2 0 23
ANNUAL REPORT
ALLIANCE RESOURCE PARTNERS, L.P.
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
(State or Other Jurisdiction of
Incorporation or Organization)
73-1564280
(IRS Employer Identification No.)
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
Common Units representing limited partner interests
Trading Symbol
ARLP
Name of Each Exchange On Which Registered
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 ☐
(Do not check if smaller reporting company)
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
TABLE OF CONTENTS
PART I
Item 1.
Item 1A.
Item 1B.
Item 1C.
Item 2.
Item 3.
Item 4.
Business
Risk Factors
Unresolved Staff Comments
Cybersecurity
Properties
Legal Proceedings
Mine Safety Disclosures
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of
Equity Securities
[Reserved]
Management's Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
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
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Supplemental Oil & Gas Reserve Information (Unaudited)
Schedule I – Condensed Financial Information of Registrant
Changes in and Disagreements with Accountant on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance of the General Partner
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder
Matters
Item 13.
Item 14.
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
Item 15.
Exhibits and Financial Statement Schedules
PART IV
ii
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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
ACE Rule
Acquisitions and Divestitures
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
AHGP
Alliance GP, LLC
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
AllDale III
Our subsidiary, AllDale Minerals II, LP
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
ARLP
Alliance Resource Holdings, Inc.
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
Ascend
ASI
Accounting Standards Codification
Ascend Elements, Inc.
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
Bituminous coal
September 9, 2022
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
Btu
CAA
CAIR
Best System of Emission Reduction
British thermal unit
Federal Clean Air Act
Clean Air Mercury Rule
Cavalier Minerals
Our subsidiary, Cavalier Minerals JV, LLC
CCB
CCRs
CEO
Coal combustion by-products
Coal combustion residues
Chief Executive Officer
CERCLA
Federal Comprehensive Environmental Response, Compensation and Liability Act
CEQ
CFO
CGA
Council on Environmental Quality
Chief Financial Officer
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
COP27
COP28
26th Conference of the Parties
27th Conference of the Parties
28th Conference of the Parties
Corps of Engineers
United States Army Corps of Engineers
COSO
CPP
Committee of Sponsoring Organizations of the Treadway Commission
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
CTO
CWA
DERs
CSX Transportation, Inc.
Chief Technology Officer
Federal Clean Water Act
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
DOL
EGUs
ELG
EPA
EPU
ESA
EV
Excel
Division of Mine Permits
U.S. Department of Labor
Electric generating units
Effluent Limitations Guidelines and Standards
United States Environmental Protection Agency
Earnings per limited partner unit
Endangered Species Act
Electric vehicle
Excel Mining, LLC
Exchange Act
Securities Exchange Act of 1934
FASB
FIPs
FMSHA
Francis
GAAP
GFANZ
GHG
Gibson
Financial Accounting Standards Board
Federal Implementation Plans
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
Generally Accepted Accounting Principles
Glasgow Financial Alliance for Net Zero
Greenhouse gas
Our subsidiary, Gibson County Coal, LLC
Gibson South
Our subsidiary, Gibson County Coal (South), LLC
vi
Grant Thornton
Grant Thornton LLP
Gross Acres
Hamilton
Haymaker
High-sulfur coal
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.
Our subsidiary, Hamilton County Coal, LLC
Haymaker Minerals & Royalties II, LLC
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)
Inferred 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.
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
IRAs
IRS
Resource Partners, L.P.
Individual retirement accounts
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
MAC
Amended and Restated Alliance Coal, LLC 2000 Long-Term Incentive Plan
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
MBbls
MBOE
Mercury and Air Toxics Standards
Thousand barrels of crude oil or other liquid hydrocarbons
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)
Mineral resource (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.
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
MMcf
Mr. Craft
MSHA
Million British thermal units
Million cubic feet of natural gas
Joseph W. Craft III, the Chairman, President and Chief Executive Officer of MGP
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
Net acres
National Environmental Policy Act
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 1/8th, royalty interest
NGFS
NGLs
Network for Greening the Financial System
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
NSR
Oil & gas
Old Ben
New Source Performance Standards
New source review
Crude oil, natural gas, and natural gas liquids
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
OSM
OWCP
PADEP
PAL
Patriot
PCAOB
Peabody
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
Federal Office of Surface Mining
Office of Workers’ Compensation Programs
Pennsylvania Department of Environmental Protection
Paducah & Louisville Railway, Inc.
Patriot Coal Corporation
Public Company Accounting Oversight Board
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
PUDs
RCRA
Reclamation
Reserves (oil & gas)
Profit sharing and savings plan
Proved undeveloped reserves
Federal Resource Conservation and Recovery Act
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 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
SEC
Our subsidiary, Sebree Mining, LLC
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
SIPs
Skyland
Alliance Coal, LLC Supplemental Executive Retirement Plan
State implementation plans
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
STIP
Federal Surface Mining Control and Reclamation Act of 1977
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
Term Loan
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 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
TRRC
TRS
Total Maximum Daily Load
Texas Railroad Commission
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
USFWS
USGA
United States Energy Association
United States Fish and Wildlife Service
United States Geological Survey
Valley Camp
Valley Camp Coal Company
VIE
VOC
Variable interest entity
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
WKY6
WKY7
WKY9
WOTUS
WVDEP
West Kentucky No. 11
West Kentucky No. 6
West Kentucky No. 7
West Kentucky No. 9
Waters of the United States
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:
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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;
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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
PART I
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.
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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.
Growth Investments and Opportunities
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.
Francis
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
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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.
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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
Illinois Basin
Appalachia
Total
2023
Year Ended December 31,
2022
(tons in millions)
2021
25.2
9.7
34.9
24.3
11.2
35.5
22.2
10.0
32.2
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The following map shows the location of our coal mining operations:
G. METTIKI COMPLEX
Mountain View Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Longwall
& Continuous Miner
Coal Type: Low/Medium
Sulfur - Metallurgical
Transportation: Railroad
& Truck
H. MC MINING COMPLEX
Excel Mine No. 5
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
Coal Type: Low-Sulfur
Transportation: Barge, Railroad,
& Truck
Illinois Basin Operations:
A. GIBSON COMPLEX
Gibson South Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
Coal Type: Low/Medium-Sulfur
Transportation: Barge, Railroad
& Truck
B. RIVER VIEW COMPLEX
a) River View Mine
b) Henderson County Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
Coal Type: Medium/High-Sulfur
Transportation: Barge & Truck
C. HAMILTON COMPLEX
Hamilton Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Longwall
& Continuous Miner
Coal Type: Medium/High-Sulfur
Transportation: Barge, Railroad
& Truck
D. WARRIOR COMPLEX
Warrior Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
Coal Type: Medium/High-Sulfur
Transportation: Barge, Railroad,
& Truck
E. MOUNT VERNON
TRANSFER TERMINAL
Rail or Truck to Ohio River Barge
Transloading Facility
Appalachian Operations:
F. TUNNEL RIDGE COMPLEX
Tunnel Ridge Mine
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Method: Longwall
& Continuous Miner
Coal Type: Medium/High-Sulfur
Transportation: Barge
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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.
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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
7
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."
8
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.
Oil & Gas Royalties
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:
Production:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
BOE (MBbls)
2023
Year Ended December 31,
2022*
2021*
1,418
5,759
726
3,105
1,061
4,814
541
2,404
898
3,460
402
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.
9
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.
10
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.
Coal Royalties
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
Illinois Basin
Appalachia
Total
2023
Year Ended December 31,
2022
(tons in millions)
2021
19.9
0.3
20.2
21.2
0.6
21.8
18.9
1.3
20.2
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The following map shows the location of our coal mineral interests:
Illinois Basin:
A. GIBSON RESERVES AND RESOURCES
E. HENDERSON/UNION RESOURCES
B. HAMILTON RESERVES AND RESOURCES
F. DOTIKI RESOURCES
Appalachian Basin:
H. TUNNEL RIDGE RESERVES AND RESOURCES
I. MOUNTAIN VIEW RESERVES AND RESOURCES
C. RIVER VIEW RESERVES
D. WARRIOR RESERVES
Illinois Basin
G. SEBREE SOUTH RESOURCES
J. PENN RIDGE RESOURCES
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:
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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.
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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
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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.
Growth Investments and Opportunities
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.
15
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.
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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
17
•
•
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
18
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."
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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.
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• 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
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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
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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
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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
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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
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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.
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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.
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ITEM 1A.
RISK FACTORS
Summary Risk Factors
Our business is subject to a number of risks, including risks that could prevent us from achieving our business
objectives or could adversely affect our business, financial condition, results of operations, cash flows, and prospects.
These risks are discussed more fully below and include but are not limited to risks related to:
Risks Inherent in an Investment in Us
• Cash distributions are not guaranteed
• Ownership of limited partner interests could be diluted
• Sales of our common units could cause decline in the market price of our common units
•
Increase in interest rates could cause decline in the market price of our common units
• The credit risk of our general partner could adversely impact us
• Our unitholders do not elect the general partner
• The control of our general partner may be transferred to a third party
• Unitholders may be required to sell their units to our general partner
• Cost reimbursements due to our general partner could be substantial
• Your liability as a limited partner may not be limited under certain circumstances
• Our general partner's fiduciary duties are limited
• Our general partner has discretion in determining the level of cash reserves
• Our general partner has potential conflicts of interest
• Some executive officers and directors face potential conflicts of interest
• ESG scores could adversely impact our securities
Risks Related to Our Business
• Declining global economic conditions could adversely impact us
• Material adverse effects on our financial condition as a result of 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
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• 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
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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.
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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.
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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.
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• 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.
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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.
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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
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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.
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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;
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• 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.
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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
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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.
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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.
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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;
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• weather conditions, such as heavy rains, flooding, ice, and other natural events affecting operations,
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;
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.
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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."
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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
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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
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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:
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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
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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:
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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.
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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.
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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
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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,
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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:
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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:
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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
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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:
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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.
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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,
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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.
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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
53
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
54
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
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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
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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.
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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
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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.
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ITEM 2.
PROPERTIES
COAL MINERAL RESOURCES AND RESERVES
Overview of Coal Properties
Our coal properties are located in the Illinois Basin and the Appalachia Basin. Our Illinois Basin properties are located
in western Kentucky, southern Illinois, and southern Indiana. Our Appalachian properties are located in eastern Kentucky,
Maryland, western Pennsylvania, and northern West Virginia. Mining operations on our coal properties consist of
underground mines that produce bituminous coal that is sold to customers principally for electric power generation
(thermal) and the production of steel (metallurgical). In addition to our coal mining operations, we also hold coal mineral
interests that we lease/sublease to our operations or hold for lease/sublease to our operations or others. For a detailed
overview of our coal mining operations and our coal royalty activities, please see "Item 1. Business—Coal Mining
Operations" and "Item 1. Business—Mineral Interest Activities", respectively.
Evaluation and Review of Coal Mineral Resources and Reserves
Numerous uncertainties are inherent in estimating coal mineral resources and reserves, and the estimates are subject
to change as additional information becomes available or circumstances change. Significant factors and assumptions
related to the uncertainty in estimating coal mineral reserves and resources include:
•
•
•
•
•
•
geological and mining conditions, which may not be fully identified by available exploration data and/or
differ from our experiences in areas where we currently mine;
the percentage of coal in the ground ultimately recoverable;
historical production from the area compared with production from other producing areas;
the assumed effects of regulation and taxes by governmental agencies;
future improvements in mining technology; and
assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes,
and development and reclamation costs.
Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used
in making the estimation and, as a result, the estimates in this report may not accurately reflect 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.
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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:
Resources (tons in millions)
per pound)
<1.2
1.2-2.5
>2.5
Measured Indicated Combined Inferred Owned
Leased
Total
Heat
Content (Btus
Pounds SO2 per MMBtu
Resource Classification
Ownership
12,100
11,450
11,450
11,750
11,650
13,200
12,600
12,500
Illinois Basin
Dotiki (KY)
Henderson/Union (KY)
River View (KY)
Sebree South (KY)
Hamilton County (IL)
Region Total
Appalachian Basin
Mountain View (WV)
Tunnel Ridge (WV)
Penn Ridge (PA)
Region Total
Total
% of Total
—
—
—
—
5.1
5.1
—
—
—
—
2.3
3.0
—
—
33.8
39.1
0.4
—
—
0.4
73.7
409.7
0.3
43.5
405.8
933.0
51.2
127.3
—
22.1
191.2
391.8
24.8
227.9
—
16.8
242.3
511.8
(1)
76.0
355.2
—
38.9
433.5
903.6
8.3
0.9
78.0
87.2
4.1
—
21.9
26.0
4.4
0.2
53.2
57.8
8.5
0.2
75.1
83.8
—
57.5
0.3
4.6
11.2
73.6
0.2
0.7
2.9
3.8
27.6
74.0
—
0.3
32.8
134.7
1.8
0.7
78.0
80.5
48.4
338.7
0.3
43.2
411.9
842.5
6.9
0.2
—
7.1
76.0
412.7
0.3
43.5
444.7
977.2
8.7
0.9
78.0
87.6
5.1
39.5
1,020.2
417.8
569.6
987.4
77.4
215.2
849.6
1,064.8
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.
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The following table sets forth coal mineral reserve information, exclusive of the coal mineral resources above, at
December 31, 2023, about our coal operations:
Reserves (tons in millions)
per pound)
<1.2
1.2-2.5
>2.5
Proven
Probable
Owned
Leased
Total
Heat
Content (Btus
Pounds SO2 per MMBtu
Classification
Ownership
Illinois Basin Operations
Warrior (KY)
River View (KY)
Hamilton County (IL)
Gibson South (IN)
Region Total
Appalachian Basin Operations
MC Mining (KY)
Mountain View (WV)
Tunnel Ridge (WV)
Region Total
Total
% of Total
12,300
11,450
11,650
11,500
12,800
13,200
12,600
—
—
—
0.9
0.9
9.6
—
—
9.6
—
—
—
9.5
9.5
0.5
4.4
—
4.9
50.0
310.4
119.8
34.8
515.0
—
5.1
118.2
123.3
39.5
169.1
54.5
35.6
298.7
7.8
9.1
64.5
81.4
10.5
141.3
65.3
9.6
226.7
2.3
0.4
53.7
56.4
13.0
58.0
20.3
15.3
106.6
—
—
11.7
11.7
37.0
252.4
99.5
29.9
418.8
10.1
9.5
106.5
126.1
10.5
14.4
638.3
380.1
283.1
118.3
544.9
50.0
310.4
119.8
45.2
525.4
10.1
9.5
118.2
137.8
663.2
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:
Operations
Location
2023
Tons Produced
2022
2021
(in millions)
Transportation
Equipment
4.4
9.9
5.6
5.3
25.2
1.2
0.8
7.7
9.7
4.1
10.2
4.7
5.3
24.3
1.5
1.4
8.3
11.2
4.1 CSX, NS, PAL, truck, barge
9.9 Truck, barge
4.9 CSX, EVW, NS, barge
3.3 CSX, NS, truck, barge
22.2
CM
CM
LW, CM
CM
1.3 CSX, truck, barge
1.5 CSX, truck
7.2 CSX, NS, barge
10.0
CM
LW, CM
LW, CM
34.9
35.5
32.2
Illinois Basin Operations
Warrior
River View
Hamilton County
Gibson South
Region Total
Kentucky
Kentucky
Illinois
Indiana
Appalachian Basin Operations
MC Mining/Excel
Mountain View
Tunnel Ridge
Kentucky
West Virginia
West Virginia
Region Total
TOTAL
CSX
EVW
NS
PAL
CM
LW
- CSX Railroad
- Evansville Western Railroad
- Norfolk Southern Railroad
- Paducah & Louisville Railroad
- Continuous Miner
- Longwall
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Individual Property Disclosures
We consider the following properties to be material based on multiple factors including, but not limited to, the
property's contribution to our overall business and financial condition. Please see Coal Mineral Resources and Coal
Mineral Reserves 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),
Personnel: Regional.
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Description
The potential underground mine(s) would utilize room-and-pillar methods operating a heavy media, float/sink style
preparation plant. Exploration continues as needed to fulfill possible permitting and development requirements. Multiple
access points are available for development. Access is available from the active River View 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.
History
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
64
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.
Encumbrances
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.
Geology and Reserves
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)
Henderson/Union
Measured Mineral Resources
Indicated Mineral Resources
Combined Mineral Resources
Inferred Mineral Resources
Tons (in millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Quality, Washed, Dry Basis
% Recovery
127.3
227.9
355.2
57.5
4.68
4.59
4.62
4.46
7.72
8.01
7.90
7.97
2.88
2.74
2.79
2.56
13,327
13,306
13,314
13,350
4.32
4.12
4.19
3.84
85.48
87.07
86.50
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),
Personnel: Regional.
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Description
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.
History
Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas
Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and
controlled a smaller portion of the reserves. We consolidated control of the property through multiple transactions from
2005 through 2015. Island Creek operated the Ohio #11 and Uniontown #9 mines to the west of River View. Island Creek
also operated the Hamilton #1 and #2 mines to the southwest. Peabody and later Patriot operated the Camp 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.
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Encumbrances
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.
Geology and Reserves
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
Tons (in millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Quality, Washed, Dry Basis
% Recovery
River View Complex
Proven Mineral Reserves
Probable Mineral Reserves
Total Mineral Reserves
169.1
141.3
310.4
4.69
4.56
4.63
8.08
8.25
8.16
3.20
3.18
3.19
13,191
13,141
13,168
4.85
4.85
4.85
87.40
87.25
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
(in millions)
Tons as of December 31, 2022
Production
Mineral Acquisition / Deletion (1)
Normal Course Adjustments
Tons as of December 31, 2023
204.7
(9.9)
115.2
0.4
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
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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),
Personnel: Regional.
Description
The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media,
float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The
mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good
working order and maintained to industry standards. Total book value of the property and any associated plant and
equipment for Hamilton as of December 31, 2023 was $332.4 million.
History
There were no previous operations on the Hamilton reserves property prior to our predecessor, White Oak Resources
LLC, who began construction of the mine in 2011. 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.
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Encumbrances
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.
Geology and Reserves
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
Tons (in millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Quality, Washed, Dry Basis
% Recovery
Hamilton County
Proven Mineral Reserves
Probable Mineral Reserves
Total Mineral Reserves
54.5
65.3
119.8
6.38
6.60
6.50
8.07
7.98
8.02
2.82
2.85
2.83
13,414
13,422
13,419
4.21
4.24
4.23
86.65
86.77
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
(in millions)
Tons as of December 31, 2022
Production
Mineral Acquisition / Deletion
Mine Plan Adjustment
Normal Course Adjustments
Tons as of December 31, 2023
125.9
(5.6)
4.1
(4.9)
0.3
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,
69
Water: Gibson Water, Inc. and well water,
Electricity: Western Indiana Energy REMC,
Personnel: Regional.
Description
The underground mine is currently in production using room-and-pillar methods utilizing a heavy media, float/sink
style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began
production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and
maintained to industry standards. Total book value of the property and any associated plant and equipment for Gibson
South as of December 31, 2023 was $117.0 million.
History
In November 1997, pursuant to (a) Assignment of Underground Coal Leases, (b) Partial Assignment of Underground
Coal Leases and (c) Special Corporate Warranty Deed, Old Ben conveyed to MAPCO Land & Development Corporation
various coal leases and fee coal interests within a large property boundary located in Gibson County, Indiana. MAPCO
Land & Development Corporation changed its name to MAPCO Coal Land & Development Corporation, and MAPCO
Coal Land & Development Corporation merged into Alliance Properties 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.
70
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.
Encumbrances
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.
Geology and Reserves
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
Gibson South
Proven Mineral Reserves
Probable Mineral Reserves
Total Mineral Reserves
Tons (in millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Quality, Washed, Dry Basis
% Recovery
35.6
9.6
45.2
5.96
5.33
5.81
7.13
8.15
7.34
2.00
2.51
2.11
13,477
13,322
13,444
2.97
3.77
3.14
94.81
92.82
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
(in millions)
Tons as of December 31, 2022
Production
Mineral Acquisition / Deletion
Tons as of December 31, 2023
49.0
(5.3)
1.5
45.2
Normal course adjustments are associated with numerous slight changes in the geologic model.
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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)
Personnel: Regional.
Description
The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media,
float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The
mine began production in 2010. All equipment, facilities, infrastructure, and underground development are in good
working order and maintained to industry standards. Total book value of the property and any associated plant and
equipment for Tunnel Ridge as of December 31, 2023 was $301.7 million.
72
History
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.
Encumbrances
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.
Geology and Reserves
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
Tunnel Ridge
Proven Mineral Reserves
Probable Mineral Reserves
Total Mineral Reserves
Tons (in millions)
Thickness (ft)
% Ash
% Sulfur
Btu
lbs. SO2
In-Seam
Quality, Washed, Dry Basis
% Recovery
64.5
53.7
118.2
7.12
7.26
7.18
7.92
8.30
8.09
3.10
3.49
3.28
13,711
13,618
13,669
4.52
5.13
4.79
67.88
68.06
67.96
Resources associated with Tunnel Ridge are included in the Coal Mineral Resources table above.
73
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
(in millions)
Tons as of December 31, 2022
Production
Mineral Acquisition / Deletion
Mine Plan Adjustment
Normal Course Adjustments
Tons as of December 31, 2023
OIL & GAS RESERVES
Summary of Oil & Gas Reserves
120.0
(7.7)
(1.2)
6.8
0.3
118.2
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.
Crude Oil
(MBbl)
As of December 31, 2023
Natural Gas Natural Gas Liquids
Total
(MMcf)
(MBbl)
(MBOE) (2)
Estimated proved developed reserves
Estimated proved undeveloped reserves
Total estimated proved reserves (1)
7,754
1,599
9,353
45,684
5,839
51,523
5,485
868
6,353
20,854
3,440
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.
74
3,795
38
(1,448)
2,462
(1,407)
3,440
The following table summarizes our changes in proved undeveloped reserves (in MBOE):
Beginning balance, January 1, 2023*
Acquisitions of proved undeveloped reserves
Transfers of PUDs to estimated proved developed
Extensions and discoveries
Revisions of previous estimates
Ending balance, December 31, 2023
* 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
75
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.
Gross
Developed Acreage
Net Mineral Net Royalty Gross
Undeveloped Acreage
Net Mineral Net Royalty
Basin
Permian Basin
Anadarko Basin
Williston Basin
Other
Total
378,510
179,993
153,772
28,174
740,449
11,114
6,489
2,541
1,027
21,171
14,894
9,199
3,363
1,296
517,804
295,884
84,118
37,363
28,752
935,169
15,204
10,667
1,390
1,362
28,623
20,350
15,112
1,849
1,682
38,993
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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:
Production:
Oil (MBbls)
Natural gas (MMcf)
Natural gas liquids (MBbls)
BOE (MBbls)
Average Realized Prices:
Oil (per Bbl)
Natural gas (per Mcf)
Natural gas liquids (per Bbl)
BOE (MBbls)
Unit cost per BOE:
Production and ad valorem taxes
2023
Year Ended December 31,
2022*
2021*
1,462
6,161
726
3,215
77.40 $
2.03 $
23.15 $
44.32 $
1,104
5,226
541
2,516
94.76 $
6.29 $
38.53 $
62.94 $
4.37 $
5.61 $
929
3,881
402
1,978
66.19
3.86
28.58
44.47
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
77
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.
78
PART II
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The common units representing limited partners' interests are listed on the NASDAQ Global Select Market under the
symbol "ARLP." The common units began trading on August 20, 1999. There were approximately 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.
79
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.
80
• 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.
Growth Investments and Opportunities
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;
81
•
•
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.
82
Segment Adjusted EBITDA
We define Segment Adjusted EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before
net interest expense, income taxes, depreciation, depletion and amortization 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.
Net income attributable to ARLP
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
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.
83
• 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 royalties
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
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
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.
Segment Adjusted EBITDA
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."
84
Segment Information
Segment Adjusted EBITDA
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination (2)
Year Ended December 31,
2023
2022 (1)
(in thousands)
$
514,118 $
330,723
121,508
41,163
4,661
420,684 $
426,402
143,179
38,809
3,495
Total Segment Adjusted EBITDA (3)
$ 1,012,173 $ 1,032,569 $
Increase (Decrease)
93,434
(95,679)
(21,671)
2,354
1,166
(20,396)
22.2 %
(22.4) %
(15.1) %
6.1 %
33.4 %
(2.0) %
Coal - Tons sold
Illinois Basin Coal Operations
Appalachia Coal Operations
Total tons sold
Coal sales
Illinois Basin Coal Operations
Appalachia Coal Operations
Total coal sales
Other revenues
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination
Total other revenues
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination (2)
Total Segment Adjusted EBITDA Expense (3)
Oil & Gas Royalties
Volume - BOE (4)
Oil & gas royalties
Coal Royalties
Volume - Tons sold (5)
Intercompany coal royalties
24,724
9,718
34,442
24,110
11,479
35,589
614
(1,761)
(1,147)
2.5 %
(15.3) %
(3.2) %
$ 1,364,901 $ 1,219,943 $ 144,958
(36,977)
$ 2,210,210 $ 2,102,229 $ 107,981
882,286
845,309
$
$
10,505 $
1,885
3,774
42
60,244
76,450 $
6,822 $
1,481
3,837
56
40,622
52,818 $
3,683
404
(63)
(14)
19,622
23,632
$
861,288 $
516,471
16,532
24,451
(14,024)
55,208
52,442
1,137
2,580
9,473
$ 1,404,718 $ 1,283,878 $ 120,840
806,080 $
464,029
15,395
21,871
(23,497)
11.9 %
(4.2) %
5.1 %
54.0 %
27.3 %
(1.6) %
(25.0) %
48.3 %
44.7 %
6.8 %
11.3 %
7.4 %
11.8 %
40.3 %
9.4 %
3,105
137,751 $
2,405
151,060 $
700
(13,309)
$
29.1 %
(8.8) %
$
20,186
65,572 $
21,780 $
60,624
(1,594)
4,948
(7.3) %
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).
85
(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.
Net income attributable to ARLP
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.
86
Coal sales
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 royalties
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
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
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."
87
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.
Segment Adjusted EBITDA
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.
88
Segment Information
Year Ended December 31,
2022 (1)
2021 (1)
(in thousands)
Increase (Decrease)
Segment Adjusted EBITDA
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination (2)
$
Total Segment Adjusted EBITDA (3)
$ 1,032,569 $
420,684 $
426,402
143,179
38,809
3,495
172,601
76,920
33,202
9,383
265,292 $ 155,392
253,801
66,259
5,607
(5,888)
557,398 $ 475,171
58.6 %
147.0 %
86.1 %
16.9 %
(62.8) %
85.2 %
8.3 %
14.7 %
10.3 %
39.6 %
72.0 %
51.6 %
46.2 %
(62.4) %
70.1 %
(18.8) %
47.3 %
37.1 %
31.4 %
34.8 %
39.3 %
19.7 %
29.2 %
34.6 %
24,110
11,479
35,589
22,264
10,004
32,268
1,846
1,475
3,321
$ 1,219,943 $
882,286
873,930 $ 346,013
369,293
512,993
$ 2,102,229 $ 1,386,923 $ 715,306
6,822 $
1,481
3,837
56
40,622
52,818 $
4,666 $
3,940
2,256
69
27,586
38,517 $
2,156
(2,459)
1,581
(13)
13,036
14,301
$
$
$
806,080 $
464,029
15,395
21,871
(23,497)
613,303 $ 192,777
119,697
344,332
4,344
11,051
3,602
18,269
(33,198)
9,701
953,757 $ 330,121
$ 1,283,878 $
Coal - Tons sold
Illinois Basin Coal Operations
Appalachia Coal Operations
Total tons sold
Coal sales
Illinois Basin Coal Operations
Appalachia Coal Operations
Total coal sales
Other revenues
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination
Total other revenues
Segment Adjusted EBITDA Expense
Illinois Basin Coal Operations
Appalachia Coal Operations
Oil & Gas Royalties
Coal Royalties
Other, Corporate and Elimination (2)
Total Segment Adjusted EBITDA Expense (3)
Oil & Gas Royalties
Volume - BOE (4)
Oil & gas royalties
Coal Royalties
Volume - Tons sold (5)
Intercompany coal royalties
2,405
151,060 $
1,877
84,183 $
528
66,877
$
28.1 %
79.4 %
21,780
60,624 $
20,247
51,402 $
1,533
9,222
$
7.6 %
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).
89
(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.
90
The following is a reconciliation of net income, the most comparable GAAP financial measure, to consolidated
Segment Adjusted EBITDA:
2023
Year Ended December 31,
2022
(in thousands)
2021
Net income
Noncontrolling interest
Net income attributable to ARLP
General and administrative
Depreciation, depletion and amortization
Interest expense, net
Income tax expense
Consolidated Segment Adjusted EBITDA
$
$
$
636,170
(6,052)
630,118
79,096
267,982
26,697
8,280
1,012,173
$
$
$
$
$
588,158
(1,958)
586,200
80,425
276,670
35,296
53,978
1,032,569 $
183,369
(598)
182,771
70,275
264,794
39,141
417
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:
Operating expenses (excluding depreciation, depletion and
amortization)
Outside coal purchases
Other expense (income)
Segment Adjusted EBITDA Expense
$
$
2023
Year Ended December 31,
2022
(in thousands)
2021
1,368,787
36,149
(218)
1,404,718
$
$
1,288,082
151
(4,355)
1,283,878
$
$
944,419
6,372
2,966
953,757
91
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."
Growth Investments and Opportunities
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
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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
93
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:
Reclamation
Obligation
Compensation
Obligation
Workers'
Other
Total
$
173.5 $
—
(in millions)
58.4 $
41.0
15.0 $
16.8
246.9
57.8
Surety bonds
Letters of credit
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.
94
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
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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.
96
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
97
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:
Expected Maturity Dates
as of December 31, 2023
2024
2025
2026
Fixed rate debt
Weighted-average interest rate
$
$
2,039
7.50 %
284,607
$
7.50 %
2027
(dollars in thousands)
$
$
—
— %
—
— %
2028
Total
Fair Value
December 31,
2023
$
—
— %
286,646
$
286,179
Variable rate debt
Weighted-average interest rate (1)
$
18,750
$
18,750
$
18,750
$
8.50 %
8.50 %
8.50 %
$
4,688
8.50 %
—
—
$
60,938
$
60,938
Expected Maturity Dates
as of December 31, 2022
2023
2024
2025
Fixed rate debt
Weighted-average interest rate
$
24,970
$
7.40 %
$
2,039
7.50 %
400,000
7.50 %
2026
(dollars in thousands)
$
$
—
— %
2027
Total
Fair Value
December 31,
2022
$
—
— %
427,009
$
424,420
(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.
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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
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
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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
100
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
February 23, 2024
101
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2023 AND 2022
(In thousands, except unit data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Trade receivables
Other receivables
Inventories, net
Advance royalties
Prepaid expenses and other assets
Total current assets
PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment, at cost
Less accumulated depreciation, depletion and amortization
Total property, plant and equipment, net
OTHER ASSETS:
Advance royalties
Equity method investments
Equity securities
Operating lease right-of-use assets
Other long-term assets
Total other assets
TOTAL ASSETS
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable
Accrued taxes other than income taxes
Accrued payroll and related expenses
Accrued interest
Workers' compensation and pneumoconiosis benefits
Other current liabilities
Current maturities, long-term debt, net
Total current liabilities
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities, net
Pneumoconiosis benefits
Accrued pension benefit
Workers' compensation
Asset retirement obligations
Long-term operating lease obligations
Deferred income tax liabilities
Other liabilities
Total long-term liabilities
Total liabilities
COMMITMENTS AND CONTINGENCIES - (Note 21)
PARTNERS' CAPITAL:
ARLP Partners' Capital:
Limited Partners - Common Unitholders 127,125,437 and 127,195,219 units outstanding,
respectively
General Partner's interest
Accumulated other comprehensive loss
Total ARLP Partners' Capital
Noncontrolling interest
Total Partners' Capital
TOTAL LIABILITIES AND PARTNERS' CAPITAL
*Recast as discussed in Note 1 – Organization and Presentation.
See notes to consolidated financial statements.
102
$
$
$
December 31,
2023
2022*
$
59,813
282,622
9,678
127,556
7,780
28,672
516,121
$
$
4,172,544
(2,149,881)
2,022,663
71,125
46,503
92,541
16,569
22,904
249,642
2,788,426
108,269
21,007
29,884
3,558
15,913
28,498
20,338
227,467
316,821
127,249
8,618
37,257
146,925
13,661
33,450
18,381
702,362
929,829
296,023
241,412
8,601
77,326
7,556
26,675
657,593
3,931,422
(2,050,754)
1,880,668
67,713
49,371
42,000
14,950
15,726
189,760
2,728,021
95,122
22,967
39,623
5,000
14,099
53,790
24,970
255,571
397,203
100,089
12,553
39,551
142,254
12,132
35,814
24,828
764,424
1,019,995
1,896,027
—
(61,525)
1,834,502
24,095
1,858,597
2,788,426
$
1,656,025
66,548
(41,054)
1,681,519
26,507
1,708,026
2,728,021
$
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands, except unit and per unit data)
c
SALES AND OPERATING REVENUES:
Coal sales
Oil & gas royalties
Transportation revenues
Other revenues
Total revenues
EXPENSES:
Operating expenses (excluding depreciation, depletion and amortization)
Transportation expenses
Outside coal purchases
General and administrative
Depreciation, depletion and amortization
Settlement gain
Total operating expenses
INCOME FROM OPERATIONS
Interest expense (net of interest capitalized of $6,706, $922 and $396,
respectively)
Interest income
Equity method investment income (loss)
Other income (expense)
INCOME BEFORE INCOME TAXES
INCOME TAX EXPENSE
NET INCOME
2023
Year Ended December 31,
2022*
2021*
$
2,210,210
137,751
142,290
76,450
2,566,701
$
2,102,229
151,060
113,860
52,818
2,419,967
$
1,386,923
84,183
69,607
38,517
1,579,230
1,368,787
142,290
36,149
79,096
267,982
—
1,894,304
1,288,082
113,860
151
80,425
276,670
(6,664)
1,752,524
944,419
69,607
6,372
70,275
264,794
—
1,355,467
672,397
667,443
223,763
(36,091)
9,394
(1,468)
218
644,450
(37,331)
2,035
5,634
4,355
642,136
8,280
53,978
(39,229)
88
2,130
(2,966)
183,786
417
636,170
588,158
183,369
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING
INTEREST
(6,052)
(1,958)
(598)
NET INCOME ATTRIBUTABLE TO ARLP
$
630,118
$
586,200
$
182,771
NET INCOME ATTRIBUTABLE TO ARLP
GENERAL PARTNER
LIMITED PARTNERS
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED
$
$
$
1,384
628,734
4.81
$
$
$
9,010
577,190
4.39
$
$
$
4,614
178,157
1.36
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC
AND DILUTED
127,180,312
127,195,219
127,195,219
*Recast as discussed in Note 1 – Organization and Presentation.
See notes to consolidated financial statements.
103
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands)
NET INCOME
$
636,170
$
588,158
$
183,369
Year Ended December 31,
2022*
2023
2021*
OTHER COMPREHENSIVE INCOME (LOSS):
Defined benefit pension plan
Amortization of prior service cost (1)
Net actuarial gain
Amortization of net actuarial loss (1)
Total defined benefit pension plan adjustments
Pneumoconiosis benefits
Net actuarial gain (loss)
Amortization of net actuarial loss (1)
Total pneumoconiosis benefits adjustments
186
2,894
682
3,762
(25,615)
1,382
(24,233)
186
10,148
1,963
12,297
9,840
1,038
10,878
OTHER COMPREHENSIVE INCOME (LOSS)
(20,471)
23,175
COMPREHENSIVE INCOME
615,699
611,333
Less: Comprehensive income attributable to noncontrolling interest
(6,052)
(1,958)
186
14,921
4,327
19,434
(161)
4,172
4,011
23,445
206,814
(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).
*Recast as discussed in Note 1 – Organization and Presentation.
See notes to consolidated financial statements.
104
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by operating activities:
Year Ended December 31,
2022*
2023
2021*
$
636,170
$
588,158
$
183,369
Depreciation, depletion and amortization
Non-cash compensation expense
Coal inventory adjustment to market
Equity method investment loss (income)
Distributions from equity method investments
Net gain on sale of property, plant and equipment
Change in deferred income tax
Other
Changes in operating assets and liabilities:
Trade receivables
Other receivables
Inventories, net
Prepaid expenses and other assets
Advance royalties
Accounts payable
Accrued taxes other than income taxes
Accrued payroll and related benefits
Pneumoconiosis benefits
Workers' compensation
Other
Total net adjustments
Net cash provided by operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures
Change in accounts payable and accrued liabilities
Proceeds from sale of property, plant and equipment
Contributions to equity method investments
Purchase of equity securities
JC Resources acquisition
Oil & gas reserve business combinations
Oil & gas reserve asset acquisitions
Other
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under securitization facility
Payments under securitization facility
Payments on equipment financings
Borrowings under revolving credit facilities
Payments under revolving credit facilities
Borrowings from line of credit
Payment on line of credit
Borrowing under long-term debt
Payments on long-term debt
Payment of debt issuance costs
Payments for purchases of units under unit repurchase program
Payments for tax withholdings related to settlements under deferred compensation plans
Excess purchase price over the contributed basis from JC Resources acquisition
Cash retained by JC Resources in acquisition
Distributions paid to Partners
Other
Net cash used in financing activities
NET CHANGE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS AT END OF PERIOD
*Recast as discussed in Note 1 – Organization and Presentation.
See notes to consolidated financial statements.
$
105
267,982
12,864
33,296
1,468
2,567
(3,230)
(8,973)
11,259
(41,210)
(1,077)
(78,004)
(2,940)
(3,636)
17,842
(1,960)
(9,739)
3,924
(1,477)
(4,484)
194,472
830,642
(379,338)
(29,695)
3,710
(2,518)
(49,560)
(64,999)
(14,459)
(24,225)
1,351
(559,733)
—
—
(24,970)
—
—
—
—
75,000
(129,455)
(12,376)
(19,432)
(10,334)
(7,251)
(2,933)
(364,579)
(10,789)
(507,119)
(236,210)
296,023
59,813
276,670
11,029
364
(5,634)
5,634
(3,665)
34,775
5,313
(108,893)
(7,921)
(20,138)
(9,179)
(6,787)
14,580
5,180
2,818
3,849
(3,996)
20,192
214,191
802,349
(286,394)
35,956
7,468
(24,087)
(42,000)
—
(92,618)
—
(1,663)
(403,338)
27,500
(27,500)
(16,071)
—
—
—
—
—
—
—
—
—
—
(10,537)
(196,347)
(2,436)
(225,391)
173,620
122,403
296,023
$
264,794
5,709
70
(2,130)
2,130
(6,592)
349
3,900
(25,931)
3,109
(4,673)
211
(7,523)
19,481
(7,267)
8,281
6,832
(1,292)
(10,654)
248,804
432,173
(122,984)
2,594
7,719
—
—
—
—
(30,960)
943
(142,688)
35,000
(90,900)
(17,299)
15,000
(102,500)
5,340
(5,340)
—
—
(113)
—
(1,090)
—
(6,971)
(52,158)
(1,625)
(222,656)
66,829
55,574
122,403
$
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands, except unit data)
Balance at January 1, 2021
Comprehensive income:
Net income
Actuarially determined long-term liability
adjustments
Total comprehensive income
Settlement of deferred common unit- based
compensation plans
Common unit-based compensation
Distributions on deferred common unit-based
compensation
Distributions from consolidated company to
noncontrolling interest
Cash retained by JC Resources in acquisition - See
Note 1
Distributions to Partners
Balance at December 31, 2021
Comprehensive income:
Net income
Actuarially determined long-term liability
adjustments
Total comprehensive income
Common unit-based compensation
Distributions on deferred common unit-based
compensation
Distributions from consolidated company to
noncontrolling interest
Profits interest adjustment for noncontrolling
interest
Cash retained by JC Resources in acquisition - See
Note 1
Distributions to Partners
Balance at December 31, 2022
Comprehensive income:
Net income
Actuarially determined long-term liability
adjustments
Total comprehensive income
Settlement of deferred common unit- based
compensation plans
Purchase of units under unit repurchase program
Common unit-based compensation
Distributions on deferred common unit-based
compensation
Distributions from consolidated company to
noncontrolling interest
JC Resources acquisition - See Note 1
Cash retained by JC Resources in acquisition - See
Note 1
Distributions to Partners
Number of
Limited
Partner
Units
127,195,219 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
860,060
(929,842)
—
—
—
—
—
—
Balance at December 31, 2023
127,125,437 $
*Recast as discussed in Note 1 – Organization and Presentation.
See notes to consolidated financial statements.
Accumulated
Other
Limited
Partners'
Capital
1,148,565 $
General
Partner's
Capital *
Comprehensive Noncontrolling Total Partners'
Income (Loss)
Interest
(87,674) $
11,376 $
1,142,699
Capital *
70,432 $
178,157
4,614
—
598
183,369
—
—
23,445
—
(1,090)
5,709
(1,280)
—
—
—
—
—
—
—
—
—
—
—
127,195,219
—
(50,878)
1,279,183
(6,971)
—
68,075
—
—
(64,229)
—
—
11,115
(6,971)
(50,878)
1,294,144
577,190
9,010
—
1,958
588,158
—
11,029
(5,553)
—
(15,030)
—
—
—
—
—
23,175
—
—
—
—
—
—
127,195,219
—
(190,794)
1,656,025
(10,537)
—
66,548
—
—
(41,054)
23,445
206,814
(1,090)
5,709
(1,280)
—
—
—
(859)
(859)
—
—
—
23,175
611,333
11,029
(5,553)
(1,596)
(1,596)
15,030
—
—
26,507
—
(10,537)
(190,794)
1,708,026
628,734
1,384
—
6,052
636,170
—
—
(20,471)
—
(10,334)
(19,432)
12,864
(8,530)
—
(7,251)
—
—
—
—
—
(64,999)
—
—
—
—
—
—
—
—
—
—
(8,464)
—
(20,471)
615,699
(10,334)
(19,432)
12,864
(8,530)
(8,464)
(72,250)
—
(356,049)
1,896,027 $
(2,933)
—
— $
—
—
(61,525) $
—
—
24,095 $
(2,933)
(356,049)
1,858,597
106
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
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
107
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").
Growth Investments and Opportunities
Francis
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.
108
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;
109
• 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.
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Advance Royalties
Rights to coal mineral leases are often acquired and/or maintained through advance royalty payments. Where royalty
payments represent prepayments recoupable against future production, they are recorded as an asset, with amounts
expected to be recouped within one year classified as a current asset. As mining occurs on these leases, the royalty
prepayments are charged to operating expenses. We assess the recoverability of royalty prepayments based on estimated
future production. Royalty prepayments estimated to be nonrecoverable are expensed. Our advance royalties are
summarized as follows:
December 31,
2023
2022
(in thousands)
Advance royalties, affiliates (see Note 20 – Related-Party
Transactions)
Advance royalties, third-parties
Total advance royalties
$
$
64,599 $
14,306
78,905 $
60,608
14,661
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
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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.
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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
113
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.
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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.
115
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
116
(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
Mineral interests in unproved properties
Belvedere
(in thousands)
$
$
12,542
18,418
30,960
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
Mineral interests in unproved properties
(in thousands)
$
$
7,724
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:
Revenue
Net income
117
Year Ended
December 31,
2022
(in thousands)
$
722
488
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.
Revenues
Net income
Jase
Year Ended
December 31,
2022
2021
(in thousands)
(unaudited)
$
2,420,824 $
588,916
1,580,373
184,361
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
Mineral interests in unproved properties
Receivables
Net assets acquired
(in thousands)
$
$
35,918
43,740
1,569
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:
Revenue
Net income
Year Ended
December 31,
2022
(in thousands)
$
1,689
854
118
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.
Revenues
Net income
JC Resources
Year Ended
December 31,
2022
2021
(in thousands)
(unaudited)
$
2,430,734 $
596,759
1,588,914
190,765
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
Mineral interests in unproved properties
Net assets acquired
(in thousands)
$
$
8,694
5,765
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.
119
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.
Revenues
Net income
Miscellaneous Acquisitions
Year Ended
December 31,
2023
2022
(in thousands)
(unaudited)
$
2,568,516 $
637,757
2,423,313
591,140
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:
December 31,
2023
2022
(in thousands)
Coal
Supplies (net of reserve for obsolescence of $8,167 and $6,601,
respectively)
Total inventories, net
$
56,549 $
23,553
$
71,007
127,556 $
53,773
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.
120
5.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consist of the following:
Mining equipment and processing facilities
Land and coal mineral rights
Oil & gas mineral interests
Buildings, office equipment, improvements and other miscellaneous
equipment
Construction, mine development and other projects in progress
Mine development costs
Property, plant and equipment, at cost
Less accumulated depreciation, depletion and amortization
$
Total property, plant and equipment, net
$
December 31,
2023
2022
(in thousands)
1,989,541 $
504,736
853,350
310,876
184,895
329,146
4,172,544
(2,149,881)
2,022,663 $
1,927,603
499,950
814,667
300,436
99,042
289,724
3,931,422
(2,050,754)
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.
121
6.
LONG-TERM DEBT
Long-term debt consists of the following:
Principal
December 31,
Unamortized Discount and
Debt Issuance Costs
December 31,
2023
2022
2023
2022
$
$
— $
60,938
284,607
—
—
2,039
347,584
(20,789)
326,795 $
(in thousands)
— $
—
400,000
—
21,072
5,937
427,009
(24,970)
402,039 $
(8,118) $
(1,416)
(891)
—
—
—
(10,425)
451
(9,974) $
(2,702)
—
(2,134)
—
—
—
(4,836)
—
(4,836)
Revolving credit facility
Term loan
Senior notes
Securitization facility
November 2019 equipment financing
June 2020 equipment financing
Less current maturities
Total long-term debt
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.
122
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 not have any outstanding borrowings under the Securitization
Facility.
123
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 monthly 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:
Year Ended
December 31,
2024
2025
2026
2027
7.
INCOME TAXES
Components of income tax expense are as follows:
(in thousands)
20,789
$
303,357
18,750
4,688
347,584
$
Current:
Federal
State
Deferred:
Federal
State
Income tax expense
2023
Year Ended December 31,
2022
(in thousands)
2021
$
$
15,917
1,336
17,253
(7,235)
(1,738)
(8,973)
8,280
$
$
17,572
1,605
19,177
33,038
1,763
34,801
53,978
$
$
(1)
70
69
356
(8)
348
417
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
124
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:
Income taxes at statutory rate
$
135,335
2023
Year Ended December 31,
2022
(in thousands)
134,849
$
$
2021
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
Change in valuation allowance of deferred tax assets
Deferred taxes related to tax election
Tax effect of noncontrolling interest income not subject to
income taxes
Return to accrual adjustments
Other
Income tax expense
$
864
—
—
(1,361)
(7,008)
6
8,280
1,492
(317)
37,253
(5,399)
69
(44)
53,978
$
$
275
(834)
—
—
(1)
(72)
417
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:
Deferred tax liabilities:
Property, plant and equipment
Total deferred tax liabilities
Deferred tax assets:
Federal loss carryovers and credits
State loss carryovers and credits
Capitalized research and development
Other
Total deferred tax assets
December 31,
2023
2022
(in thousands)
$
(36,453)
(36,453)
$
(38,349)
(38,349)
4,508
2,126
2,567
1,098
10,299
2,139
951
—
133
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.
125
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:
Finance lease cost:
Amortization of right-of-use assets
Interest on lease liabilities
Operating lease cost
Short-term lease cost
Variable lease cost
Total lease cost
2023
December 31,
2022
(in thousands)
2021
$
$
96
27
3,572
—
1,680
5,375
$
$
597 $
73
2,884
—
1,665
5,219 $
597
147
2,404
200
1,306
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
December 31,
2022
(in thousands)
2021
Cash paid for amounts included in the measurement of lease
liabilities:
Operating cash flows for operating leases
Operating cash flows for finance leases
Financing cash flows for finance leases
$
$
$
3,720
27
363
$
$
$
2,880 $
73 $
840 $
2,367
147
766
Right-of-use assets obtained in exchange for lease obligations:
Operating leases
$
2,596
$
1,315 $
189
Supplemental balance sheet information related to leases was as follows:
Finance leases:
Property and equipment finance lease assets, gross
Accumulated depreciation
Property and equipment finance lease assets, net
December 31,
2023
2022
(in thousands)
$
$
1,085 $
(507)
578 $
5,485
(5,061)
424
126
Weighted average remaining lease term
Operating leases
Finance leases
Weighted average discount rate
Operating leases
Finance leases
Maturities of lease liabilities as of December 31, 2023 were as follows:
2024
2025
2026
2027
2028
Thereafter
Total lease payments
Less imputed interest
Total
December 31,
2023
2022
11.7 years
4.0 years
13.4 years
5.0 years
6.0 %
4.8 %
6.0 %
4.8 %
Operating leases Finance leases
(in thousands)
$
$
3,437 $
2,403
1,923
1,930
1,646
12,122
23,461
(6,869)
16,592 $
140
140
140
140
—
—
560
(55)
505
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:
Long-term debt
December 31, 2023
December 31, 2022
Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
(in thousands)
$
— $ 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:
127
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
$
$
$
$
Year Ended December 31,
2022
0.250 $
0.350 $
0.400 $
0.500 $
2023
0.700 $
0.700 $
0.700 $
0.700 $
2021
—
0.100
0.100
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:
128
Assets (liabilities):
Cash and cash equivalents
Trade receivables
Total property, plant and equipment, net
Accounts payable
Due to affiliates
Accrued taxes other than income taxes
AllDale III
December 31,
2023
2022
(in thousands)
$
4,690 $
16,058
389,767
(175)
—
(958)
4,698
13,933
406,135
(257)
(24)
(206)
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.
Francis
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.
129
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:
Beginning balance
Equity method investment income
Distributions received
Ending balance
Francis
$
$
2023
Year Ended December 31,
2022
(in thousands)
26,325
$
5,634
(6,675)
25,284
$
$
$
25,284
2,567
(3,918)
23,933
2021
27,268
2,130
(3,073)
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:
Beginning balance
Contributions
Equity method investment loss
Ending balance
NGP ET IV
Year Ended December 31,
2022
2023
(in thousands)
$
$
20,000
—
(3,513)
16,487
$
$
—
20,000
—
20,000
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:
Beginning balance
Contributions
Equity method investment loss
Ending balance
Infinitum
Year Ended December 31,
2022
2023
(in thousands)
$
$
4,087
2,518
(522)
6,083
$
$
—
4,087
—
4,087
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.
130
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
Illinois
Basin
Appalachia Oil & Gas Coal
(in thousands)
Other,
Corporate and
Elimination Consolidated
Year Ended December 31, 2023
Coal sales
Oil & gas royalties
Coal royalties
Transportation revenues
Other revenues
Total revenues
$ 1,364,901 $ 845,309 $
— $
—
—
106,150
10,505
—
—
36,140
1,885
137,751
—
—
3,774
$ 1,481,556 $ 883,334 $ 141,525 $
— $
—
65,572
—
42
65,614 $
— $ 2,210,210
137,751
—
—
(65,572)
142,290
—
60,244
76,450
(5,328) $ 2,566,701
Year Ended December 31, 2022
Coal sales
Oil & gas royalties
Coal royalties
Transportation revenues
Other revenues
Total revenues
$ 1,219,943 $ 882,286 $
— $
—
—
69,540
6,822
—
—
44,320
1,481
151,060
—
—
3,837
$ 1,296,305 $ 928,087 $ 154,897 $
— $
—
60,624
—
56
60,680 $
— $ 2,102,229
151,060
—
—
(60,624)
113,860
—
52,818
40,622
(20,002) $ 2,419,967
Year Ended December 31, 2021
Coal sales
Oil & gas royalties
Coal royalties
Transportation revenues
Other revenues
Total revenues
$
873,930 $ 512,993 $
—
—
41,001
4,666
—
—
28,606
3,940
$
919,597 $ 545,539 $
— $
84,183
—
—
2,256
86,439 $
— $
—
51,402
—
69
51,471 $
— $ 1,386,923
84,183
—
—
(51,402)
69,607
—
38,517
27,586
(23,816) $ 1,579,230
131
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.
2024
2025
2027 and
Thereafter
2026
(in thousands)
Total
Illinois Basin Coal Operations coal
revenues
Appalachia Coal Operations coal
revenues
Total coal revenues (1)
$ 1,291,152
$
494,386
$
253,465
$
238,500
$
2,277,503
754,183
$ 2,045,335
$
325,425
819,811
$
1,600
255,065
$
—
238,500
$
1,081,208
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.
Year Ended December 31,
2023
2022
2021
(in thousands, except per unit data)
Net income attributable to ARLP
Less:
$ 630,118
$ 586,200
$ 182,771
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
Undistributed earnings attributable to participating securities
(9,688)
(7,203)
(8,527)
(10,576)
(2,334)
(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.
132
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:
Change in benefit obligations:
Benefit obligations at beginning of year
Interest cost
Actuarial loss (gain)
Benefits paid
Benefit obligations at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Actual return on plan assets
Benefits paid
Fair value of plan assets at end of year
Funded status at the end of year
Amounts recognized in balance sheet:
Non-current liability
Amounts recognized in accumulated other comprehensive income consists
of:
Prior service cost
Net actuarial loss
December 31,
2023
2022
(dollars in thousands)
$
$
104,682 $
5,180
2,446
(6,438)
105,870
92,129
11,561
(6,438)
97,252
(8,618) $
139,566
3,749
(32,996)
(5,637)
104,682
113,976
(16,210)
(5,637)
92,129
(12,553)
$
(8,618) $
(12,553)
$
$
(196) $
(11,584)
(11,780) $
(382)
(15,160)
(15,542)
Weighted-average assumption to determine benefit obligations as of
December 31,
Discount rate
Weighted-average assumptions used to determine net periodic benefit cost
for the year ended December 31,
Discount rate
Expected return on plan assets
4.90%
5.10%
5.10%
7.00%
2.73%
6.00%
133
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:
As of December 31, 2023
Equity securities
Fixed income securities
Asset allocation
assumption
75%
25%
100%
The actual return on plan assets was 12.5% and (14.6)% for the years ended December 31, 2023 and 2022,
respectively.
Year Ended December 31,
2023
2022
2021
(in thousands)
Components of net periodic benefit cost (credit):
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of net loss
Net periodic benefit cost (credit) (1)
$ 5,180
(6,220)
186
682
(172)
$
$ 3,749
(6,638)
186
1,963
(740)
$
$ 3,438
(6,580)
186
4,327
$ 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.
Year Ended December 31,
2023
2022
(in thousands)
$
2,894 $
10,148
186
682
3,762
172
186
1,963
12,297
740
3,934 $
13,037
Other changes in plan assets and benefit obligation
recognized in accumulated other comprehensive loss:
Net actuarial gain
Reversal of amortization item:
Prior service cost
Net actuarial loss
Total recognized in accumulated other comprehensive loss
Net periodic benefit cost
Total recognized in net periodic benefit cost and accumulated
other comprehensive loss
$
134
Estimated future benefit payments as of December 31, 2023 are as follows:
Year Ended
December 31,
2024
2025
2026
2027
2028
2029-2033
(in thousands)
$
$
6,331
6,490
6,688
6,820
6,899
35,204
68,432
We do not 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:
Equity securities
Fixed income securities
Percentage of Total Portfolio
Maximum
Minimum
50%
15%
85%
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.
135
The following information discloses the fair values of our Pension Plan assets by asset category:
2023
2022
December 31,
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Cash and cash equivalents
Equity investments - Individual securities
(a):
$
1,665
$
—
$
—
$
(in thousands)
1,665
$
5,422
$
—
$
—
$
5,422
Consumer discretionary
Consumer durables
Energy
Financials
Health Care
Industrials & materials
Information technology &
communication
Fixed income investments - Individual
securities (b):
Preferred stocks non-convertible
Equity investments - Mutual funds (c):
Mid-cap stock funds
Small-cap stock funds
International stock funds
Equity investments - Exchange traded
funds (d):
Large-cap blend - S&P 500 index
International - Developed markets
International - Emerging markets
Accrued income (e)
2,605
2,088
952
4,852
4,296
4,507
8,102
37
11,847
4,007
7,849
18,044
3,138
1,894
—
$ 75,883 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
29
29 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,605
2,088
952
4,852
4,296
4,507
8,102
37
11,847
4,007
7,849
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
18,044
3,138
1,894
29
$ 75,912
$
—
—
—
—
5,422 $
—
—
—
—
— $
Commingled investment funds measured at
net asset value (f):
Equities - United States
Equities - United States futures
Equities - International developed
markets
Equities - International developed
markets futures
Equities - International emerging
markets
Equities - International emerging
markets futures
Fixed income - Investment grade
Fixed income - High yield
Fixed income - Futures
Alternatives
Total
—
—
—
—
—
—
21,340
—
—
—
$ 97,252
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5,422
$
36,259
(697)
14,214
(1,693)
782
3,289
13,856
156
8,590
11,951
$ 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.
136
(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:
Non-vested grants at January 1, 2021
Granted (1)
Forfeited
Non-vested grants at December 31, 2021
Granted (1)
Forfeited
Non-vested grants at December 31, 2022
Granted (1)
Vested (2)
Forfeited
Non-vested grants at December 31, 2023
Number of units
Weighted average
grant date fair
value per unit
Intrinsic value
(in thousands)
1,430,489 $
1,818,190
(118,204)
3,130,475
769,907
(203,249)
3,697,133
450,125
(1,291,330)
(145,584)
2,710,344
5.02 $
6.03
5.48
5.59
14.65
6.93
7.40
21.54
5.02
6.86
10.91
6,409
39,569
75,126
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.
137
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
(in thousands)
Phantom units outstanding as of January 1, 2021
Granted
Settled (1)
Phantom units outstanding as of December 31, 2021
Granted
Phantom units outstanding as of December 31, 2022
Granted
Settled (1)
Phantom units outstanding as of December 31, 2023
760,630 $
46,638
(138,570)
668,698
73,842
742,540
118,737
(49,331)
811,946
22.04 $
9.45
25.86
20.37
19.44
20.28
20.46
20.27
20.44
3,408
8,452
15,088
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
Cash Paid For:
Interest
Income taxes
Non-Cash Activity:
Accounts payable for purchase of property, plant and equipment
Right-of-use assets acquired by operating lease
Market value of common units distributed under deferred compensation plans
before tax withholding requirements
2023
Year Ended December 31,
2022
(in thousands)
2021
37,126 $
34,844 $
13,615 $
23,794 $
36,402
11
14,586 $
44,281 $
2,596 $
1,315 $
28,906 $
— $
8,325
189
1,082
$
$
$
$
$
138
18.
ASSET RETIREMENT OBLIGATIONS
The following table presents the activity affecting the asset retirement and mine closing liability:
Year Ended December 31,
2023
2022
(in thousands)
Beginning balance
Accretion expense
Payments
Allocation of liability associated with mine development and change in
assumptions
Ending balance
$
149,813 $
4,433
(2,317)
131,099
3,731
(2,445)
(1,486)
150,443 $
17,428
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:
Year Ended
December 31,
2024
2025
2026
2027
2028
Thereafter
Aggregate undiscounted asset retirement obligations
Less: effect of discounting
Total asset retirement obligations
Less: current portion
Non-current asset retirement obligations
(in thousands)
$
$
3,518
5,557
4,063
7,038
4,291
242,134
266,601
(116,158)
150,443
(3,518)
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.
139
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):
Beginning balance
Changes in accruals
Payments
Interest accretion
Valuation loss (gain)
Ending balance
December 31,
2023
2022
$
$
49,452 $
12,155
(14,438)
2,202
(1,396)
47,975 $
53,448
7,384
(12,708)
1,147
181
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:
Benefit obligations at beginning of year
Service cost
Interest cost
Actuarial loss (gain)
Benefits and expenses paid
Benefit obligations at end of year
December 31,
2023
2022
(in thousands)
$
$
104,287 $
2,698
4,951
25,615
(5,107)
132,444 $
111,316
3,798
2,991
(9,840)
(3,978)
104,287
140
The following is a reconciliation of the changes in the pneumoconiosis benefit obligation recognized in accumulated
other comprehensive loss:
Net actuarial gain (loss)
Reversal of amortization item:
Net actuarial loss
Total recognized in accumulated other comprehensive loss
$
2023
Year Ended December 31,
2022
(in thousands)
2021
$
(25,615) $
9,840 $
(161)
1,382
(24,233) $
1,038
10,878 $
4,172
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
Year Ended December 31,
2022
(in thousands)
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:
Workers' compensation claims
Pneumoconiosis benefit claims
Total obligations
Less current portion
Non-current obligations
December 31,
2023
2022
(in thousands)
$
$
47,975 $
132,444
180,419
(15,913)
164,506 $
49,452
104,287
153,739
(14,099)
139,640
Both the pneumoconiosis benefit and workers' compensation obligations were unfunded at December 31, 2023 and
2022.
141
The pneumoconiosis benefit and workers' compensation expense consists of the following components:
2023
Year Ended December 31,
2022
(in thousands)
2021
Black lung benefits:
Service cost
Interest cost (1)
Net amortization (1)
$
2,698
4,951
1,382
9,031
15,152
24,183
$
$
3,798
2,991
1,038
7,827
11,675
19,502
4,021
2,545
4,172
10,738
8,339
19,077
Total pneumoconiosis expense
Workers' compensation expense
Net periodic benefit cost
________________________________________
(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.
142
Affiliate Coal Lease Agreements
The following table summarizes advanced royalties outstanding and related payments and recoupments under our
affiliate coal lease agreements:
Craft Foundations
Tunnel
Ridge
Acquired
2005
Towhead
Coal
Henderson
& Union
WKY CoalPlay
Webster
Henderson
WKY
Coal
Coal
Webster
Henderson
CoalPlay
Henderson
& Union
Counties, KY County, KY County, KY Counties, KY
Total
Acquired
Acquired
Acquired
Acquired
2014
2014
2014
2015
(in thousands)
$
$
1,500
3,000
(3,000)
—
1,500
3,000
(3,000)
—
1,500
3,000
(3,000)
—
1,500
$
$
19,178 $
3,597
(1,025)
—
21,750
3,597
(3,255)
—
22,092
3,597
(4,258)
—
21,431 $
— $
2,568
—
(2,568)
—
—
—
—
—
—
—
—
— $
15,129 $
2,521
—
—
17,650
2,522
—
—
20,172
2,521
—
—
22,693 $
12,582 $
2,131
—
—
14,713
2,131
—
—
16,844
2,131
—
—
18,975 $
48,389
13,817
(4,025)
(2,568)
55,613
11,250
(6,255)
—
60,608
11,249
(7,258)
—
64,599
As of January 1, 2021
Payments
Recoupment
Unrecoupable
As of December 31, 2021
Payments
Recoupment
Unrecoupable
As of December 31, 2022
Payments
Recoupment
Unrecoupable
As of December 31, 2023
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.
143
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.
144
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
Year Ended December 31,
2022
(in thousands)
2021
Customer A
Customer B
Customer C
Customer D
Illinois Basin/Appalachia
$
Illinois Basin
Illinois Basin
Illinois Basin/Appalachia
332,500
253,573
—
—
$
— $
260,146
328,406
228,480
—
—
239,482
—
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
145
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
Illinois
Basin
Appalachia
Oil & Gas
Coal
(in thousands)
Other,
Corporate and
Elimination
Consolidated
Year Ended December 31, 2023
Revenues - Outside (1)
Revenues - Intercompany
Total revenues (1)
$
1,481,556 $
—
1,481,556
883,334 $
—
883,334
141,525 $
—
141,525
42 $
65,572
65,614
60,244 $
(65,572)
(5,328)
2,566,701
—
2,566,701
Segment Adjusted EBITDA
Expense (2)
Segment Adjusted EBITDA (3)
Total assets
Capital expenditures (4)
Year Ended December 31, 2022
861,288
514,118
966,102
257,885
516,471
330,723
488,427
116,217
16,532
121,508
781,184
—
24,451
41,163
315,592
400
(14,024)
4,661
237,121
4,836
1,404,718
1,012,173
2,788,426
379,338
Revenues - Outside (1)
Revenues - Intercompany
Total revenues (1)
$
1,296,305 $
—
1,296,305
928,087 $
—
928,087
154,897 $
—
154,897
56 $
60,624
60,680
40,622 $
(60,624)
(20,002)
2,419,967
—
2,419,967
Segment Adjusted EBITDA
Expense (2)
Segment Adjusted EBITDA (3)
Total assets
Capital expenditures (4)
Year Ended December 31, 2021
806,080
420,684
779,018
158,624
464,029
426,402
431,913
76,603
15,395
143,179
778,465
—
21,871
38,809
321,587
38,276
(23,497)
3,495
417,038
12,891
1,283,878
1,032,569
2,728,021
286,394
Revenues - Outside (1)
Revenues - Intercompany
Total revenues (1)
$
919,597 $
—
919,597
545,539 $
—
545,539
86,439 $
—
86,439
69 $
51,402
51,471
27,586 $
(51,402)
(23,816)
1,579,230
—
1,579,230
Segment Adjusted EBITDA
Expense (2)
Segment Adjusted EBITDA (3)
Total assets
Capital expenditures (4)
613,303
265,292
676,091
60,166
344,332
172,601
420,144
47,577
11,051
76,920
698,702
—
18,269
33,202
285,943
45
(33,198)
9,383
146,601
15,196
953,757
557,398
2,227,481
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.
146
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:
Operating expenses (excluding depreciation, depletion
and amortization)
Outside coal purchases
Other expense (income)
Segment Adjusted EBITDA Expense
$
$
Year Ended December 31,
2023
2022
(in thousands)
2021
1,368,787
36,149
(218)
1,404,718
$
$
1,288,082
151
(4,355)
1,283,878
$
$
944,419
6,372
2,966
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:
Year Ended December 31,
2023
2022
(in thousands)
2021
Net income
Noncontrolling interest
Net income attributable to ARLP
General and administrative
Depreciation, depletion and amortization
Interest expense, net
Income tax expense
Consolidated Segment Adjusted EBITDA
$
$
$
636,170
(6,052)
630,118
79,096
267,982
26,697
8,280
1,012,173
$
$
$
$
$
588,158
(1,958)
586,200
80,425
276,670
35,296
53,978
1,032,569 $
183,369
(598)
182,771
70,275
264,794
39,141
417
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.
147
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:
Acquisition costs of properties
Proved
Unproved
Total
2023
Year Ended December 31,
2022
(in thousands)
2021
$
$
21,943 $
16,741
38,684 $
44,986 $
47,785
92,771 $
12,542
18,418
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:
2023
As of December 31,
2022
(in thousands)
2021
Our Share
of an
Equity
Method
Investee Consolidated
Our Share
of an
Equity
Method
Investee Consolidated
Our Share
of an
Equity
Method
Investee
Consolidated
Proved properties
Unproved properties
Total
Less accumulated depreciation,
depletion and amortization
Oil & gas properties, net
$
438,378 $
414,972
853,350
14,950 $
13,295
28,245
388,358 $
426,309
814,667
11,965 $
16,193
28,158
318,250 $
403,645
721,895
9,138
19,216
28,354
(144,561)
708,789 $
(5,183)
23,062 $
(117,982)
696,685 $
(3,912)
24,246 $
(85,038)
636,857 $
(3,015)
25,339
$
148
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.
Consolidated activities
Oil & gas royalties
Other revenues
Production costs and severance taxes
Depreciation, depletion and amortization
Income tax expense
Total results of oil & gas activities
Our share of an equity method investee
Oil & gas royalties
Other revenues
Production costs and severance taxes
Depreciation, depletion and amortization
Total results of oil & gas activities
Oil & Gas Reserves
2023
Year Ended December 31,
2022
(in thousands)
2021
$
$
$
$
137,751 $
3,774
(13,423)
(36,865)
(14,568)
76,669 $
4,719 $
102
(638)
(1,142)
3,041 $
151,060 $
3,837
(13,200)
(30,034)
(54,842)
56,821 $
7,292 $
37
(916)
(897)
5,516 $
84,183
2,256
(8,511)
(25,684)
—
52,244
3,788
66
(472)
(787)
2,595
The net proved developed and undeveloped oil & gas reserves quantities of the mineral interests attributable to us are
summarized below:
Consolidated activities
As of January 1, 2021
Purchases of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2021 (1)
Purchases of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2022 (1)
Purchases of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2023 (1)
Crude Oil
Natural Gas Natural Gas Liquids
(MBbl)
(MMcf)
(MBbl)
Total
(MBOE)
7,517
287
(404)
677
(898)
7,179
859
(24)
2,060
(1,061)
9,013
361
(175)
1,252
(1,418)
9,033
34,055
2,149
132
621
(3,460)
33,497
3,619
4,686
8,334
(4,814)
45,322
2,421
2,177
4,460
(5,759)
48,621
3,340
332
177
387
(402)
3,834
497
668
1,018
(541)
5,476
142
559
654
(726)
6,105
16,533
977
(205)
1,168
(1,877)
16,596
1,960
1,425
4,466
(2,404)
22,043
907
748
2,649
(3,105)
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.
149
Our share of an equity method investee
As of January 1, 2021
Sales of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2021
Sales of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2022
Sales of minerals in place
Revisions of previous estimates
Extensions and discoveries
Production
As of December 31, 2023
Crude Oil Natural Gas Natural Gas Liquids Total
(MBbl)
(MMcf)
(MBbl)
(MBOE)
342
(9)
(50)
73
(31)
325
(7)
17
57
(43)
349
—
(46)
61
(44)
320
2,052
(15)
320
450
(421)
2,386
(18)
210
294
(412)
2,460
—
74
770
(402)
2,902
188
—
(53)
43
—
178
(4)
13
25
—
212
—
(23)
59
—
248
873
(12)
(51)
190
(101)
899
(14)
66
132
(112)
971
—
(57)
248
(110)
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
Net proved developed reserves as of
December 31, 2022
Net proved developed reserves as of
December 31, 2023
Net proved undeveloped reserves as of
December 31, 2021
Net proved undeveloped reserves as of
December 31, 2022
Net proved undeveloped reserves as of
December 31, 2023
6,016
31,211
3,369
14,587
7,551
41,173
4,806
19,219
7,754
45,684
5,485
20,854
1,488
4,672
1,811
6,609
1,599
5,839
643
882
868
2,908
3,795
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.
150
• 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.
2023
As of December 31,
2022
(in thousands)
2021
Our Share
of an
Equity
Method
Investee Consolidated
Our Share
of an
Equity
Method
Investee Consolidated
Our Share
of an
Equity
Method
Investee
Consolidated
$
914,461 $
34,986 $ 1,275,564 $
52,636 $
636,933 $
31,636
(69,507)
(194,339)
(2,548)
—
(97,158)
(255,504)
(4,287)
—
(48,013)
—
(2,484)
—
650,615
32,438
922,902
48,349
588,920
29,152
Future cash inflows
Future production costs and
severance taxes
Future income tax expense (1)
Future net cash flows
(undiscounted)
Annual discount 10% for
estimated timing
Total standardized measure (2) $
335,288 $
17,586 $
456,657 $
24,445 $
299,883 $
(315,327)
(14,852)
(466,245)
(23,904)
(289,037)
(13,980)
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.
151
The average realized product prices weighted by production over the remaining lives of the properties are presented
in the table below:
Oil (per Bbl)
Natural gas (per Mcf)
NGLs (per Bbl)
For the Year Ended December 31,
2022
2021
2023
$
77.61 $
1.55
22.63
92.5 $
5.43
35.87
63.57
2.98
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:
2023
As of December 31,
2022
(in thousands)
2021
Our
Share of
an
Equity
Method
Investee Consolidated
Our
Share of
an
Equity
Method
Investee Consolidated
Our
Share of
an
Equity
Method
Investee
Consolidated
Standardized measure, beginning of year
$
456,657 $ 24,445 $
299,883 $ 15,172 $
Purchases and sales of reserves in place, less related costs
Sales, net of production costs
Net changes due to extensions and discoveries
Net changes in prices and production costs
Revisions of previous quantity estimates
Net changes in income taxes (1)
Accretion of discount
Changes in timing and other
Net increase (decrease) in standardized measures
Standardized measure, end of year
$
17,519
(124,328)
60,628
(185,935)
15,479
36,699
39,912
18,657
(121,369)
335,288 $ 17,586 $
—
(4,081)
3,582
(7,960)
(686)
—
1,839
447
(6,859)
(265)
55,812
(6,376)
(137,860)
5,139
149,721
8,386
211,222
344
21,457
—
(138,047)
1,086
23,283
959
(28,814)
156,774
9,273
456,657 $ 24,445 $
165,483 $ 7,764
(264)
15,358
(3,316)
(75,672)
3,613
37,395
6,753
132,427
(871)
9,252
—
—
545
12,933
948
2,707
134,400
7,408
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.
152
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)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Total current assets
OTHER ASSETS:
Investments in consolidated subsidiaries
Total other assets
TOTAL ASSETS
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accrued taxes other than income taxes
Total current liabilities
Total liabilities
PARTNERS' CAPITAL:
December 31,
2023
2022*
$
$
$
2,043
2,043
$
2,174
2,174
1,894,158
1,894,158
1,896,201
174
174
174
$
$
1,720,499
1,720,499
1,722,673
100
100
100
Limited Partners - Common Unitholders 127,125,437 and 127,195,219 units outstanding,
respectively
General Partner's interest
Total Partners' Capital
1,656,025
66,548
1,722,573
1,722,673
TOTAL LIABILITIES AND PARTNERS' CAPITAL
* 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.
1,896,027
—
1,896,027
1,896,201
$
$
CONDENSED STATEMENTS OF OPERATIONS (PARENT)
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands, except unit and per unit data)
EXPENSES:
General and administrative
Total operating expenses
LOSS FROM OPERATIONS
Interest income
Equity in earnings of consolidated subsidiaries
NET INCOME ATTRIBUTABLE TO ARLP
NET INCOME ATTRIBUTABLE TO ARLP
GENERAL PARTNER
LIMITED PARTNERS
EARNINGS PER LIMITED PARTNER UNIT - BASIC AND DILUTED
2023
Year Ended December 31,
2022*
2021*
$
$
151
151
(151)
57
630,212
630,118
1,384
628,734
4.81
$
$
$
$
$
$
$
$
—
—
—
—
586,200
586,200
9,010
577,190
4.39
$
$
$
$
$
—
—
—
—
182,771
182,771
4,614
178,157
1.36
WEIGHTED-AVERAGE NUMBER OF UNITS OUTSTANDING – BASIC
AND DILUTED
* 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.
127,180,312
127,195,219
127,195,219
153
CONDENSED STATEMENTS OF CASH FLOWS (PARENT)
FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
$
364,448
$
196,348
$
52,157
Year Ended December 31,
2022*
2023
2021*
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions paid to Partners
Net cash used in financing activities
NET CHANGE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS AT END OF PERIOD
* 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.
$
$
$
(364,579)
(364,579)
(131)
2,174
2,043
(196,347)
(196,347)
1
2,173
2,174
(52,158)
(52,158)
(1)
2,174
2,173
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.
154
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.
155
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.
156
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
February 23, 2024
157
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.
158
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE
GENERAL PARTNER
As is commonly the case with publicly traded limited partnerships, we are managed and operated by our general
partner. The following table shows information for executive officers and members of the Board of Directors as of the
date of the filing of this Annual Report on Form 10-K. Executive officers and directors are elected until death, resignation,
retirement, disqualification, or removal.
Name
Age
Position With Our General Partner
Joseph W. Craft III
73 Chairman, President and Chief Executive Officer
Brian L. Cantrell
64 Former Senior Vice President and Chief Financial Officer
Megan J. Cordle
51 Vice President, Controller and Chief Accounting Officer
R. Eberley Davis
66 Senior Vice President, General Counsel and Secretary
Cary P. Marshall
59 Senior Vice President and Chief Financial Officer
Robert G. Sachse
75 Executive Vice President
Kirk D. Tholen
51 Senior Vice President; also President, Alliance Minerals, LLC
Timothy J. Whelan
61 Senior Vice President - Sales and Marketing of Alliance Coal, LLC
D. Andrew Woodward
41 Senior Vice President - New Ventures
Thomas M. Wynne
67 Senior Vice President and Chief Operating Officer
Nick Carter
77 Director and Member of Audit, Compensation and Conflicts Committees
Robert J. Druten
76 Director and Member of Audit, Compensation and Conflicts* Committees
John H. Robinson
73 Director and Member of Audit, Compensation* and Conflicts Committees
Wilson M. Torrence
82 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
159
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.
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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,
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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.
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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
Nick Carter
Robert J. Druten
John H. Robinson
Code of Ethics
We have adopted a code of ethics with which the Chairman, President and CEO and the senior financial officers
(including the principal financial officer and the principal accounting officer) are expected to comply. The code of ethics
is publicly available on our website under "Investor Relations" at www.arlp.com and is available in print without charge
to any unitholder who requests it. Such requests should be directed to Investor Relations at (918) 295-7673. If any
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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
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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
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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
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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.
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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
168
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).
169
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
Nick Carter
Robert J. Druten
Wilson M. Torrence
Notwithstanding anything to the contrary set forth in any of our previous filings under the Securities Act or the
Exchange Act, that incorporate future filings, including this Annual Report on Form 10-K, in whole or in part, the
foregoing Compensation Committee Report shall not be deemed to be filed with the SEC or incorporated by reference into
any filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.
170
Summary Compensation Table
Name and Principal
Position (1)
Joseph W. Craft III
President, Chief Executive
Officer and Chairman
Cary P. Marshall,
Senior Vice President and
Chief Financial Officer
Brian L. Cantrell,
Former Senior Vice President and
Chief Financial Officer
R. Eberley Davis
Senior Vice President,
General Counsel and Secretary
Kirk D. Tholen
Senior Vice President; also
President Alliance Minerals, LLC
Thomas M. Wynne
Senior Vice President and
Chief Operating Officer
Year
2023
2022
2021
2023
2023
2022
2021
2023
2022
2021
2023
2022
2021
2023
2022
2021
Salary
($)(2)
Bonus
($)(3)
Unit
Awards
($)(4)
Non-Equity
Incentive Plan
Compensation Compensation
All Other
($)(5)
($)(6)
Total
1
1
1
—
—
—
—
—
—
—
—
—
—
—
—
1
1
1
293,269
26,340
666,555
220,000
63,368
1,269,532
105,231
304,000
309,846
365,000
362,693
351,635
500,000
500,000
509,615
430,000
427,000
411,769
789,241
117,723
—
50,966
152,898
—
1,000,000
1,000,000
500,000
58,393
175,179
—
—
—
567,182
634,461
629,541
722,394
734,083
1,040,560
1,194,061
734,083
728,391
835,818
—
340,000
250,000
285,000
365,000
365,000
341,000
531,920
540,000
345,000
460,000
400,000
6,548
54,089
30,443
83,247
86,600
41,768
223,014
204,252
152,688
101,155
87,433
43,588
901,020
815,812
1,157,471
1,418,674
1,596,732
1,480,797
2,798,097
3,276,732
2,896,364
1,668,631
1,878,003
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 $10,000. A reconciliation of the 2023 amounts is as
follows:
171
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
SERP ($)
Profit Sharing Plan
Employer
Contribution ($)
Perquisites (a)
Total ($)
—
24,632
—
56,847
196,614
62,905
—
$
—
23,461
6,548
26,400
26,400
26,400
15,275
—
—
—
11,850
—
63,368
6,548
83,247
223,014
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 $11,850.
172
Estimated Future Payouts Under
Non-Equity Incentive Plan Awards
Target
($)(4)
Threshold
($)(3)
($)(3)
(#)(5)
Estimated Future Payouts Under
Equity Incentive Plan Awards
All Other
Unit
Awards:
Grant Date
Fair Value
of Unit
Maximum Threshold
Maximum Number of
Grants of Plan-Based Awards Table
Name
Grant Date
Approved Date
Joseph W. Craft III
February 14, 2023
May 15, 2023
August 14, 2023
November 14, 2023
(1), (2)
(1), (2)
(1), (2)
(1), (2)
Cary P. Marshall
February 15, 2023 February 15, 2023
February 14, 2023
May 15, 2023
August 14, 2023
November 14, 2023
December 31, 2023
January 27, 2023
(1), (2)
(1), (2)
(1), (2)
(1), (2)
(2)
February 7, 2024
Brian L. Cantrell
February 14, 2023
(1), (2)
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
February 15, 2023 February 15, 2023
February 14, 2023
May 15, 2023
August 14, 2023
November 14, 2023
December 31, 2023
January 27, 2023
(1), (2)
(1), (2)
(1), (2)
(1), (2)
(2)
February 7, 2024
February 15, 2023 February 15, 2023
February 14, 2023
May 15, 2023
August 14, 2023
November 14, 2023
December 31, 2023
January 27, 2023
(1), (2)
(1), (2)
(1), (2)
(1), (2)
(2)
February 7, 2024
February 15, 2023 February 15, 2023
February 14, 2023
May 15, 2023
August 14, 2023
November 14, 2023
December 31, 2023
January 27, 2023
(1), (2)
(1), (2)
(1), (2)
(1), (2)
(2)
February 7, 2024
220,000
220,000
285,000
285,000
341,000
341,000
345,000
345,000
Target
(#)(6)
30,945
—
—
—
—
—
—
30,945
29,455
—
—
—
—
—
—
29,455
34,080
—
—
—
—
—
—
34,080
34,080
—
—
—
—
—
—
34,080
(#)(5)
Units (#)(7) Awards ($)(8)
10,273
11,676
11,982
10,978
44,909
—
1,515
1,722
1,767
1,620
1,163
—
7,787
216,966
224,062
239,041
245,907
925,976
666,555
31,997
33,045
35,252
36,288
24,632
—
827,769
1,543
1,543
32,588
32,588
—
2,370
2,693
2,764
2,532
2,684
—
13,043
—
1,855
2,108
2,163
1,982
9,283
—
17,391
634,461
50,054
51,679
55,142
56,717
56,847
—
904,900
734,083
39,178
40,453
43,152
44,397
196,614
—
1,097,877
—
2,366
2,690
2,760
2,529
2,970
—
13,315 $
734,083
49,970
51,621
55,062
56,650
62,905
—
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.
173
(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.
174
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:
Name
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
Salary and
Bonus as a % of
Salary and
Bonus ($) (1)
Total
Compensation ($)
Total
Compensation ($)(1)
1
1
100.0%
319,609
1,269,532
894,472
901,020
415,966
1,418,674
1,500,000
2,798,097
488,393
1,668,631
25.2%
99.3%
29.3%
53.6%
29.3%
Year
2023
2023
2023
2023
2023
2023
(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.
175
Outstanding Equity Awards at 2023 Fiscal Year End Table
Name
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
Equity
Incentive Plan
Awards:
Number of
Unearned
Units or Other
Rights That
Have Not
Vested (#)(1)
Equity
Incentive Plan
Awards:
Market or
Payout Value
of Unearned
Units or
Other Rights
That Have
Not Vested ($)(2)
—
$
124,278
—
196,447
310,103
227,292
—
2,632,208
—
4,160,748
6,567,982
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:
Name
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
2024
—
January 1,
2025
—
2026
—
64,160
29,173
30,945
—
119,800
198,020
138,610
—
47,192
78,003
54,602
—
29,455
34,080
34,080
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 $21.18 per unit, the closing price of our common units on December 29, 2023, the final
market trading day of 2023.
176
Units Vested Table for 2023
Name
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Thomas M. Wynne
Unit Awards
Number of Units
Acquired on Vesting
(#)(1)
Value Realized on
Vesting ($)(1)
—
$
—
51,842
69,152
88,078
—
1,053,429
1,405,169
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 $20.32 per unit, the closing price on December 30, 2022, the final
market trading day of 2022. Please see "Item 11. Compensation Discussion and Analysis—Compensation
Components—Equity Awards under the LTIP."
Nonqualified Deferred Compensation Table for 2023
Name
Joseph W. Craft III
Cary P. Marshall
Brian L. Cantrell
R. Eberley Davis
Kirk D. Tholen
Executive
Contributions
in Last Fiscal
Year ($) (1)
Registrant
Contributions
in Last Fiscal
Year ($) (2)
—
—
Aggregate
Earnings
in Last Fiscal
Year ($) (3)
1,224,776
Aggregate
Withdrawals/ Aggregate
Distributions
Balance
in Last Fiscal
Year ($) (4)
at Last Fiscal
Year End ($) (5)
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
Thomas M. Wynne
—
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.
177
(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.
178
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
Non-Equity
Change in Pension
Value and
Name
Robert J. Druten
John H. Robinson
Wilson M. Torrence
Nick Carter
$
Fees earned
or Paid in
Cash ($)
Unit
Awards
($) (2)(3)
Option
Awards
($)(1)
Incentive Plan Nonqualified Deferred
Compensation
($)(1)
Compensation
Earnings ($)(1)
All Other
Compensation
($)(1)
Total ($)
195,000 $
195,000
215,000
185,000
36,930 $
—
30,332
—
— $
—
—
—
— $
—
—
—
— $
—
—
—
— $
—
—
—
231,930
195,000
245,332
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:
Name
Robert J. Druten
John H. Robinson
Wilson M. Torrence
Nick Carter
Directors
Deferred
Compensation
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
179
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
180
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.
181
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.
Name of Beneficial Owner
Directors and Executive Officers
Joseph W. Craft III (1)
Nick Carter
Robert J. Druten
John H. Robinson
Wilson M. Torrence
Brian L. Cantrell
R. Eberley Davis
Cary P. Marshall (2)
Kirk D. Tholen
Thomas M. Wynne (3)
All directors and executive officers as a group (14 persons)
5% Common Unit Holder
Kathleen Mowry
*
Less than one percent.
Common Units
Beneficially Owned
Percentage of Common
Units
Beneficially Owned
18,800,000
20,000
25,628
7,462
40,396
252,193
262,446
1,077,748
110,396
1,284,334
22,392,314
16,167,865
14.7%
*
*
*
*
*
*
*
*
1.0%
17.5%
12.6%
(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.
182
Equity Compensation Plan Information
Plan Category
Equity compensation plans approved
by unitholders:
Long-Term Incentive Plan
Equity compensation plans not
approved by unitholders:
Supplemental Executive
Retirement Plan
Directors' Deferred
Compensation
Number of units to be issued upon
exercise/vesting of outstanding
options, warrants and rights
as of December 31, 2023
Weighted-average exercise
price of outstanding options, under equity compensation plans
Number of units remaining
available for future issuance
warrants and rights
as of December 31, 2023
2,710,344
N/A
7,886,556
785,186
26,760
N/A
N/A
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.
183
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:
Audit Fees (1)
Audit-related fees (2)
Tax fees (3)
All other fees
Total
2023
2022
(in thousands)
748 $
207
—
—
955 $
813
59
—
—
872
$
$
(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.
184
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) (1)
Financial Statements and Supplementary Data.
PART IV
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
100
102
103
104
105
106
107
107
109
117
120
121
122
124
126
127
127
128
130
131
132
133
137
138
139
140
142
144
144
145
148
Supplemental Oil & Gas Reserve Information (Unaudited)
(a)(2)
Financial Statement Schedule.
Schedule I – Condensed Financial Information of Registrant
153
All other schedules are omitted because they are not applicable or the information is shown in the financial statements or
notes thereto.
185
(a)(3) and (c) The exhibits listed below are filed as part of this annual report.
Exhibit
Number
Exhibit Description
Form
SEC
File No. and
Film No.
Exhibit Filing Date
Filed
Herewith*
Incorporated by Reference
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
4.1
Fourth Amended and Restated Agreement of
Limited Partnership of Alliance Resource
Partners, L.P.
8-K
000-26823
17990766
3.2
07/28/2017
Amended and Restated Agreement of Limited
Partnership of Alliance Resource Operating
Partners, L.P.
10-K
000-26823
583595
3.2
03/29/2000
Amended and Restated Certificate of Limited
Partnership of Alliance Resource Partners, L.P.
8-K
Certificate of Limited Partnership of Alliance
Resource Operating Partners, L.P.
S-1/A
000-26823
17990766
333-78845
99669102
3.6
07/28/2017
3.8
07/23/1999
Certificate of Formation of Alliance Resource
Management GP, LLC
S-1/A
333-78845
99669102
3.7
07/23/1999
Amendment No. 1 to the Fourth Amended
and Restated Agreement of Limited
Partnership of Alliance Resource Partners,
L.P.
Amendment No. 2 to Fourth Amended and
Restated Agreement of Limited Partnership
of Alliance Resource Partners, L.P., dated as
of May 31, 2018.
Amendment No. 3 to Fourth Amended and
Restated Agreement of Limited Partnership
of Alliance Resource Partners, L.P., dated as
of June 1, 2018.
Amendment No. 1 to Amended and Restated
Agreement of Limited Partnership of Alliance
Resource Operating Partners, L.P., dated as of
May 31, 2018.
Third Amended and Restated Operating
Agreement
Resource
Management GP, LLC, dated as of May 31,
2018.
Alliance
of
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).
10-K
000-26823
18634680
3.9
02/23/2018
8-K
000-26823
1883834
3.3
06/06/2018
8-K
000-26823
1883834
3.4
06/06/2018
8-K
000-26823
1883834
3.5
06/06/2018
8-K
000-26823
1883834
3.7
06/06/2018
8-K
000-26823
17990766
3.2
07/28/2017
186
Exhibit
Number
4.2
4.3
4.4
10.1
Exhibit Description
Form
Incorporated by Reference
SEC
File No. and
Film No.
Exhibit Filing Date
Filed
Herewith*
Indenture, dated as of April 24, 2017, by and
among Alliance Resource Operating Partners,
L.P.
and Alliance Resource Finance
Corporation, as issuers, Alliance Resource
Partners, L.P., as parent, the subsidiary
guarantors party thereto and Wells Fargo
Bank, National Association, as trustee.
8-K
000-26823
17798539
4.1
04/24/2017
Form of 7.500% Senior Note due 2025
(included in Exhibit 4.2).
8-K
000-26823
17778550
4.1
04/24/2017
Description of the Registrant's Securities
registered under Section 12 of the Securities
Exchange Act of 1934.
Contribution and Assumption Agreement, dated
August 16, 1999, among Alliance Resource
Holdings, Inc., Alliance Resource Management
GP, LLC, Alliance Resource GP, LLC, Alliance
Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. and the other parties
named therein
10-K
000-26823,
23666549
4.4
02/24/2023
10-K
000-26823
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.
10-K
000-26823
583595
10.4
03/29/2000
10.3(1)
Alliance Coal, LLC Short-Term Incentive Plan
10-K
10.4(1)
Alliance Coal, LLC Supplemental Executive
Retirement Plan
10.5(1)
Alliance Resource Management GP, LLC
Deferred Compensation Plan for Directors
S-8
S-8
000-26823
583595
333-85258
02595143
333-85258
02595143
10.12
03/29/2000
99.2
04/01/2002
99.3
04/01/2002
10.6
10.7
Third Amended and Restated Charter for the
Audit Committee of the Board of Directors
Second Amendment to the Omnibus Agreement
dated May 15, 2006 by and among Alliance
Resource Partners, L.P., Alliance Resource GP,
LLC, Alliance Resource Management GP, LLC,
Alliance Resource Holdings, Inc., Alliance
Resource Holdings II, Inc., AMH-II, LLC,
Alliance Holdings GP, L.P., Alliance GP, LLC
and Alliance Management Holdings, LLC
10.8
Administrative Services Agreement dated
May 15, 2006 among Alliance Resource
Partners, L.P., Alliance Resource Management
GP, LLC, Alliance Resource Holdings II, Inc.,
10-Q
000-26823
061017824
10.1
08/09/2006
10-Q
000-26823
061017824
10.2
08/09/2006
187
Exhibit
Number
Exhibit Description
Form
SEC
File No. and
Film No.
Exhibit Filing Date
Filed
Herewith*
Incorporated by Reference
Alliance Holdings GP, L.P. and Alliance GP,
LLC
10.9(1)
First Amendment to the Alliance Coal, LLC
Short-Term Incentive Plan
10-K
000-26823
07660999
10.52
03/01/2007
10.10(1)
Second Amendment to the Alliance Coal, LLC
Short-Term Incentive Plan
10-K
000-26823
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
10-K
000-26823
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
10-K
000-26823
11645603
10.42
02/28/2011
10.13
10.14
10.15
Amended and Restated Charter
the
Compensation Committee of the Board of
Directors dated January 27, 2023.
for
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.
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
10-Q
000-26823
101000555
10.1
08/09/2010
8-K
000-26823
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
10-K
000-26823
161460619
10.46
02/26/2016
10.17
First Amendment to the Receivables Financing
Agreement, dated as of December 4, 2015
10-Q
000-26823
161634229
10.1
05/10/2016
10.18
the Receivables
Second Amendment
Financing Agreement, dated as of February 24,
2016
to
10-Q
000-26823
161634229
10.2
05/10/2016
10.19
Third Amendment to the Receivables Financing
Agreement, dated as of December 2, 2016
10-K
000-26823
17636362
10.45
02/24/2017
188
Exhibit
Number
10.20
Exhibit Description
Form
Incorporated by Reference
SEC
File No. and
Film No.
Exhibit Filing Date
Filed
Herewith*
the Receivables
Fourth Amendment
Financing Agreement, dated as of November 27,
2017
to
10-K
000-26823
18634680
10.47
02/23/2018
10.21
Fifth Amendment to the Receivables Financing
Agreement, dated as of January 17, 2018
10-K
000-26823
18634680
10.48
02/23/2018
10.22
Sixth Amendment to the Receivables Financing
Agreement, dated as of June 19, 2018
10-Q
000-26823
18994075
10.2
08/06/2018
10.23
10.24
10.25
Seventh Amendment
the Receivables
Financing Agreement, dated as of January 16,
2019
to
10-K
000-26823
19624803
10.52
02/22/2019
Eighth Amendment
the Receivables
Financing Agreement, dated as of October 22,
2019.
to
10-Q
000-26823
191192460
10.2
11/05/2019
and Restated Credit
Fifth Amended
Agreement, dated as of March 9, 2020, by and
among Alliance Resource Operating Partners,
L.P., as borrower, JPMorgan Chase Bank,
N.A., as administrative agent, and the lenders
party thereto.
8-K
000-26823
20711345
10.1
03/13/2020
10.26
Fifth Amendment to the Amended and Restated
Alliance Coal, LLC 2000 Long-Term Incentive
Plan.
8-K
000-26823
201385345
10.1
12/14/2020
10.27
Ninth Amendment to the Receivables Financing
Agreement, dated as of January 15, 2021.
10-K
000-26823
21663570
10.64
02/23/2021
10.28
Tenth Amendment to the Receivables Financing
Agreement, dated as of January 14, 2022.
10-K
000-26823
22677260
10.57
02/25/2022
10.29
10.30
Eleventh Amendment
the Receivables
Financing Agreement, dated as of January 13,
2023.
to
10-K
000-26823
23666549
10.54
02/24/2023
Thirteenth Amendment to the Receivables
Financing Agreement, dated as of January 12,
2024.
10-K
189
8-K
000-26823
23540292
10.1
01/20/2023
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
therein as
institutions named
documentation agents.
10.32
Sixth Amendment to the Amended and
Restated Alliance Coal, LLC 2000 Long-
Term Incentive Plan.
8-K
000-26823
221401012
10.1
11/18/2022
14.1
Code of Ethics for Principal Executive Officer
and Senior Financial Officers
10-K
000-26823
13656028
14.1
03/01/2013
21.1
List of Subsidiaries.
23.1
Consent of Grant Thornton LLP.
23.2
Consent of Cawley, Gillespie & Associates, Inc.
31.1
31.2
32.1
32.2
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.,
to
dated February 23,
Section 302 of the Sarbanes-Oxley Act of 2002.
pursuant
2024,
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.
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.
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.
190
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
000-26823
221205681
96.3
08/26/2022
96.4
96.5
97.1
99.1
101
Gibson South Mine SEC S-K 1300 Technical
Report Summary dated February 2022.
10-K/A
000-26823
221205681
96.4
08/26/2022
Tunnel Ridge Mine SEC S-K 1300 Technical
Report Summary dated February 2023.
Alliance Resource Partners, L.P. Incentive
Based Compensation Recoupment Policy
Report of Cawley, Gillespie & Associates,
Inc., dated December 7, 2023
Interactive Data File (Form 10-K for the year
ended December 31, 2023 filed
in Inline
XBRL).
104
Cover Page Interactive Data File (formatted as
Inline XBRL and contained in Exhibit 101).
* Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).
(1) Denotes management contract or compensatory plan or arrangement.
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
Joseph W. Craft III
President, Chief Executive
Officer and Chairman
191
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
Joseph W. Craft III
President, Chief Executive Officer,
and Chairman (Principal Executive Officer)
February 23, 2024
Senior Vice President and
Chief Financial Officer (Principal Financial Officer)
February 23, 2024
/s/ Cary P. Marshall
Cary P. Marshall
/s/ Megan J. Cordle
Megan J. Cordle
/s/ Nick Carter
Nick Carter
/s/ Robert J. Druten
Robert J. Druten
/s/ John H. Robinson
John H. Robinson
Vice President, Controller and
Chief Accounting Officer (Principal Accounting
Officer)
Director
Director
Director
February 23, 2024
February 23, 2024
February 23, 2024
February 23, 2024
February 23, 2024
/s/ Wilson M. Torrence
Wilson M. Torrence
Director
192
P.O. Box 22027, Tulsa, Oklahoma 74121-2027 | www.arlp.com