to secure the performance of our reclamation obligations.

 19. ACCRUED WORKERS' COMPENSATION AND PNEUMOCONIOSIS BENEFITS

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

 2023

 2022

 $

 49,452

 $

 53,448

 Changes in accruals

 12,155

 7,384

 ( 14,438)

 ( 12,708)

 Interest accretion

 2,202

 1,147

 Valuation loss (gain)

 ( 1,396)

 $

 47,975

 $

 49,452

 The discount rate used to calculate the estimated present value of future obligations for workers' compensation was 4.66 % and 4.87 % at December 31, 2023 and 2022, respectively.

 The valuation gain in 2023 was primarily attributable to a favorable change in claims development partially offset by a decrease in the discount rate used to calculate the estimated present value of the future obligations. The valuation loss in 2022 was primarily attributable to an increase in the discount rate used to calculate the estimated present value of the future obligations being partially offset by unfavorable changes in claims development.

 As of December 31, 2023 and 2022, we had $ 99.4 million and $ 99.8 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, 2023 and 2022 were $ 4.1 million. 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:

 2023

 2022

 Benefit obligations at beginning of year

 $

 104,287

 $

 111,316

 Service cost

 2,698

 3,798

 Interest cost

 4,951

 2,991

 Actuarial loss (gain)

 25,615

 ( 9,840)

 Benefits and expenses paid

 ( 5,107)

 ( 3,978)

 Benefit obligations at end of year

 $

 132,444

 $

 104,287

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

 2023

 2022

 2021

 Net actuarial gain (loss)

 $

 ( 25,615)

 $

 9,840

 $

 ( 161)

 Reversal of amortization item:

 Net actuarial loss

 1,382

 1,038

 4,172

 Total recognized in accumulated other comprehensive loss

 $

 ( 24,233)

 $

 10,878

 $

 4,011

 The discount rate used to calculate the estimated present value of future obligations for pneumoconiosis benefits was 4.81 %, 5.0 % and 2.73 % at December 31, 2023, 2022 and 2021, respectively.

 2023

 2022

 2021

 Amount recognized in accumulated other comprehensive loss consists of:

 Net actuarial loss

 $

 49,745

 $

 25,510

 $

 36,388

 The actuarial loss component of the change in benefit obligations in 2023 was primarily attributable to a) unfavorable changes in the discount rate, b) unfavorable demographics in the at-risk population, c) unfavorable black lung claims experience, d) unfavorable assumption changes regarding future average medical benefits, and e) unfavorable assumption changes related to Federal and State benefit levels. The actuarial gain component of the change in benefit obligations in 2022 was primarily attributable to favorable assumption changes in the discount rate and demographics in the at-risk population. These components were offset in part by a) unfavorable black lung claims experience, b) unfavorable assumption changes regarding future average medical benefits and legal expense levels, and c) unfavorable assumption changes related to Federal and State benefit levels.

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

 2023

 2022

 Workers' compensation claims

 $

 47,975

 $

 49,452

 Pneumoconiosis benefit claims

 132,444

 104,287

 Total obligations

 180,419

 153,739

 Less current portion

 ( 15,913)

 ( 14,099)

 Non-current obligations

 $

 164,506

 $

 139,640

 Both the pneumoconiosis benefit and workers' compensation obligations were unfunded at December 31, 2023 and 2022.

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

 2023

 2022

 2021

 Black lung benefits:

 Service cost

 $

 2,698

 $

 3,798

 $

 4,021

 Interest cost (1)

 4,951

 2,991

 2,545

 Net amortization (1)

 1,382

 1,038

 4,172

 Total pneumoconiosis expense

 9,031

 7,827

 10,738

 Workers' compensation expense

 15,152

 11,675

 8,339

 Net periodic benefit cost

 $

 24,183

 $

 19,502

 $

 19,077

 ________________________________________
 (1)
 Interest cost and net amortization is included in the Other income line item within our consolidated statements of income.

 20. 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.

 Line of Credit

 On February 19, 2021, we entered into a line of credit arrangement (the "Line of Credit") with a related party for $ 5.0 million. This Line of Credit was amended on November 4, 2021 to increase the total available under the Line of Credit to $ 5.5 million. The Line of Credit had a maturity date of February 28, 2023 and accrued interest at an annual rate of 3.5 % payable quarterly. During the year ended December 31, 2021 we received proceeds and made payments under the Line of Credit of $ 5.3 million. On November 10, 2021 we terminated the Line of Credit.

 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

 Craft Foundations

 Coal

 Coal

 Coal

 CoalPlay

 Henderson

 Henderson

 Tunnel

 & Union

 Webster

 Henderson

 & Union

 Ridge

 Counties, KY

 County, KY

 County, KY

 Counties, KY

 Total

 2005

 2014

 2014

 2014

 2015

 As of January 1, 2021

 $

 1,500

 $

 19,178

 $

 —

 $

 15,129

 $

 12,582

 $

 48,389

 3,000

 3,597

 2,568

 2,521

 2,131

 13,817

 Recoupment

 ( 3,000)

 ( 1,025)

 —

 —

 —

 ( 4,025)

 Unrecoupable

 —

 —

 ( 2,568)

 —

 —

 ( 2,568)

 As of December 31, 2021

 1,500

 21,750

 —

 17,650

 14,713

 55,613

 3,000

 3,597

 —

 2,522

 2,131

 11,250

 Recoupment

 ( 3,000)

 ( 3,255)

 —

 —

 —

 ( 6,255)

 Unrecoupable

 —

 —

 —

 —

 —

 —

 As of December 31, 2022

 1,500

 22,092

 —

 20,172

 16,844

 60,608

 3,000

 3,597

 —

 2,521

 2,131

 11,249

 Recoupment

 ( 3,000)

 ( 4,258)

 —

 —

 —

 ( 7,258)

 Unrecoupable

 —

 —

 —

 —

 —

 —

 As of December 31, 2023

 $

 1,500

 $

 21,431

 $

 —

 $

 22,693

 $

 18,975

 $

 64,599

 Craft Foundations

 In January 2005, we acquired Tunnel Ridge from ARH. In connection with this acquisition, we assumed a coal lease with Alliance Resource GP, LLC, an entity indirectly wholly owned by Mr. Craft and Kathleen S. Craft until it was dissolved in December 2020. In December 2018, the property subject to the lease was transferred to the Joseph W. Craft III Foundation and the Kathleen S. Craft Foundation, which each hold an undivided one - half interest (the "Craft Foundations"). 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 $ 12.1 million, $ 12.3 million and $ 5.8 million in earned royalties in 2023, 2022 and 2021 respectively.

 Tunnel Ridge has a surface land lease with an annual payment of $ 0.2 million, payable in January of each year with the Craft Foundations.

 WKY CoalPlay

 In February 2015, WKY CoalPlay, LLC ("WKY CoalPlay") entered into a coal lease agreement with Alliance Resource Properties regarding coal mineral resources 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.

 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 and annual minimum royalty payments of $ 3.6 million and $ 2.5 million, respectively. All annual minimum royalty payments under each agreement are recoupable from future earned royalties payable under that agreement.

 In December 2014, WKY CoalPlay's subsidiary, Webster Coal Reserves, LLC entered into a coal lease agreement with Alliance Resource Properties. The lease had a term of 7 years and provided for earned royalty payments of 4.0 % of the coal sales price and annual minimum royalty payments of $ 2.6 million. This lease expired in December 2021.

 21. 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 mineral reserve and resource leases as discussed in Note 20 – Related-Party Transactions.

 Contractual Commitments

 In connection with planned capital projects, we have contractual commitments of approximately $ 201.9 million at December 31, 2023. As of December 31, 2023, we had $ 22.3 million in commitments to purchase coal from external production sources in 2024 and thereafter.

 General Litigation

 Certain of our subsidiaries are party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. The plaintiffs seek class and collective action certification, which we oppose, and the courts have not yet made definitive final rulings on those issues. We believe our ultimate exposure, if any, will not be material to our results of operations or financial position; however, if our current belief as to the merit of the claims is not upheld, it is reasonably possible that the ultimate resolution of these matters could result in a potential loss that may be material to our results of operations.

 We also have various other lawsuits, claims and regulatory proceedings incidental to our business that 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 are different from management's current expectations, such matters could have a material adverse effect on our business and operations.

 Other

 Effective October 1, 2023, we renewed our property and casualty insurance program through September 30, 2024. 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 $ 25.0 million overall aggregate deductible. We retained a 7.25 % participating interest in our current 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.

 22. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS

 The international coal market has been a part of our business with indirect sales to end-users in Europe, Africa, Asia, North America and South America. Our sales into the international coal market are considered exports and are made through brokered transactions. During the years ended December 31, 2023, 2022 and 2021, export tons represented approximately 15.7 %, 12.5 % and 12.5 % of tons sold, respectively.

 Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known. No individual country was attributed greater than 10% of total domestic and export tons sold during the years ended December 31, 2023, 2022 and 2021.

 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. A major customer is defined as a customer from which we derive at least ten percent of our total revenues, including transportation revenues. Total revenues from major customers are as follows:

 Segment

 2023

 2022

 2021

 Customer A

 Illinois Basin/Appalachia

 $

 332,500

 $

 —

 $

 —

 Customer B

 253,573

 260,146

 —

 Customer C

 —

 328,406

 239,482

 Customer D

 Illinois Basin/Appalachia

 —

 228,480

 —

 Trade accounts receivable from major customers totaled approximately $ 54.3 million and $ 63.6 million at December 31, 2023 and 2022, respectively. Our credit loss experience has historically been insignificant. Financial conditions of our customers could result in a material change to our credit loss expense in future periods. The coal supply agreements with Customers A and B expire in 2025 and 2029, respectively.

 23. SEGMENT INFORMATION

 We operate in the United States as a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests. We aggregate multiple operating segments into four reportable segments, Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an "all other" category referred to as Other, Corporate and Elimination. Our two coal operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. The two coal operations reportable 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. Our Oil & Gas Royalties reportable segment includes our oil & gas mineral interests which are located primarily in the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) basins. The operations within our Oil & Gas Royalties reportable segment primarily include receiving royalties and lease bonuses for our oil & gas mineral interests. Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties, which are either (a) leased to our mining complexes or (b) near our coal mining operations but not yet leased.

 The Illinois Basin Coal Operations reportable segment includes (a) the Gibson County Coal, LLC's ("Gibson ") mining complex, (b) the Warrior Coal, LLC ("Warrior") mining complex, (c) the River View mining complex and (d) the Hamilton mining complex. The segment also includes our Mt. Vernon Transfer Terminal, LLC ("Mt. Vernon") coal loading terminal in Indiana which operates on the Ohio River, Mid-America Carbonates, LLC ("MAC") and other support services, and our non-operating mining complexes.

 The Appalachia Coal Operations reportable segment includes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining, LLC ("MC Mining") mining complex.

 The Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by Alliance Minerals' through its consolidated subsidiaries as well as equity interests held in AllDale III (Note 12 – Equity Investments).

 Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties that are (a) leased to certain of our mining complexes in both the Illinois Basin Coal Operations and Appalachia

 Coal Operations reportable segments or (b) located near our operations and external mining operations. Approximately 60 % of the coal sold by our coal operations' mines was leased from our Coal Royalties entities.

 Other, Corporate and Elimination includes marketing and administrative activities, Matrix Design Group, LLC, its subsidiaries, and Alliance Design Group, LLC (collectively referred to as the "Matrix Group"), our investments in Francis, Infinitum, NGP ET IV and Ascend (see Note 12 – Equity Investments), Wildcat Insurance, which assists the ARLP Partnership with its insurance requirements, AROP Funding and Alliance Finance (both discussed in Note 6 – Long-Term Debt) and other miscellaneous activities. The eliminations included in Other, Corporate and Elimination primarily represent the intercompany coal royalty transactions described above between our Coal Royalties reportable segment and our coal operations' mines.

 Reportable segment results are presented below.

 Coal Operations

 Royalties

 Other,

 Illinois

 Corporate and

 Basin

 Appalachia

 Oil & Gas

 Coal

 Elimination

 Year Ended December 31, 2023

 Revenues - Outside (1)

 $

 1,481,556

 $

 883,334

 $

 141,525

 $

 $

 60,244

 $

 2,566,701

 Revenues - Intercompany

 —

 —

 —

 65,572

 ( 65,572)

 —

 Total revenues (1)

 1,481,556

 883,334

 141,525

 65,614

 ( 5,328)

 2,566,701

 Segment Adjusted EBITDA Expense (2)

 861,288

 516,471

 16,532

 24,451

 ( 14,024)

 1,404,718

 Segment Adjusted EBITDA (3)

 514,118

 330,723

 121,508

 41,163

 4,661

 1,012,173

 Total assets

 966,102

 488,427

 781,184

 315,592

 237,121

 2,788,426

 Capital expenditures (4)

 257,885

 116,217

 —

 4,836

 379,338

 Year Ended December 31, 2022

 Revenues - Outside (1)

 $

 1,296,305

 $

 928,087

 $

 154,897

 $

 $

 40,622

 $

 2,419,967

 Revenues - Intercompany

 —

 —

 —

 60,624

 ( 60,624)

 —

 Total revenues (1)

 1,296,305

 928,087

 154,897

 60,680

 ( 20,002)

 2,419,967

 Segment Adjusted EBITDA Expense (2)

 806,080

 464,029

 15,395

 21,871

 ( 23,497)

 Segment Adjusted EBITDA (3)

 420,684

 426,402

 143,179

 38,809

 3,495

 Total assets

 779,018

 431,913

 778,465

 321,587

 417,038

 2,728,021

 Capital expenditures (4)

 158,624

 76,603

 —

 38,276

 12,891

 286,394

 Year Ended December 31, 2021

 Revenues - Outside (1)

 $

 919,597

 $

 545,539

 $

 86,439

 $

 $

 27,586

 $

 1,579,230

 Revenues - Intercompany

 —

 —

 —

 51,402

 ( 51,402)

 —

 Total revenues (1)

 919,597

 545,539

 86,439

 51,471

 ( 23,816)

 1,579,230

 Segment Adjusted EBITDA Expense (2)

 613,303

 344,332

 11,051

 18,269

 ( 33,198)

 953,757

 Segment Adjusted EBITDA (3)

 265,292

 172,601

 76,920

 33,202

 9,383

 557,398

 Total assets

 676,091

 420,144

 698,702

 285,943

 146,601

 2,227,481

 Capital expenditures (4)

 60,166

 47,577

 —

 15,196

 122,984

 (1)
 Revenues included in the Other, Corporate and Elimination column are attributable to intercompany eliminations, which are primarily intercompany coal royalties eliminations, outside revenues at the Matrix Group and other outside miscellaneous sales and revenue activities.

 (2)
 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 Operating expenses (excluding depreciation, depletion and amortization), the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA Expense:

 2023

 2022

 2021

 Operating expenses (excluding depreciation, depletion and amortization)

 $

 1,368,787

 $

 1,288,082

 $

 944,419

 Outside coal purchases

 36,149

 6,372

 Other expense (income)

 ( 218)

 ( 4,355)

 2,966

 Segment Adjusted EBITDA Expense

 $

 1,404,718

 $

 $

 953,757

 (3)
 Segment Adjusted EBITDA is defined as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expense. 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. Net income, the most comparable GAAP financial measure, is reconciled to consolidated Segment Adjusted EBITDA:

 2023

 2022

 2021

 $

 $

 $

 Noncontrolling interest

 ( 6,052)

 ( 1,958)

 ( 598)

 $

 $

 $

 General and administrative

 79,096

 80,425

 70,275

 267,982

 276,670

 264,794

 Interest expense, net

 26,697

 35,296

 39,141

 8,280

 Consolidated Segment Adjusted EBITDA

 $

 1,012,173

 $

 $

 557,398

 (4)
 Capital expenditures shown exclude $ 110.9 million, $ 92.6 million and $ 31.0 million paid for oil & gas acquisitions in 2023, 2022 and 2021, respectively. See Note 3 – Acquisitions for more information.

 SUPPLEMENTAL OIL & GAS RESERVE INFORMATION (UNAUDITED)

 All periods presented in these supplemental oil & gas reserve information disclosures have been recast to reflect the JC Resources Acquisition as if we, rather than JC Resources, acquired the mineral interests in 2019. For more information with respect to the JC Resources Acquisition please see Note – 1 Organization and Presentation and Note – 3 Acquisition in our consolidated financial statements.

 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:

 2023

 2022

 2021

 Acquisition costs of properties

 Proved

 $

 21,943

 $

 44,986

 $

 12,542

 Unproved

 16,741

 47,785

 18,418

 Total

 $

 38,684

 $

 92,771

 $

 30,960

 Property acquisition costs for 2023 primarily include the Skyland Acquisition and other ground game acquisitions. Property acquisition costs for 2022 primarily include the Belvedere and Jase Acquisitions. Property acquisition costs for 2021 are related to the Boulders Acquisition. See Note 3 – Acquisitions in our consolidated financial statements for more information regarding these acquisitions.

 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,

 2023

 2022

 2021

 Proved properties

 $

 438,378

 $

 14,950

 $

 388,358

 $

 11,965

 $

 318,250

 $

 9,138

 Unproved properties

 414,972

 13,295

 426,309

 16,193

 403,645

 19,216

 Total

 853,350

 28,245

 814,667

 28,158

 721,895

 28,354

 Less accumulated depreciation, depletion and amortization

 (144,561)

 (5,183)

 (117,982)

 (3,912)

 (85,038)

 (3,015)

 Oil & gas properties, net

 $

 708,789

 $

 23,062

 $

 696,685

 $

 24,246

 $

 636,857

 $

 25,339

 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 of our Oil & Gas Royalties segment to our overall results.

 2023

 2022

 2021

 Consolidated activities

 $

 $

 $

 3,774

 3,837

 2,256

 Production costs and severance taxes

 (13,423)

 (13,200)

 (8,511)

 (36,865)

 (30,034)

 (25,684)

 (14,568)

 (54,842)

 —

 Total results of oil & gas activities

 $

 76,669

 $

 56,821

 $

 52,244

 Our share of an equity method investee

 $

 4,719

 $

 7,292

 $

 3,788

 Production costs and severance taxes

 (638)

 (916)

 (472)

 (1,142)

 (897)

 (787)

 Total results of oil & gas activities

 $

 3,041

 $

 5,516

 $

 2,595

 Oil & Gas Reserves

 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

 (MMcf)

 (MBOE)

 Consolidated activities

 As of January 1, 2021

 7,517

 34,055

 3,340

 16,533

 Purchases of minerals in place

 2,149

 (404)

 (205)

 1,168

 (898)

 (3,460)

 (402)

 (1,877)

 As of December 31, 2021 (1)

 7,179

 33,497

 3,834

 16,596

 Purchases of minerals in place

 3,619

 1,960

 (24)

 4,686

 1,425

 2,060

 8,334

 1,018

 4,466

 (1,061)

 (4,814)

 (541)

 (2,404)

 As of December 31, 2022 (1)

 9,013

 45,322

 5,476

 22,043

 Purchases of minerals in place

 2,421

 (175)

 2,177

 1,252

 4,460

 2,649

 (1,418)

 (5,759)

 (726)

 (3,105)

 As of December 31, 2023 (1)

 9,033

 48,621

 6,105

 23,242

 (1)
 Proved reserves of approximately 1,780 MBOE, 1,736 MBOE and 1,285 MBOE were attributable to noncontrolling interests, as of December 31, 2023, 2022 and 2021, respectively.

 Crude Oil

 Natural Gas

 Natural Gas Liquids

 Total

 (MMcf)

 (MBOE)

 Our share of an equity method investee

 As of January 1, 2021

 2,052

 Sales of minerals in place

 (9)

 (15)

 —

 (12)

 (50)

 (53)

 (51)

 (31)

 (421)

 —

 (101)

 As of December 31, 2021

 2,386

 Sales of minerals in place

 (7)

 (18)

 (4)

 (14)

 (43)

 (412)

 —

 (112)

 As of December 31, 2022

 2,460

 Sales of minerals in place

 —

 —

 —

 —

 (46)

 (23)

 (57)

 (44)

 (402)

 —

 (110)

 As of December 31, 2023

 2,902

 1,052

 Total consolidated and equity interests in reserves at December 31, 2023

 9,353

 51,523

 6,353

 24,294

 Net proved developed reserves as of December 31, 2021

 6,016

 31,211

 3,369

 14,587

 Net proved developed reserves as of December 31, 2022

 7,551

 41,173

 4,806

 19,219

 Net proved developed reserves as of December 31, 2023

 7,754

 45,684

 5,485

 20,854

 Net proved undeveloped reserves as of December 31, 2021

 1,488

 4,672

 2,908

 Net proved undeveloped reserves as of December 31, 2022

 1,811

 6,609

 3,795

 Net proved undeveloped reserves as of December 31, 2023

 1,599

 5,839

 3,440

 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, 2021, included:

 Net change due to extensions and discoveries - The increases are a result of additional development by the operators of the properties under which we own mineral interests. In 2021, a net addition of 1,358 MBOE occurred primarily from the completion of 906 new wells on our acreage and from the addition of 498 new proved undeveloped locations due to permitting and drilling activity.

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

 Notable changes in proved reserves during the year ended December 31, 2022, included:

 Net change due to extensions and discoveries - The increases are a result of additional development by the operators of the properties under which we own mineral interests. In 2022, a net addition of 4,598 MBOE occurred primarily from the completion of 1,212 new wells on our acreage and from the addition of 878 new proved undeveloped locations due to permitting and drilling activity.

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

 Notable changes in proved reserves during the year ended December 31, 2023, included:

 Net change due to extensions and discoveries - The increases are a result of additional development by the operators of the properties under which we own mineral interests. In 2023, a net addition of 2,897 MBOE occurred primarily from the completion of 2,117 new wells on our acreage and from the addition of 548 new proved undeveloped locations due to permitting and drilling activity.

 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

 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 years ended December 31, 2023, 2022 and 2021. 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.

 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,

 2023

 2022

 2021

 Future cash inflows

 $

 914,461

 $

 34,986

 $

 1,275,564

 $

 52,636

 $

 636,933

 $

 31,636

 Future production costs and severance taxes

 (69,507)

 (2,548)

 (97,158)

 (4,287)

 (48,013)

 (2,484)

 Future income tax expense (1)

 (194,339)

 —

 (255,504)

 —

 —

 —

 Future net cash flows (undiscounted)

 650,615

 32,438

 922,902

 48,349

 588,920

 29,152

 Annual discount 10% for estimated timing

 (315,327)

 (14,852)

 (466,245)

 (23,904)

 (289,037)

 (13,980)

 Total standardized measure (2)

 $

 335,288

 $

 17,586

 $

 456,657

 $

 24,445

 $

 299,883

 $

 15,172

 (1)
 On March 15, 2022, Alliance Minerals changed its Federal income tax status from a pass-through entity to a taxable entity via a "check the box" election, which became effective January 1, 2022. See Note 7 – Income Tax in our consolidated financial statements for more information.

 (2)
 Includes standardized discounted future net cash flows of approximately $31.6 million, $45.3 million and $17.9 million attributable to noncontrolling interests in the ARLP Partnership's consolidated subsidiaries as of December 31, 2023, 2022 and 2021, 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,

 2023

 2022

 2021

 Oil (per Bbl)

 $

 77.61

 $

 92.5

 $

 63.57

 Natural gas (per Mcf)

 1.55

 5.43

 2.98

 NGLs (per Bbl)

 22.63

 35.87

 21.13

 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,

 2023

 2022

 2021

 Standardized measure, beginning of year

 $

 456,657

 $

 24,445

 $

 299,883

 $

 15,172

 $

 165,483

 $

 7,764

 Purchases and sales of reserves in place, less related costs

 17,519

 —

 55,812

 (265)

 15,358

 (264)

 Sales, net of production costs

 (124,328)

 (4,081)

 (137,860)

 (6,376)

 (75,672)

 (3,316)

 Net changes due to extensions and discoveries

 60,628

 3,582

 149,721

 5,139

 37,395

 3,613

 Net changes in prices and production costs

 (185,935)

 (7,960)

 211,222

 8,386

 132,427

 6,753

 Revisions of previous quantity estimates

 15,479

 (686)

 21,457

 9,252

 (871)

 Net changes in income taxes (1)

 36,699

 —

 (138,047)

 —

 —

 —

 Accretion of discount

 39,912

 1,839

 23,283

 1,086

 12,933

 Changes in timing and other

 18,657

 (28,814)

 2,707

 Net increase (decrease) in standardized measures

 (121,369)

 (6,859)

 156,774

 9,273

 134,400

 7,408

 Standardized measure, end of year

 $

 335,288

 $

 17,586

 $

 456,657

 $

 24,445

 $

 299,883

 $

 15,172

 (1)
 On March 15, 2022, Alliance Minerals changed its federal income tax status from a pass-through entity to a taxable entity via a "check the box" election, which became effective January 1, 2022. See Note 7 – Income Tax in our consolidated financial statements for more information.

 SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
 ALLIANCE RESOURCE PARTNERS, L.P.

 CONDENSED BALANCE SHEETS (PARENT)
 DECEMBER 31, 2023 AND 2022
 (In thousands, except unit data)

 2023

 2022*

 ASSETS

 CURRENT ASSETS:

 Cash and cash equivalents

 $

 2,043

 $

 2,174

 Total current assets

 2,043

 2,174

 OTHER ASSETS:

 Investments in consolidated subsidiaries

 1,894,158

 1,720,499

 Total other assets

 1,894,158

 1,720,499

 TOTAL ASSETS

 $

 1,896,201

 $

 1,722,673

 LIABILITIES AND PARTNERS' CAPITAL

 CURRENT LIABILITIES:

 Accrued taxes other than income taxes

 $

 $

 Total current liabilities

 Total liabilities

 PARTNERS' CAPITAL:

 Limited Partners - Common Unitholders 127,125,437 and 127,195,219 units outstanding, respectively

 1,896,027

 1,656,025

 General Partner's interest

 —

 66,548

 Total Partners' Capital

 1,896,027

 1,722,573

 TOTAL LIABILITIES AND PARTNERS' CAPITAL

 $

 1,896,201

 $

 1,722,673

 * Recast as discussed in "Item 8. Financial Statements and Supplementary Data—Note 1 – Organization and Presentation" of this Annual Report on Form 10-K.
 See accompanying notes.

 CONDENSED STATEMENTS OF OPERATIONS (PARENT)
 (In thousands, except unit and per unit data)

 2023

 2022*

 2021*

 EXPENSES:

 General and administrative

 $

 $

 —

 $

 —

 Total operating expenses

 —

 —

 LOSS FROM OPERATIONS

 ( 151)

 —

 —

 Interest income

 —

 —

 Equity in earnings of consolidated subsidiaries

 630,212

 NET INCOME ATTRIBUTABLE TO ARLP

 $

 $

 $

 NET INCOME ATTRIBUTABLE TO ARLP

 GENERAL PARTNER

 $

 1,384

 $

 9,010

 $

 4,614

 LIMITED PARTNERS

 $

 628,734

 $

 577,190

 $

 178,157

 EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED

 $

 4.81

 $

 4.39

 $

 1.36

 WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC AND DILUTED

 127,180,312

 * Recast as discussed in "Item 8. Financial Statements and Supplementary Data—Note 1 – Organization and Presentation" of this Annual Report on Form 10-K.
 See accompanying notes.

 CONDENSED STATEMENTS OF CASH FLOWS (PARENT)
 (In thousands)

 2023

 2022*

 2021*

 CASH FLOWS FROM OPERATING ACTIVITIES:

 $

 364,448

 $

 196,348

 $

 52,157

 CASH FLOWS FROM FINANCING ACTIVITIES:

 Distributions paid to Partners

 ( 364,579)

 ( 196,347)

 ( 52,158)

 Net cash used in financing activities

 ( 364,579)

 ( 196,347)

 ( 52,158)

 NET CHANGE IN CASH AND CASH EQUIVALENTS

 ( 131)

 ( 1)

 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 2,174

 2,173

 2,174

 CASH AND CASH EQUIVALENTS AT END OF PERIOD

 $

 2,043

 $

 2,174

 $

 2,173

 * Recast as discussed in "Item 8. Financial Statements and Supplementary Data—Note 1 – Organization and Presentation" of this Annual Report on Form 10-K.
 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 have been recast as a result of the JC Resources Acquisition as discussed in "Item 8. Financial Statements and Supplementary Data—Note 1 – Organization and Presentation" of this Annual Report on Form 10-K. 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 Alliance Coal and the Intermediate Partnership, ARLP is a guarantor of the Credit Facility and the Senior Notes discussed in "Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt" of this Annual Report on Form 10-K. In addition to these guarantees, ARLP has provided guarantees on surety indemnity agreements and financially guaranteed certain coal supply agreements. The duration of these guarantees varies. The maximum undiscounted potential future payment obligation for our guarantees of certain coal supply agreements as of December 31, 2023 is approximately $ 75.1 million. These guarantees provide for compensation to customers based on additional cost to the customer to replace any contracted tons that our subsidiaries fail to deliver. We do not expect to make any payments under these guarantees.

 3. CASH DISTRIBUTIONS RECEIVED

 We received distributions of $ 364.6 million, $ 196.3 million and $ 52.2 million from our consolidated subsidiaries during the years ended December 31, 2023, 2022, and 2021, respectively.

 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 CEO and CFO, as appropriate, to allow for timely decisions regarding required disclosures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the CEO and CFO, 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, 2023. Based on this evaluation, the CEO and CFO concluded that these controls and procedures are effective as of December 31, 2023.

 Our management, including the CEO and CFO, 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, 2023 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, 2023. In making this assessment, management used the criteria set forth by COSO in Internal Control — Integrated Framework (2013). Based on its assessment, management concluded that, as of December 31, 2023, the ARLP Partnership's internal control over financial reporting was effective based on those criteria, and management believes that we have no material internal control weaknesses in our financial reporting process.

 Grant Thornton 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, 2023, 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, 2023 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 Board of Directors of Alliance Resource Management GP, LLC
 and Unitholders of Alliance Resource Partners, L.P.

 Opinion on internal control over financial reporting
 We have audited the internal control over financial reporting of Alliance Resource Partners, L.P. (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2023, and our report dated February 23, 2024 expressed an unqualified opinion on those financial statements.

 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 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/ GRANT THORNTON LLP

 Tulsa, Oklahoma

 ITEM 9B. OTHER INFORMATION

 None of our directors or officers adopted, modified or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the three months ended December 31, 2023, as such terms are defined under Item 408(a) of Regulation S-K.

 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

 Chairman, President and Chief Executive Officer

 Former Senior Vice President and Chief Financial Officer

 Megan J. Cordle

 Vice President, Controller and Chief Accounting Officer

 Senior Vice President, General Counsel and Secretary

 Senior Vice President and Chief Financial Officer

 Robert G. Sachse

 Executive Vice President

 Senior Vice President; also President, Alliance Minerals, LLC

 Timothy J. Whelan

 Senior Vice President - Sales and Marketing of Alliance Coal, LLC

 D. Andrew Woodward

 Senior Vice President - New Ventures

 Senior Vice President and Chief Operating Officer

 Director and Member of Audit, Compensation and Conflicts Committees

 Director and Member of Audit, Compensation and Conflicts* Committees

 Director and Member of Audit, Compensation* and Conflicts Committees

 Director and Member of Audit* and Compensation Committees

 * Indicates Chairman of Committee.

 Joseph W. Craft III has been President, 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 Director of the National Mining Association, and a Director and former Chairman of 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 the 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 was Senior Vice President and CFO from October 2003 through his retirement on March 31, 2023. 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. Mr. Cantrell announced his retirement effective March 31, 2023.

 Megan J. Cordle became Vice President, Controller and Chief Accounting Officer in March 2022. Since joining the Partnership in October 1999, Ms. Cordle has held several positions of increasing responsibility, serving as Vice President Assistant Controller prior to her current position. She held the position of Audit Manager with Deloitte & Touche LLP prior to joining the Partnership. She is a certified public accountant and holds a Bachelor of Science in Business Administration degree with a major in Accounting from the University of Tulsa.

 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.

 Cary P. Marshall became Senior Vice President and CFO in April 2023. Prior to his current position, Mr. Marshall previously served as Vice President, Corporate Finance and Treasurer since May 2003. Mr. Marshall joined Alliance in 1993 and has held several positions with increasing responsibilities in the finance and marketing areas. Mr. Marshall joined Alliance's predecessor, MAPCO Inc. in 1989 and held a variety of corporate finance positions. Mr. Marshall is an alumnus of Southern Methodist University, where he received a Bachelor of Business Administration degree and a Master of Business Administration degree.

 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 in December 2019 and also serves as President of the Partnership'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 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.

 Timothy J. Whelan has been Senior Vice President - Sales and Marketing of Alliance Coal, LLC since May 2013. Since joining the Partnership 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.

 D. Andrew Woodward became Senior Vice President – New Ventures in September 2022. Prior to joining the Partnership, Mr. Woodward most recently served as Chief Executive Officer of Blueknight Energy Partners, L.P. (NASDAQ: BKEP/BKEPP) where he led the partnership's strategy, commercial activities and a successful sale of the business in August 2022. Prior to Blueknight, Mr. Woodward was the principal financial officer and Vice President, Finance and Treasurer of Andeavor Logistics, L.P. (NYSE: ANDX). Prior to this position, Mr. Woodward held various positions in corporate development, finance and investor relations at Andeavor (NYSE: ANDV), now Marathon Petroleum Corp. (NYSE: MPC). Before joining Andeavor, Mr. Woodward served as Vice President at RBC Capital Markets within its energy investment banking group. Mr. Woodward received his Bachelor of Arts in economics and philosophy from Colorado College and his Master of Business Administration from the University of Texas.

 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 held a variety of positions with the company prior to his appointment 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 Inc. and was engaged in the private practice of law. Mr. Carter previously served on the board of directors, the audit committee and as chairman of the compensation committee of Community Trust Bancorp, Inc. (NASDAQ: CTBI). Mr. Carter also previously served as chairman of the National Council of Coal Lessors for 12 years, as chairman of the West Virginia Chamber of Commerce, and 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's 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 Master of Business Administration from Rockhurst University. Mr. Druten previously served as Chairman of the Board of Directors of Kansas City Southern Industries, Inc. (NYSE: KSU), a transportation and financial services company, and was Chairman of its executive committee and a member of its compensation committee and nominating and governance committees, and now serves as a trustee of the voting trust holding KSU pending the Surface Transportation Board's review and approval of KSU's recent combination with Canadian Pacific Railway Limited. 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 its audit committee and also served on its 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 the 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 the 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 was 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. 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 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. We believe this leadership structure of the Board of Directors is appropriate for the Partnership given Mr. Craft's extensive knowledge of our industries, 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 or, in the case of Mrs. Cordle, the CFO, 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 the 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 the consideration of diversity in identifying director nominees, but has endeavored to assemble a talented 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 and the Exchange Act (i.e., Forms 10-K, 10-Q, and 8-K);

 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 2023. 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, 2023, (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. A copy of the Audit Committee charter 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) 295-7673. 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, Grant Thornton, is responsible for expressing an opinion on the conformity of the audited financial statements with GAAP. The Audit Committee reviewed with Grant Thornton 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 PCAOB and the SEC.

 The Audit Committee received written disclosures and the letter from Grant Thornton required by applicable requirements of the PCAOB Rule 3526, "Communication with Audit Committees Concerning Independence," and has discussed with Grant Thornton 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, 2023 for filing with the SEC.

 Members of the Audit Committee:

 Wilson M. Torrence, Chairman

 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) 295-7673. 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. There were no such amendments or waivers during the year ended December 31, 2023.

 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 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 on a review of the copies of the forms furnished to us and written representations from certain reporting persons, we believe that during 2023 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), with the following exception: a Form 3/A was filed on November 7, 2023 for Ms. Kathleen Mowry, who beneficially owns more than ten percent of our common units, to correct her reported beneficial ownership in her initial Form 3 filed on June 5, 2018.

 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 Named Executive Officers, each of whom is named in the Summary Compensation Table. Our Named Executive Officers are employees of our operating subsidiary, Alliance Coal. We do not currently, nor did we during the 2023 calendar year, maintain employment agreements with any of our Named Executive Officers.

 Compensation Objectives and Philosophy

 The compensation of our Named Executive Officers is designed to achieve three key objectives: (i) provide a competitive compensation opportunity to allow us to recruit and retain key management talent, (ii) align executive officers' interests with unitholder interests and (iii) motivate and reward the executive officers for creating sustainable, capital-efficient growth in available cash to maximize unitholder returns. 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 on 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

 Role of the Compensation Committee

 The 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 the 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 2023, the Compensation Committee and the Chairman, President and CEO have been substantially aligned on decisions regarding the 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 2023 (which was the same peer group applicable to the 2022 calendar year) included Alpha Metallurgical Resources, Inc., Arch Resources, Inc., Consol Energy, Inc., Natural Resource Partners L.P., Peabody Energy Corporation, and Warrior Met Coal, Inc. In assessing the competitiveness of our executive compensation program for 2023, 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 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 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, including DERs.

 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.

 All executive officers, including the Named Executive Officers, are entitled to customary benefits available to our employees generally, including group medical, dental, and life insurance and participation in our 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. Each of our Named Executive Officers (including Mr. Craft) also received supplemental retirement benefits through the SERP in 2023, which are described in more detail below.

 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 during the 2023 year.

 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 businesses. (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 relation 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 2023, the Compensation Committee approved a minimum financial performance target of $756.2 million in EBITDA from current

 operations, normalized by excluding any charges for unit-based and directors' compensation. For 2023, we exceeded the minimum performance target.

 Individual awards to our Named Executive Officers each year are determined by 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 2024 will be based on adjusted 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 2024 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.

 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) cash awards. The Compensation Committee has the 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 has not been granted an award under the LTIP since 2005, 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 distributed upon satisfaction of the applicable vesting requirements is reduced to cover the income tax withholding requirement for each individual participant based on 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 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 and 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. The compensation expense associated with LTIP grants is recognized over the vesting period in accordance with FASB 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 the 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.

 Grants for 2023 under the LTIP, made January 27, 2023, will cliff vest on January 1, 2026, provided we achieve a target level of aggregate EBITDA for current operations, excluding any charges for unit-based and directors' compensation, for the period January 1, 2023 through December 31, 2025. Regardless of achieving the EBITDA target, the 2023 grants have a minimum value guarantee of either $10.27 or $15.41 per unit. Grants for 2024 under the LTIP, made January 24, 2024, will cliff vest on January 1, 2027, provided we achieve a target level of aggregate EBITDA for current operations, excluding any charges for unit-based and directors' compensation, for the period January 1, 2024 through December 31, 2026. Regardless of achieving the EBITDA target, the 2024 grants have a minimum value guarantee of either $10.63 or $15.95 per unit. The LTIP provides the Compensation Committee with the 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.

 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

 The SERP is sponsored by Alliance Coal. Participation in the SERP aligns the interest of each participant 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 could amend or terminate the SERP at any time. All of our Named Executive Officers currently participate in the SERP.

 On December 14, 2023 the Compensation Committee approved termination of the SERP, and authorized distribution of accounts to participants on December 15, 2024 or as soon thereafter as practical. Account settlements must be delayed at least one year according to termination rules governing the SERP. The accounts will continue to accrue benefits in accordance with plan terms until distributed.

 Under the terms of the SERP, a participant was 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 would be 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 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.

 This allocation for the year in which a participant's termination occurred 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 annual physical medical exams, and are reviewed annually by the Compensation Committee.

 Clawback Policy

 We maintain the Alliance Resource Partners, L.P. Incentive-Based Compensation Recoupment Policy (the "Clawback Policy"), which is administered by the Compensation Committee. The Clawback Policy authorizes the Compensation Committee to recoup incentive compensation in the event of a restatement of financial statements. A copy of the Clawback Policy is filed as Exhibit 97.1 to this Annual Report on Form 10-K.

 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, 2023.

 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

 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.

 Summary Compensation Table

 Non-Equity

 Unit

 Incentive Plan

 All Other

 Name and Principal

 Salary

 Bonus

 Awards

 Position (1)

 Year

 ($)(2)

 ($)(3)

 ($)(4)

 ($)(5)

 ($)(6)

 Total

 2023

 —

 —

 —

 —

 President, Chief Executive

 2022

 —

 —

 —

 —

 Officer and Chairman

 2021

 —

 —

 —

 —

 Cary P. Marshall,

 2023

 293,269

 26,340

 666,555

 220,000

 63,368

 1,269,532

 Senior Vice President and

 Chief Financial Officer

 Brian L. Cantrell,

 2023

 105,231

 789,241

 —

 —

 6,548

 901,020

 Former Senior Vice President and

 2022

 304,000

 117,723

 —

 340,000

 54,089

 815,812

 Chief Financial Officer

 2021

 309,846

 —

 567,182

 250,000

 30,443

 1,157,471

 2023

 365,000

 50,966

 634,461

 285,000

 83,247

 1,418,674

 Senior Vice President,

 2022

 362,693

 152,898

 629,541

 365,000

 86,600

 1,596,732

 General Counsel and Secretary

 2021

 351,635

 —

 722,394

 365,000

 41,768

 1,480,797

 2023

 500,000

 1,000,000

 734,083

 341,000

 223,014

 2,798,097

 Senior Vice President; also

 2022

 500,000

 1,000,000

 1,040,560

 531,920

 204,252

 3,276,732

 President Alliance Minerals, LLC

 2021

 509,615

 500,000

 1,194,061

 540,000

 152,688

 2,896,364

 2023

 430,000

 58,393

 734,083

 345,000

 101,155

 1,668,631

 Senior Vice President and

 2022

 427,000

 175,179

 728,391

 460,000

 87,433

 1,878,003

 Chief Operating Officer

 2021

 411,769

 —

 835,818

 400,000

 43,588

 1,691,175

 (1)
 Mr. Cantrell retired from his position as Senior Vice President and CFO on March 31, 2023. Mr. Marshall was appointed Senior Vice President and CFO effective April 1, 2023.

 (2)
 Amounts represent the salary earned by each Named Executive Officer for the respective year. The amounts for Mr. Cantrell include $23,385 paid in 2023 for unused vacation upon his retirement on March 31, 2023.

 (3)
 The amount for Mr. Marshall represents the second payment of the 2020 service-based vesting LTIP awards which was paid in cash in February 2023. The amounts for Messrs. Cantrell, Davis and Wynne represent the first and second payments of the 2020 service-based vesting LTIP awards which were paid in cash in February 2022 and February 2023, respectively, as well as a cash bonus paid in 2023 to Mr. Cantrell. The amounts for Mr. Tholen represent the payments of his 2019 and 2020 service-based vesting LTIP awards which were paid in cash in February 2022 and 2023, respectively, and the last installment of his signing bonus paid in 2021.

 (4)
 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 16 – Common Unit-Based Compensation Plans," to each Named Executive Officer under the LTIP in the respective year. 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. 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 and (c) perquisites in excess of $10,000. A reconciliation of the 2023 amounts is as follows:

 Profit Sharing Plan

 Employer

 SERP ($)

 Contribution ($)

 Perquisites (a)

 Total ($)

 —

 —

 $

 —

 —

 24,632

 23,461

 15,275

 63,368

 —

 6,548

 —

 6,548

 56,847

 26,400

 —

 83,247

 196,614

 26,400

 —

 223,014

 62,905

 26,400

 11,850

 101,155

 a)
 For Mr. Marshall, perquisites and other personal benefits totaling $15,275 comprise tax preparation fees of $13,625 and other perquisites of $1,650. For Mr. Wynne, perquisites and other personal benefits comprise tax preparation fees of $11,850.

 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)

 10,273

 216,966

 11,676

 224,062

 11,982

 239,041

 10,978

 245,907

 44,909

 925,976

 30,945

 —

 666,555

 —

 1,515

 31,997

 —

 1,722

 33,045

 —

 1,767

 35,252

 —

 1,620

 36,288

 (2)

 —

 1,163

 24,632

 January 27, 2023

 February 7, 2024

 220,000

 —

 —

 —

 220,000

 30,945

 7,787

 827,769

 1,543

 32,588

 1,543

 32,588

 29,455

 —

 634,461

 —

 2,370

 50,054

 —

 2,693

 51,679

 —

 2,764

 55,142

 —

 2,532

 56,717

 (2)

 —

 2,684

 56,847

 January 27, 2023

 February 7, 2024

 285,000

 —

 —

 —

 285,000

 29,455

 13,043

 904,900

 —

 734,083

 —

 1,855

 39,178

 —

 2,108

 40,453

 —

 2,163

 43,152

 —

 1,982

 44,397

 (2)

 —

 9,283

 196,614

 January 27, 2023

 February 7, 2024

 341,000

 —

 —

 —

 341,000

 17,391

 1,097,877

 —

 734,083

 —

 2,366

 49,970

 —

 2,690

 51,621

 —

 2,760

 55,062

 —

 2,529

 56,650

 (2)

 —

 2,970

 62,905

 January 27, 2023

 February 7, 2024

 345,000

 —

 —

 —

 345,000

 13,315

 $

 1,010,291

 (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 the STIP are subject to our achieving an annual financial performance target each year. However, determination of individual awards under the STIP is based on 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)
 These amounts represent awards pursuant to our STIP. On January 27, 2023, the Compensation Committee set the EBITDA target amount for use in determining the total plan payout for 2023. The discretionary payout allocations to all participating employees is determined after the year is completed. 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. The grants include a minimum value guarantee. 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. The grants include a minimum value guarantee. Mr. Cantrell did not receive an LTIP award in 2023 as his retirement in March 2023 was prior to the vesting of these grants. 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 15, 2023 to our Named Executive Officers using a value of $21.54 per unit, the closing unit price on the grant 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. The grants include a minimum value guarantee. Please see "Item 11. Compensation Discussion and Analysis—Compensation Components— Equity Awards under the LTIP."

 During the fourth quarter of 2020, it was determined the vesting performance requirement with respect to the 2020 Grants was not probable of being satisfied, and previously recognized expense for the 2020 Grants was reversed. In December 2020, 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 vested on January 1, 2023.

 In addition, in 2020 the Compensation Committee approved new 2020 service-based vesting LTIP awards. These awards are denominated in cash were paid 75% in February 2022 and 25% in February 2023 for all participants other than Mr. Tholen. Mr. Tholen was granted a service-based vesting award denominated in cash and was paid one-half in February 2022 and one-half in February 2023.

 These 2020 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. They are described herein to provide details regarding the LTIP awards that are included below within the table titled "Units Vested Table for 2023."

 Supplemental Executive Retirement Plan

 Under the terms of the SERP, participants were 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 would be 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."

 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 ($)

 Compensation ($)(1)

 2023

 100.0%

 2023

 319,609

 1,269,532

 25.2%

 2023

 894,472

 901,020

 99.3%

 2023

 415,966

 1,418,674

 29.3%

 2023

 1,500,000

 2,798,097

 53.6%

 2023

 488,393

 1,668,631

 29.3%

 (1)
 Percentages were calculated using the base salary and bonus of the Named Executive Officers. The bonus we provided in 2023 to our Named Executive Officers was the second payment of the 2020 service-based vesting LTIP awards which were paid in cash in February 2023 and a separate cash bonus to Mr. Cantrell.

 Outstanding Equity Awards at 2023 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)

 —

 $

 —

 124,278

 2,632,208

 —

 —

 196,447

 4,160,748

 310,103

 6,567,982

 227,292

 4,814,044

 (1)
 Amounts represent restricted units awarded under the LTIP that were not vested as of December 31, 2023. Subject to our achieving financial performance targets, these units will vest as follows:

 January 1,

 Name

 2024

 2025

 2026

 —

 —

 —

 64,160

 29,173

 30,945

 —

 —

 —

 119,800

 47,192

 29,455

 198,020

 78,003

 138,610

 54,602

 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 $21.18 per unit, the closing price of our common units on December 29, 2023, the final market trading day of 2023.

 Units Vested Table for 2023

 Unit Awards

 Number of Units

 Acquired on Vesting

 Value Realized on

 Name

 (#)(1)

 Vesting ($)(1)

 —

 $

 —

 51,842

 1,053,429

 69,152

 1,405,169

 88,078

 1,789,745

 —

 —

 101,629

 2,065,101

 (1)
 Amounts represent the number and value of restricted units granted under the LTIP that vested in 2023. All of these units vested on January 1, 2023 and are valued at $20.32 per unit, the closing price on December 30, 2022, the final market trading day of 2022. Please see "Item 11. Compensation Discussion and Analysis—Compensation Components—Equity Awards under the LTIP."

 Nonqualified Deferred Compensation Table for 2023

 Aggregate

 Executive

 Registrant

 Aggregate

 Withdrawals/

 Aggregate

 Contributions

 Contributions

 Earnings

 Distributions

 Balance

 in Last Fiscal

 in Last Fiscal

 in Last Fiscal

 in Last Fiscal

 at Last Fiscal

 Name

 Year ($) (1)

 Year ($) (2)

 Year ($) (3)

 Year ($) (4)

 Year End ($) (5)

 —

 —

 1,224,776

 —

 7,689,463

 —

 24,632

 180,648

 —

 1,158,694

 —

 —

 28,887

 (999,939)

 —

 —

 56,847

 282,507

 —

 1,830,354

 —

 196,614

 221,116

 —

 1,584,688

 —

 62,905

 282,123

 —

 1,833,976

 (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 2023 year.

 (3)
 Amounts represent earnings accrued during 2023 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. The market value of the notional account balance at the end of 2023 and 2022 was $21.18 and $20.32 per common unit, respectively. Earnings were not above-market or preferential.

 (4)
 Amount represents a payout of Mr. Cantrell's SERP notional account balance upon his retirement in March 2023 and was valued $20.27 per unit, representing the closing price of our common units on March 30, 2023.

 (5)
 Amounts represent the Named Executive Officer's cumulative notional account balance of phantom units valued at $21.18, the closing price of our common units on December 29, 2023, the final market-trading day of 2023. 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. Marshall, $253,302; Mr. Davis, $745,813; Mr. Tholen; $657,614; and Mr. Wynne, $673,959. These amounts contributed since inception, other than the amounts contributed in the last fiscal year, were previously reported as compensation in the Summary Compensation Table in previous years if the Named Executive Officer was included in those years. On December 14, 2023 the Compensation Committee approved termination of the SERP, and authorized distribution of accounts to participants on December 15, 2024 or as soon thereafter as practical. As a result, all SERP accounts are expected to be settled prior to the end of the 2024 year. The accounts will continue to accrue benefits in accordance with plan terms until distributed.

 Narrative Discussion Relating to the Nonqualified Deferred Compensation Table for 2023

 Supplemental Executive Retirement Plan

 Under the terms of the SERP, participants were 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 would be 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 (other than Mr. Cantrell, described below) 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 2023" 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 2023 Fiscal Year End Table", in each case assuming the triggering event occurred on December 31, 2023. 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.

 None of our Named Executive Officers are eligible for severance or change in control benefits outside of their SERP payments and potential equity award acceleration described above.

 In connection with Mr. Cantrell's retirement in 2023, he received a settlement of his SERP account valued at $999,939 and a $750,000 cash bonus.

 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 Compensation Committee with the concurrence of Mr. Craft, who indirectly owns our general partner. Mr. Craft, our only employee director, received no director compensation for 2023, 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.

 Director Compensation Table for 2023

 Change in Pension

 Non-Equity

 Value and

 Fees earned

 Unit

 Option

 Incentive Plan

 Nonqualified Deferred

 All Other

 or Paid in

 Awards

 Awards

 Name

 Cash ($)

 ($) (2)(3)

 ($)(1)

 ($)(1)

 Earnings ($)(1)

 ($)(1)

 Total ($)

 $

 195,000

 $

 36,930

 $

 —

 $

 —

 $

 —

 $

 —

 $

 231,930

 195,000

 —

 —

 —

 —

 —

 195,000

 215,000

 30,332

 —

 —

 —

 —

 245,332

 185,000

 —

 —

 —

 —

 —

 185,000

 (1)
 Columns are not applicable to 2023 director compensation.

 (2)
 Amounts represent the grant date fair value of equity awards in 2023 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 16 – Common Unit-Based Compensation Plans"). Please see Narrative to Director Compensation Table, below.

 (3)
 At December 31, 2023, each director had the following number of "phantom" ARLP common units credited to his notional account under the Directors' Deferred Compensation Plan:

 Directors

 Deferred

 Name

 Plan (in Units)

 14,696

 —

 12,064

 —

 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 2023 was $185,000. In addition to the retainer, Mr. Torrence also was entitled to annual cash compensation in 2023 of $30,000 for service as Chairman of the Audit Committee, and Mr. Robinson and Mr. Druten also were entitled to additional annual cash compensation of $10,000 each for service as Chairman of the Compensation Committee and the Conflicts Committee, respectively.

 Prior to 2024, Directors had 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 2023. On December 14, 2023 the Board of Directors approved termination of the Directors' Deferred Compensation Plan, and authorized distribution of accounts on December 15, 2024 or as soon

 thereafter as practical. Termination rules regarding deferred compensation plans required termination of this plan in connection with termination of the SERP.

 Pursuant to the Directors' Deferred Compensation Plan, a notional account was 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 was 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 were made with respect to ARLP common units, an amount equal to such quarterly distribution was 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 could 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 was required prior to each plan year; if no election was made, the account would be paid on the January 1 on or next following the director's separation from service. The Directors' Deferred Compensation Plan was administered by the Compensation Committee, and the Board of Directors reserved the right to change or terminate the plan at any time, provided that accrued benefits under the plan were not impaired.

 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.

 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 2023, our last completed fiscal year:

 The median of the annual total compensation of all employees of our company (other than the CEO) was $109,758.

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

 Based on this information, for 2023 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, 2023, our employee population consisted of approximately 3,595 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 2023.

 We identified our median employee for 2023 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 2023 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in

 annual total compensation of $109,758, comprised of such employee's W-2 compensation of $103,299 and contributions in the amount of $6,459 that we made on the employee's behalf to our 401(k) plan for the 2023 year.

 With respect to the annual total compensation of our CEO, we used the amount reported in the "Total" column of our 2023 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.

 ITEM 12.

 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

 The following table sets forth certain information as of February 8, 2024, 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 128,061,981 common units outstanding as of February 8, 2024.

 Percentage of Common

 Common Units

 Units

 Name of Beneficial Owner

 Beneficially Owned

 Beneficially Owned

 Directors and Executive Officers

 Joseph W. Craft III (1)

 18,800,000

 14.7%

 20,000

 *

 25,628

 *

 7,462

 *

 40,396

 *

 252,193

 *

 262,446

 *

 Cary P. Marshall (2)

 1,077,748

 *

 110,396

 *

 Thomas M. Wynne (3)

 1,284,334

 1.0%

 All directors and executive officers as a group (14 persons)

 22,392,314

 17.5%

 5% Common Unit Holder

 Kathleen Mowry

 16,167,865

 12.6%

 *

 Less than one percent.

 (1)
 The common units attributable to Mr. Craft consist of (i) 18,631,398 common units held directly by him and (ii) 168,602 common units attributable to Mr. Craft's spouse.

 (2)
 The common units attributable to Mr. Marshall consist of common units held through a trust and another entity controlled by him.

 (3)
 The common units attributable to Mr. Wynne consist of (i) 859,940 common units held directly by him and (ii) 424,394 common units held through a trust and another entity controlled by him.

 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 plans

 Plan Category

 as of December 31, 2023

 warrants and rights

 as of December 31, 2023

 Equity compensation plans approved by unitholders:

 Long-Term Incentive Plan

 2,710,344

 N/A

 7,886,556

 Equity compensation plans not approved by unitholders:

 Supplemental Executive Retirement Plan

 785,186

 N/A

 N/A

 Directors' Deferred Compensation

 26,760

 N/A

 N/A

 ITEM 13.

 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

 Omnibus Agreement

 We are party to an omnibus agreement with MGP and AGP, which governs potential competition among us and the other parties to this agreement. Pursuant to the terms of the omnibus agreement, AGP and its affiliates agreed, for so long as Mr. Craft 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, AGP has the ability to purchase businesses, the majority value of which is not mining, marketing or transporting coal, provided AGP offers us the opportunity to purchase the coal assets following the acquisition. The restriction does not apply to the assets retained and business conducted by an affiliate of AGP at the closing of our initial public offering. Except as provided above, AGP and its affiliates are prohibited from engaging in activities wherein they compete directly with us.

 Related-Party Transactions

 In addition to the related-party policies and transactions discussed in "Item 8. Financial Statements and Supplementary Data — Note 1 — Organization and Presentation and Note 20 — Related-Party Transactions" ARLP has the following additional related-party transactions:

 Expense Reimbursements

 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. MGP may determine in its sole discretion the expenses that are allocable to us. Total costs billed to us by MGP and its affiliates were approximately $1.0 million for the year ended December 31, 2023. The executive officers of MGP are employees of and paid by Alliance Coal, and the reimbursement we pay to MGP pursuant to the partnership agreement does not include any compensation expenses associated with them.

 JC Land

 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 $0.3 million for the year ended December 31, 2023 for use of the aircraft.

 Effective August 1, 2013, Alliance Coal entered into an expense reimbursement agreement with JC Land regarding pilots employed by Alliance Coal to operate aircraft owned by Alliance Service, Inc. 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 2023 pursuant to this agreement. Separately, JC Land paid us $0.5 million during 2023 for fuel, pilot travel, etc. paid by us on their behalf.

 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 of the Audit and Compensation Committees—Messrs. Torrence, Carter, Druten and Robinson—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 Grant Thornton LLP is our independent registered public accounting firm for the 2023 year. The following table sets forth fees paid to Grant Thornton LLP during the years ended December 31, 2023 and 2022:

 2023

 2022

 Audit Fees (1)

 $

 $

 Audit-related fees (2)

 Tax fees (3)

 —

 —

 All other fees

 —

 —

 Total

 $

 $

 (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 consist primarily of attest services related to financial reporting that are not required by statue or regulation but can also include accounting consultations and audits in connections with acquisitions.

 (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.

 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

 Page

 Report of Independent Registered Public Accounting Firm-Grant Thornton LLP (PCAOB ID Number 248)

 Consolidated Balance Sheets

 Consolidated Statements of Income

 Consolidated Statements of Comprehensive Income

 Consolidated Statements of Cash Flows

 Consolidated Statement of Partners' Capital

 Notes to Consolidated Financial Statements

 1. Organization and Presentation

 2. Summary of Significant Accounting Policies

 3. Acquisitions

 4. Inventories

 5. Property, Plant and Equipment

 6. Long-Term Debt

 7. Income Taxes

 8. Leases

 9. Fair Value Measurements

 10. Partners' Capital

 11. Variable Interest Entities

 12. Equity Investments

 13. Revenue From Contracts With Customers

 14. Earnings Per Limited Partner Unit

 15. Employee Benefit Plans

 16. Common Unit-Based Compensation Plans

 17. Supplemental Cash Flow Information

 18. Asset Retirement Obligations

 19. Accrued Workers' Compensation and Pneumoconiosis Benefits

 20. Related-Party Transactions

 21. Commitments and Contingencies

 22. Concentration of Credit Risk and Major Customers

 23. Segment Information

 Supplemental Oil & Gas Reserve Information (Unaudited)

 (a)(2) Financial Statement Schedule.

 Schedule I – Condensed Financial Information of Registrant

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

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

 Incorporated by Reference

Number

 Exhibit Description

 Form

 SEC
File No. and
Film No.

 Filing Date

 Filed
Herewith*

 3.1

 Fourth Amended and Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.

 17990766

 3.2

 07/28/2017

 3.2

 Amended and Restated Agreement of Limited Partnership of Alliance Resource Operating Partners, L.P.

 583595

 3.2

 03/29/2000

 3.3

 Amended and Restated Certificate of Limited Partnership of Alliance Resource Partners, L.P.

 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.

 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.

 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.

 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.

 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.

 1883834

 3.7

 06/06/2018

 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 3.2).

 17990766

 3.2

 07/28/2017

 Incorporated by Reference

Number

 Exhibit Description

 Form

 SEC
File No. and
Film No.

 Filing Date

 Filed
Herewith*

 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.

 17798539

 4.1

 04/24/2017

 4.3

 Form of 7.500% Senior Note due 2025 (included in Exhibit 4.2).

 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.

 000-26823, 23666549

 4.4

 02/24/2023

 10.1

 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

 583595

 10.3

 03/29/2000

 10.2

 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.

 583595

 10.4

 03/29/2000

 10.3(1)

 Alliance Coal, LLC Short-Term Incentive Plan

 583595

 10.12

 03/29/2000

 10.4(1)

 Alliance Coal, LLC Supplemental Executive Retirement Plan

 S-8

 333-85258
 02595143

 99.2

 04/01/2002

 10.5(1)

 Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors

 S-8

 333-85258
 02595143

 99.3

 04/01/2002

 10.6

 Third Amended and Restated Charter for the Audit Committee of the Board of Directors

 10.7

 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

 061017824

 10.1

 08/09/2006

 10.8

 Administrative Services Agreement dated May 15, 2006 among Alliance Resource Partners, L.P., Alliance Resource Management GP, LLC, Alliance Resource Holdings II, Inc.,

 061017824

 10.2

 08/09/2006

 Incorporated by Reference

Number

 Exhibit Description

 Form

 SEC
File No. and
Film No.

 Filing Date

 Filed
Herewith*

 Alliance Holdings GP, L.P. and Alliance GP, LLC

 10.9(1)

 First Amendment to the Alliance Coal, LLC Short-Term Incentive Plan

 07660999

 10.52

 03/01/2007

 10.10(1)

 Second Amendment to the Alliance Coal, LLC Short-Term Incentive Plan

 08654096

 10.53

 02/29/2008

 10.11(1)

 Amended and Restated Alliance Coal, LLC Supplemental Executive Retirement Plan dated as of January 1, 2011

 11645603

 10.40

 02/28/2011

 10.12(1)

 Amended and Restated Alliance Resource Management GP, LLC Deferred Compensation Plan for Directors dated as of January 1, 2011

 11645603

 10.42

 02/28/2011

 10.13

 Amended and Restated Charter for the Compensation Committee of the Board of Directors dated January 27, 2023.

 10.14

 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.

 101000555

 10.1

 08/09/2010

 10.15

 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

 141277053

 10.3

 12/10/2014

 10.16(1)

 The Amended and Restated Alliance Coal, LLC Long-Term Incentive Plan as amended by the Third Amendment and Fourth Amendment

 161460619

 10.46

 02/26/2016

 10.17

 First Amendment to the Receivables Financing Agreement, dated as of December 4, 2015

 161634229

 10.1

 05/10/2016

 10.18

 Second Amendment to the Receivables Financing Agreement, dated as of February 24, 2016

 161634229

 10.2

 05/10/2016

 10.19

 Third Amendment to the Receivables Financing Agreement, dated as of December 2, 2016

 17636362

 10.45

 02/24/2017

 Incorporated by Reference

Number

 Exhibit Description

 Form

 SEC
File No. and
Film No.

 Filing Date

 Filed
Herewith*

 10.20

 Fourth Amendment to the Receivables Financing Agreement, dated as of November 27, 2017

 18634680

 10.47

 02/23/2018

 10.21

 Fifth Amendment to the Receivables Financing Agreement, dated as of January 17, 2018

 18634680

 10.48

 02/23/2018

 10.22

 Sixth Amendment to the Receivables Financing Agreement, dated as of June 19, 2018

 18994075

 10.2

 08/06/2018

 10.23

 Seventh Amendment to the Receivables Financing Agreement, dated as of January 16, 2019

 19624803

 10.52

 02/22/2019

 10.24

 Eighth Amendment to the Receivables Financing Agreement, dated as of October 22, 2019.

 191192460

 10.2

 11/05/2019

 10.25

 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.

 20711345

 10.1

 03/13/2020

 10.26

 Fifth Amendment to the Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan.

 201385345

 10.1

 12/14/2020

 10.27

 Ninth Amendment to the Receivables Financing Agreement, dated as of January 15, 2021.

 21663570

 10.64

 02/23/2021

 10.28

 Tenth Amendment to the Receivables Financing Agreement, dated as of January 14, 2022.

 22677260

 10.57

 02/25/2022

 10.29

 Eleventh Amendment to the Receivables Financing Agreement, dated as of January 13, 2023.

 23666549

 10.54

 02/24/2023

 10.30

 Thirteenth Amendment to the Receivables Financing Agreement, dated as of January 12, 2024.

 10.31

 Credit Agreement, dated as of January 13, 2023, among Alliance Coal, LLC, as borrower, Alliance Resource Operating Partners, L.P., Alliance Resource Partners, L.P., UC Coal, LLC, UC Mining, LLC, UC Processing, LLC and MGP II, LLC as additional Alliance entities and the initial lenders, initial issuing banks and swingline bank named therein, PNC Bank, National Association as administrative agent and collateral agent and PNC Capital Markets LLC, BOKF, NA DBA Bank of Oklahoma, Fifth Third Bank, National Association, Old National Bank and Trust Securities, Inc. as joint lead arrangers and joint bookrunners and the other institutions named therein as documentation agents.

 23540292

 10.1

 01/20/2023

 10.32

 Sixth Amendment to the Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan.

 221401012

 10.1

 11/18/2022

 14.1

 Code of Ethics for Principal Executive Officer and Senior Financial Officers

 13656028

 14.1

 03/01/2013

 21.1

 List of Subsidiaries.

 23.1

 Consent of Grant Thornton LLP.

 23.2

 Consent of Cawley, Gillespie & Associates, Inc.

 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, 2024, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 31.2

 Certification of Cary P. Marshall, 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, 2024, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 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, 2024, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 32.2

 Certification of Cary P. Marshall, 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, 2024, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 95.1

 Federal Mine Safety and Health Act Information

 96.1

 Henderson/Union Resources SEC S-K 1300 Technical Report Summary dated February 2024.

 96.2

 River View Complex SEC S-K 1300 Technical Report Summary February 2024.

 96.3

 Hamilton Mine SEC S-K 1300 Technical Report Summary dated February 2022.

 10-K/A

 221205681

 96.3

 08/26/2022

 96.4

 Gibson South Mine SEC S-K 1300 Technical Report Summary dated February 2022.

 10-K/A

 221205681

 96.4

 08/26/2022

 96.5

 Tunnel Ridge Mine SEC S-K 1300 Technical Report Summary dated February 2023.

 97.1

 Alliance Resource Partners, L.P. Incentive Based Compensation Recoupment Policy

 99.1

 Report of Cawley, Gillespie & Associates, Inc., dated December 7, 2023

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

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

 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, 2024.

 ALLIANCE RESOURCE PARTNERS, L.P.

 By:

 Alliance Resource Management GP, LLC

 its general partner

 /s/ 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)

 /s/ Cary P. Marshall

 Senior Vice President and
Chief Financial Officer (Principal Financial Officer)

 /s/ Megan J. Cordle

 Vice President, Controller and
Chief Accounting Officer (Principal Accounting Officer)

 Megan J. Cordle

 /s/ Nick Carter

 Director

 /s/ Robert J. Druten

 Director

 /s/ John H. Robinson

 Director

 /s/ Wilson M. Torrence

 Director