What changed in this filing

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Item 1. Business

2023-02-24 compared with 2022-02-25 · 207 added, 165 removed, 659 unchanged (36% of the section changed)

We are a diversified natural resource company that generates operating income from the production and marketing of coal and royalty income from coal and oil & gas mineral interests located in strategic producing regions across the United States.

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.

We believe that our diverse and rich resource base will allow us to continue to create long-term value for unitholders.

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 currently the second-largest coal producer in the eastern United States with seven operating underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia as well as a coal-loading terminal in Indiana on the Ohio River.

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We market our coal production to major domestic and international utilities and industrial users.

We currently own both mineral and royalty interests in approximately 1.5 million gross acres in premier oil & gas producing regions in the United States, primarily the Permian, Anadarko, and Williston Basins.

While we own both mineral and royalty interests, we refer to them collectively as mineral interests throughout our discussions of our business as the majority of our holdings are mineral interests.

We market our mineral interests for lease to operators in those regions and generate royalty income from the leasing and development of those mineral interests.

We currently own mineral and royalty interests in approximately 61,400 net royalty acres 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 currently have approximately 580.7 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia.

All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties, which are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased.

Substantially, all of our measured, indicated and inferred coal mineral resources and 464.8 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 Francis Renewable Energy, LLC ("Francis"), Infinitum Electric, Inc.

("Infinitum"), and NGP ETP IV, L.P.

("NGP ETP IV") as described below.

In addition, we develop and market industrial, mining and technology products and services.

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We are managed by our sole general partner, MGP, a Delaware limited liability company, which holds a non-economic general partner interest in ARLP.

AllDale I & II Acquisition

On January 3, 2019 (the "Acquisition Date"), we acquired the general partner interests and all of the limited partner interests not owned by Cavalier Minerals JV, LLC ("Cavalier Minerals") in AllDale Minerals, LP ("AllDale I") and AllDale Minerals II, LP ("AllDale II", and collectively with AllDale I, "AllDale I & II") for $176.2 million (the "AllDale Acquisition").

ARLP indirectly owns a 96.0% non-managing member interest and a non-economic managing member interest in Cavalier Minerals.

The AllDale Acquisition provided us with diversified exposure to industry-leading operators.

Wing Acquisition

On August 2, 2019, our subsidiary AR Midland, LP ("AR Midland") acquired from Wing Resources LLC and Wing Resources II LLC (collectively, "Wing") approximately 9,000 oil & gas net royalty acres in the Midland Basin for $144.9 million (the "Wing Acquisition").

The Wing Acquisition enhanced our ownership position in the Permian Basin and expanded our exposure to industry-leading operators.

Boulders Acquisition

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

Oil & Gas Acquisitions

On October 13, 2021, AR Midland, LP ("AR Midland"), an indirect subsidiary of Alliance Minerals, acquired approximately 1,480 oil & gas net royalty acres in the Delaware Basin from Boulders Royalty Corp.

("Boulders") for a purchase price of $31.0 million (the "Boulders Acquisition").

The Boulders Acquisition also enhanced our ownership position in the Permian Basin.

These acquisitions furthered our business strategy to grow our Oil & Gas Royalties segment through accretive acquisitions.

See "Item 8.

Financial Statements and Supplementary Data—Note 3 – Acquisitions"

for more information.

We now hold approximately 57,000 net royalty acres in premier oil & gas resource plays.

On September 9, 2022, AR Midland 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").

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

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 will assist us in the identification, evaluation, and acquisition of target oil & gas mineral interests.

In exchange for these services, the third party will receive a participation share, partially funded by the third party, and will be paid a periodic management fee.

On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources LP ("JC Resources"), a related party entity owned by Mr.

Craft, for $72.3 million, which was funded with cash on hand (the "JC Resources Acquisition").

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

New Ventures Investments

On April 5, 2022, we made a $20.0 million convertible note investment 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.

On April 29, 2022, we purchased $32.6 million of Series D Preferred Stock in 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 November 2, 2022, we purchased an additional $9.4 million of Series D Preferred Stock in Infinitum.

The preferred stock provides for non-cumulative dividends when and if declared by Infinitum's board of directors.

Each share is convertible, at any time, at our option, into shares of common stock of Infinitum.

On June 2, 2022, we committed to purchase $25.0 million of limited partner interests in NGP ETP IV, a private equity fund sponsored by NGP Energy Capital Management, LLC ("NGP").

As of December 31, 2022 we have funded $4.1 million of this commitment.

NGP ETP 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.

Our investments in the advancement of energy and related infrastructure further our business strategy to develop strategic relationships and invest in attractive opportunities.

For more information on our acquisitions and investments, please read "Item 8.

Financial Statements and Supplementary Data—Note 3 – Acquisitions","—Note 13 – Variable Interest Entities", "—Note 14 – Investments"

and "—Note 26 – Subsequent Events"

of this Annual Report on Form 10-K.

The following diagram depicts our simplified organization and ownership as of December 31, 2022:

Our internet address is http://www.arlp.com , and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, Forms 3, 4 and 5 for our Section 16 filers and other documents (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC.

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 http://www.sec.gov .

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 production of steel but is also used for chemical, food, and cement processing.

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 while operating our mines with an industry-leading safety record.

At December 31, 2021, our mining operations had access to approximately 547.1 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana,

Kentucky, Maryland, Pennsylvania, and West Virginia.

All of our measured, indicated and inferred coal mineral resources and 422.9 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties and are currently leased or subleased or held for lease or sublease to our mining operations or others.

We have established long-term relationships with customers through exemplary and consistent performance.

At December 31, 2022, our mining operations had access to approximately 580.7 million tons of proven and probable coal mineral reserves and 1.17 billion tons of measured, indicated and inferred coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia.

Substantially, all of our measured, indicated and inferred coal mineral resources and 464.8 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 2022, we sold 35.6 million tons of coal and produced 35.5 million tons.

Of the 32.3 million tons sold, approximately two-thirds was leased from Alliance Resource Properties.

Of the 35.6 million tons sold, approximately two-thirds were leased from Alliance Resource Properties.

The coal we sold in 2022 was approximately 4.4% low-sulfur coal, 60.4% medium-sulfur coal, and 35.2% high-sulfur coal.

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Production from the mine began in April 2014.

Gibson County Coal production in 2022 was 5.3 million tons.

Hamilton Complex.

Our subsidiary, Hamilton County Coal, LLC ("Hamilton"), operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois.

The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal, longwall mining began in October 2014 and we acquired complete ownership and control in 2015.

The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal.

Longwall mining began in October 2014 and we acquired complete ownership and control in 2015.

Hamilton's preparation plant has throughput capacity of 2,000 tons of raw coal per hour.

Hamilton has the ability to ship production from the Hamilton mine via the CSX, Evansville Western Railway, or NS rail directly to customers or various transloading facilities, including our Mt.

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 2022 was 4.7 million tons.

River View Complex.

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Coal produced from the River View mine is transported by overland belt to a barge loading facility on the Ohio River.

River View coal production in 2022 was 10.2 million tons.

Warrior Complex .

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Vernon transloading facility, for barge deliveries.

Warrior coal production in 2022 was 4.1 million tons.

Vernon Transfer Terminal, LLC.

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Our subsidiary, MC Mining, LLC ("MC Mining"), through our subsidiary, Excel Mining, LLC ("Excel") operates the Excel Mine No.

Excel completed development of Mine No.

Excel completed the development of Mine No.

5 in May 2020 and transitioned its employees and equipment from Mine No.

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The existing preparation plant, which has throughput capacity of 1,000 tons of raw coal per hour, is utilized by Mine No.

Substantially all of the coal produced at MC Mining in 2021 met or exceeded the compliance requirements of Phase II of the Federal Clean Air Act ("CAA") (see "—Environmental, Health and Safety Regulations— Air Emissions "

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 to various docks on the Big Sandy River for barge deliveries.

Substantially all of the coal produced at MC Mining in 2022 met or exceeded the compliance requirements of Phase II of the Federal Clean Air Act

("CAA") (see "—Environmental, Health and Safety Regulations— Air Emissions "

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 2022 was 1.5 million tons.

Mettiki Complex.

The Mettiki Complex ("Mettiki") comprises the Mountain View mine located in Tucker County, West Virginia operated by our subsidiary Mettiki Coal (WV), LLC ("Mettiki (WV)") and a preparation plant located near the city of Oakland in Garrett County, Maryland operated by our subsidiary Mettiki Coal, LLC ("Mettiki (MD)").

Mettiki (WV) and began longwall mining in November 2006.

The Mountain View mine produces medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical coal market or otherwise, or directly to the coal blending facility at the Virginia Electric and Power Company Mt.

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.

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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 2022 was 1.4 million tons.

Tunnel Ridge Complex.

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The Tunnel Ridge preparation plant has throughput capacity of 2,000 tons of raw coal per hour.

Coal produced from the Tunnel Ridge mine is a medium/high-sulfur coal and is transported by conveyor belt to a barge loading facility on the Ohio River.

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 2022 was 8.3 million tons.

Coal Marketing and Sales

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Although some utility customers have appeared to favor a shorter-term contracting strategy, in 2022 approximately 85.0% and 65.6% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2022 to 2029.

As of February 11, 2022, our nominal commitment under contract was approximately 33.1 million tons for delivery in 2022.

Our initial 2023 guidance includes 34.7 million priced and committed tons for delivery in 2023.

The contractual time commitments for customers to nominate future purchase volumes under these contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity.

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Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract.

The long-term contracts typically stipulate procedures for transportation of coal, quality control, sampling, and weighing.

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.

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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.

Our sales into the international coal market are considered exports and are made through brokered transactions.

During the years ended December 31, 2022, 2021, and 2020, export tons represented approximately 12.5%, 12.5% and 3.3% of tons sold, respectively.

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Reliance on Major Customers

In 2021, we derived more than 10% of our total revenue from Louisville Gas and Electric Company.

In 2022, we derived more than 10% of our total revenue from each of Duke Energy, Louisville Gas and Electric Company, and Tennessee Valley Authority.

We did not derive 10% or more of our revenues from any other single customer.

For more information about this customer, please read "Item 8.

For more information about these customers, please read "Item 8.

Financial Statement and Supplemental Data—Note 24 – Concentration of Credit Risk and Major Customers."

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In addition, we seek to export a portion of our coal into the international coal markets and we compete with companies that produce coal from one or more foreign countries.

The prices we are able to obtain for our export coal have been influenced by a number of factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

The prices we are able to obtain for our export coal have been influenced by many factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

The prices we are able to obtain for our domestic sales of coal are primarily linked to coal consumption patterns of domestic electricity-generating utilities, which in turn are influenced by economic activity, government regulations, weather, and technological developments, as well as the location, quality, price and availability of competing sources of fuel and alternative energy sources such as natural gas, nuclear energy, petroleum and renewable energy sources for electrical power generation.

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Approximately 51.8% of our 2022 sales volume was initially shipped from the mining complexes by barge, 30.0% was shipped from the mining complexes by rail, and 18.2% was shipped from the mining complexes by truck.

The practices of, rates set by and capacity availability of, the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mining complex.

The practices of, rates set by and capacity availability of, the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts 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.

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Our mineral interest activities include both oil & gas and coal mineral interests.

Our oil & gas mineral interest business includes all activities related to the oil & gas mineral interests held by AR Midland and AllDale I & II and includes Alliance Minerals' equity interest in AllDale Minerals III, L.P.

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 Minerals III, L.P.

("AllDale III").

AR Midland acquired its mineral interests in the Wing and Boulders Acquisitions.

Our mineral interests are primarily located on private lands in three basins, which are also our areas of focus for future development by operators.

These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) Basins.

Our developed and undeveloped net acres standardized to a 1/8th royalty equate to approximately 57,000 oil & gas net royalty acres, including 3,976 oil & gas net royalty acres owned through our equity interest in AllDale III.

Our coal mineral interests include all of our measured, indicated and inferred coal mineral resources and 422.9 million tons of coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased.

Our developed and undeveloped net acres standardized to a 1/8th royalty equate to nearly 61,400 oil & gas net royalty acres, including 3,968 oil & gas net royalty acres owned through our equity interest in AllDale III.

Our coal mineral interests include substantially all of our measured, indicated and inferred coal mineral resources and 464.8 million tons of coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased.

Our coal mineral interests are located in both the Illinois Basin and the Appalachia Basin.

Oil & Gas Royalties

When our oil & gas mineral interests are leased, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to receive a fixed percentage of the revenue or production from the oil & gas produced from the acreage underlying our interests, free of lease operating expenses and capital costs.

In 2014, we began to invest in oil & gas mineral interests in some of the nation's premier oil-rich basins.

Beginning in 2019, we transitioned from a passive investor in mineral interests to an active and material participant in oil & gas minerals.

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.

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Unlike owners of working interests in oil & gas properties, we are not obligated to fund drilling and completion costs, lease operating expenses, or plugging and abandonment costs associated with oil & gas production.

The following chart summarizes the production of our oil & gas mineral interests for the year ended December 31, 2021, 2020, and 2019:

The following chart summarizes the production of our oil & gas mineral interests for the year ended December 31, 2022, 2021, and 2020, not including our equity interest in AllDale III:

Year Ended December 31,

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

In 2014, we began to invest in oil & gas mineral interests in some of the nation's premier oil-rich basins.

Beginning in 2019, we transitioned from a passive investor in mineral interests to an active and material participant in oil & gas minerals.

Permian Basin—Delaware and Midland Basins

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Based on geologic data and the ongoing development by operators, our mineral interests in the Permian Basin contain multiple producing zones of economic horizontal development including but not limited to the Wolfcamp, Spraberry, and Bone Spring formations.

Our recent purchase of acreage located entirely in the Permian Basin through the Boulders Acquisition demonstrates our commitment to continued acquisition of mineral interests in the nation's highest growth oil & gas plays.

Our recent purchases of acreage located entirely in the Permian Basin through the Belvedere Acquisition, the Jase Acquisition and the JC Resources Acquisition demonstrate our commitment to continued acquisition of mineral interests in the nation's highest growth oil & gas plays.

Anadarko Basin—SCOOP and STACK Plays

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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.

Based on geologic data and the ongoing development by operators, our mineral interests in the STACK play contain multiple producing zones of economic horizontal development including but not limited to the Meramec and Woodford formations.

Williston Basin—Bakken

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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.

Our other interests are comprised primarily of mineral interests owned in the Appalachia Basin that stretches throughout most of Ohio, West Virginia, Pennsylvania, and extends into other states.

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.

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Coal Royalties

Our Coal Royalties segment includes approximately 422.9 million tons of proven and probable reserves and all of the 1.17 billion tons of our measured, indicated and inferred coal mineral resources.

Our Coal Royalties segment includes approximately 464.8 million tons of proven and probable reserves and substantially all of the 1.17 billion tons of our measured, indicated and inferred coal mineral resources.

Our coal mineral reserves and resources are located in the Appalachia and Illinois Basins in the United States.

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Illinois Basin:

Appalachian Basin:

Mining Access:

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Slope & Shaft

Mining Method:

Mining Access:

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Mining Method:

Medium/High-Sulfur

& Continuous Miner

Low/Medium-Sulfur

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Barge, Railroad,

Medium/High-Sulfur

Transportation:

Barge & Truck

Barge, Railroad

Transportation:

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HENDERSON/UNION

Appalachian Basin:

MOUNTAIN VIEW

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Slope & Shaft

Mining Method:

Continuous Miner

Mining Access:

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Mining Method:

Medium/High-Sulfur

Continuous Miner

Mining Method:

Medium/High-Sulfur

& Continuous Miner

Transportation:

Barge & Truck

& Continuous Miner

Medium/High-Sulfur

Sulfur - Metallurgical

Transportation:

Barge, Railroad

Sulfur - Metallurgical

Transportation:

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Medium/High-Sulfur

Mining Access:

Slope & Shaft

Mining Method:

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Barge, Railroad

Mining Access:

Slope & Shaft

Mining Method:

Medium/High-Sulfur

& Continuous Miner

Medium/High-Sulfur

Transportation:

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& Continuous Miner

Mining Access:

Slope & Shaft

Mining Method:

Medium/High-Sulfur

Transportation:

Barge & Truck

Illinois Basin

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

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

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Financial Statements and Supplementary Data—Note 22 – Related-Party Transactions."

Approximately 6.5 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Gibson County Coal.

Approximately 128.5 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Hamilton.

Approximately 206.8 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, River View.

Approximately 77.1 million tons of these reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Warrior.

Approximately 76.0 million tons of these resources are currently leased/subleased or held for lease/sublease to our subsidiary, Webster County Coal, LLC ("Webster County Coal").

Sebree South .

Approximately 43.5 million tons of these resources are currently leased/subleased to our subsidiary, Sebree Mining, LLC ("Sebree").

Alliance Resource Properties holds miscellaneous non-strategic coal properties in the Illinois Basin that are not under lease or currently anticipated to be leased to any of our operating companies.

Approximately 388.0 million tons of proven and probable reserves and 1.08 billion tons of measured, indicated and inferred coal mineral resources are controlled by Alliance Resource Properties in the Illinois Basin and are leased/subleased or held for lease/sublease to our mining complexes or third parties as follows:

Approximately 5.7 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Gibson County Coal.

Approximately 565.2 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Hamilton.

Approximately 197.1 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, River View.

Approximately 59.7 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Warrior.

Henderson/Union.

Approximately 520.8 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.

Approximately 76.0 million tons of the resources are currently leased/subleased or held for lease/sublease to our subsidiary, Webster County Coal, LLC ("Webster County Coal").

Sebree South .

Approximately 43.5 million tons of the resources are currently leased/subleased to our subsidiary, Sebree Mining, LLC ("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:

● Grant County, West Virginia

● Tucker County, West Virginia

● Washington County, Pennsylvania

Approximately 76.8 million tons of proven and probable reserves and 85.4 million tons of measured, indicated and inferred coal mineral resources are controlled by Alliance Resource Properties in the Appalachian Basin and are leased/subleased or held for lease/sublease to our mining complexes or third parties as follows:

Tunnel Ridge .

Approximately 71.5 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Tunnel Ridge, LLC.

Mountain View.

Alliance Resource Properties holds coal mineral reserves and resources in Grant County and Tucker County, West Virginia, estimated to include approximately 10.7 million tons of medium sulfur coal, all of which is currently leased/subleased or held for lease/sublease to our subsidiary, Mettiki (WV).

Approximately 12.7 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Mettiki (WV).

Penn Ridge Resources.

Alliance Resource Properties holds coal mineral resources in Washington County, Pennsylvania, (the "Penn Ridge Resources") estimated to include approximately 78.0 million tons of measured, indicated and inferred high-sulfur coal in the Pittsburgh No.

These resources are near our Tunnel Ridge mining complex but are not currently leased.

Leasing of these resources is dependent upon further development by Tunnel Ridge or third-party mining complexes, which is regulatory and market dependent.

Alliance Resource Properties holds miscellaneous non-strategic coal properties in the Appalachia Basin that are not under lease.

Leasing of these properties is dependent upon mining complexes nearby deciding to develop a project, which is regulatory and market dependent.

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

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We also face competition from land companies, coal producers, and international steel companies in purchasing coal mineral reserves and resources as well as royalty-producing properties.

Numerous producers in the coal industry make coal marketing very competitive.

Our mining complexes in which we lease our reserves compete with coal producers in various regions of the United States for domestic sales on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer, and the reliability of supply.

Continued demand for our coal and the prices that our lessees obtain are also affected by demand for electricity and steel, as well as government regulations, technological developments, and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar, and hydroelectric power.

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".

Minerals Interest - Seasonal Nature of Business

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.

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Other Operations

Coal Brokerage

As markets allow, Alliance Coal buys coal from our mining operations and outside producers principally throughout the eastern United States, which we then resell.

We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal.

Our subsidiaries, Matrix Design Group, LLC ("Matrix Design") and its subsidiaries Matrix Design International, LLC and Matrix Design Africa (PTY) LTD, and Alliance Design Group, LLC ("Alliance Design") (collectively the Matrix Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties.

Our subsidiaries, Matrix Design Group, LLC ("Matrix Design") and its subsidiaries Matrix Design International, LLC, Matrix Design (Australia) PTY LTD and Matrix Design Africa (PTY) LTD, and Alliance Design Group, LLC ("Alliance Design") (collectively the Matrix Design entities and Alliance Design are referred to as the "Matrix Group"), provide a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties.

Matrix Group's products and services include data network, communication and tracking systems, mining proximity detection systems, industrial collision avoidance systems, and data and analytics software.

We acquired Matrix Design in September 2006.

Additional Services

We develop and market additional services to establish ourselves as the supplier of choice for our customers.

Historically, and in 2021, outside revenues from these services were immaterial.

Our subsidiary, AROP II, LLC, and its subsidiary, AROP II Investments, LLC, make 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.

We have made investments of $20 million in Francis, $42 million in Infinitum and, as of December 31, 2022, $4.1 million (of a $25 million commitment) in NGP ETP IV.

In 2022, revenues from these investments were immaterial.

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.

Environmental, Health, and Safety Regulations

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We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary.

The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the estimated costs and timing assumptions of asset retirement obligations and mine closing procedures.

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.

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These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction.

Meeting all requirements imposed by any of these authorities may be costly and time-consuming and may delay or prevent commencement or continuation of mining operations.

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.

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Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations.

MSHA has published a request for information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, which is currently set to close on July 9, 2022.

It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.

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

MSHA published a request for information regarding engineering controls and best practices to lower miners' exposure to respirable coal mine dust and the comment period closed in July 2022.

It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period.

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

● In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.

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Black Lung Benefits Act

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 ("BLBA") requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses where no responsible coal mine operator has been identified for claims.

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 ("BLBA") require businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses where no responsible coal mine operator has been identified for claims.

The coal we sell into international markets is generally not subject to this tax.

In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax.

Effective January 1, 2019, the trust fund was funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

Effective January 1, 2020, the trust fund was funded by an excise tax on coal sold of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

Effective January 1, 2022, the trust fund is funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

It is uncertain as to whether the excise tax rates will be adjusted in the future or whether any such modifications would be retroactive.

As of January 1, 2022, the trust fund was funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

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.

Workers ' Compensation and Black Lung

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however, the final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites.

The Federal Office of Surface Mining ("OSM") has announced its intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken.

The Federal Office of Surface Mining ("OSM") has announced its intention to release a proposed rule to regulate the placement and use of CCRs at coal mine sites, but, to date, no further action has been taken.

These actions by OSM potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

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CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers.

The full impacts of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.

The full impacts of CSAPR are presently unknown due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.

● In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants.

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In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule.

In April 2017, the D.C Circuit Court of Appeals granted the EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding.

In April 2017, the D.C.

Circuit Court of Appeals granted the EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding.

In December 2018, the EPA issued a proposed Supplemental Cost Finding, as well as the CAA required "risk and technology review."

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However, in February 2022, EPA published a proposed rule proposing to revoke the May 2020 finding.

The final rule remains pending.

Although various issues surrounding the MATS rule remain subject to litigation in the D.C.

Circuit, the MATS rule has forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule.

Circuit, the MATS rule has forced electric power generators to make capital investments to retrofit power plants and

could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule.

The announced and possible additional retirements are likely to reduce the demand for coal.

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Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter ("PM"), ozone, nitrogen oxide, and sulfur dioxide.

As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs

for areas that were previously in "attainment"

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.

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In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone;

however, various entities filed litigation against one or both of these rulemakings, and the Biden Administration has announced that it will reconsider and potentially revise the NAAQS and consider instituting a more stringent standard.

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.

However, with respect to ozone, a draft assessment released in April 2022 indicates EPA staff have reached a preliminary conclusion that the December 2020 decision will stand, but uncertainty remains until a final decision is reached.

New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers.

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The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program.

Several of these lawsuits have settled, but others remain pending.

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.

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Additionally, in November 2021, EPA issued a proposed rule that, if finalized, would establish new source and first-time existing source standards of performance for GHG and volatile organic compound ("VOC") emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities.

EPA plans to issue a supplemental proposal in 2022 containing additional requirements not included in the November 2021 proposed rule and anticipates the issuance of final rule by the end of the year.

In November 2022, EPA published a supplemental methane proposal which, among other items, sets forth specific revisions strengthening the first nationwide emissions guidelines for states to limit methane emissions from existing crude oil and natural gas facilities.

The proposal also revises 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.

The proposal is currently subject to public comment and is expected to be finalized in 2023;

however, it is likely that it will be subject to legal challenges.

Oil & gas production on the properties in which we hold mineral interests could be adversely affected to the extent any final rule imposes increased operating costs on the oil & gas industry.

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Future regulation of GHG emissions in the United States could occur pursuant to future United States treaty commitments, new domestic legislation, or regulation by the EPA.

Although no comprehensive climate change regulation has been adopted at the federal level in the United States, President Biden announced that climate change will be a focus of his administration.

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.

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Although the United States had withdrawn from the Paris Agreement, President Biden recommitted the United States in February 2021 and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030.

The international community gathered again in Glasgow in November 2021 at the 26th Conference to the Parties ("COP26") during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures.

The international community gathered again at the 26th Conference to the Parties ("COP26") during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures.

Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions"

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Also at COP26, more than forty countries pledged to phase out coal, although the United States did not sign the pledge.

The impact of these actions remain unclear at this time.

At COP27, 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.

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 could be negatively impacted, which would have an adverse effect on our operations.

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.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S.

Supreme Court's 2007 decision that the EPA has authority to regulate GHG emissions.

Supreme Court's 2007 decision that the EPA has the authority to regulate GHG emissions.

Although the U.S.

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Several rulemakings have been issued under the NSPS that constrain the GHG emissions of fossil-fuel-fired power plants.

In January 2021, the EPA published a final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations.

In January 2021, the EPA published a final significant contribution

finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations.

However, this finding also excludes several sectors and may, therefore, be subject to revision, and future implementation of the NSPS is uncertain at this time.

The EPA is expected to publish a notice of proposed rulemaking in Spring 2023.

In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO2 emission performance rates.

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In June 2019, the EPA published the final repeal of the CPP and promulgation of the ACE rule.

The EPA's attempts to replace the CPP with the ACE rule are currently subject to litigation, and on January 19, 2021, the Circuit Court struck down the ACE rule, though the case is not yet final with oral arguments scheduled before the U.S.

Supreme Court on February 28, 2022.

We cannot predict the outcome of the litigation.

Notwithstanding the ACE rule, requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal.

Congress has not currently adopted legislation to restrict carbon dioxide emissions from existing power plants and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP.

Substantial limitations on GHG emissions could adversely affect demand for the coal we produce or the oil & gas produced from our mineral interests.

On January 19, 2021, the Circuit Court struck down the ACE rule and found the EPA's "repeal of the CPP rested critically on a mistaken reading of the CAA."

On June 30, 2022, the Supreme Court of the United States reversed and remanded the Circuit Court's decision in West Virginia v.

EPA and found that, in the promulgation of the CPP, the EPA had acted outside the bounds of the legal authority granted to the agency by Congress.

Notwithstanding the ACE rule, the CPP's requirements and impact during the pendency of the litigation led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal.

Congress has not currently adopted legislation to restrict carbon dioxide emissions from existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v.

EPA , including as it relates to authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP.

We cannot predict whether such legislation will be signed into law in the future.

There have been numerous protests and challenges to the permitting of new fossil-fuel infrastructure, including power plants and pipelines, by environmental organizations and state regulators for concerns related to GHG emissions.

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These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects.

In July 2020, the Council on Environmental Quality ("CEQ") finalized revisions to NEPA regulations that clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA.

However, in October 2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions.

A final rule is expected in 2022.

Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities.

In April 2022, the Council on Environmental Quality ("CEQ") issued a final rule revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporated the consideration of direct, indirect and cumulative effects of major federal actions, including GHG emissions.

And, in January 2023, the CEQ released guidance, effective immediately, to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA.

For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement ("RGGI"), calling for the implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states.

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Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers, while Virginia has withdrawn from RGGI via executive order by its governor.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020.

These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners, though only California and certain Canadian provinces are currently active participants in the Western Climate Initiative.

These regional efforts will likely continue based on current trends and concerns related to the reduction of GHG emissions.

Similar to RGGI, five western states launched the Western Regional Climate Initiative, although only California 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.

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Any future use of the EPA's Section 404 "veto"

power could create uncertainly with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues.

In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on fictitious mine scenario.

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.

Total Maximum Daily Load ("TMDL") regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body.

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.

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Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings have been subject to substantial litigation.

On August 30, 2021, the US District Court for Arizona granted a request for voluntary remand of the EPA's rule.

The Biden Administration has announced plans to establish its own definition of "waters of the United States"

("WOTUS").

Most recently, the EPA and the Corps of Engineers published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway.

Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the CWA and the definition of WOTUS.

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 December 2022, the EPA and Corps of Engineers released a final revised definition of "waters of the United States"

("WOTUS") founded upon a pre-2015 definition and including updates to incorporate existing Supreme Court decisions.

However, continued uncertainty remains as to the government's jurisdictional reach as the rule is likely to be subject to legal challenge.

Judicial developments further add to this uncertainty.

In October 2022, the Supreme Court heard oral arguments in Sackett v.

EPA regarding the scope and authority of the CWA and the definition of WOTUS and is expected to release an opinion in this case in 2023, which could impact the regulatory definition and its implementation.

To the extent any decision expands the scope of the EPA and the Corps of Engineers' jurisdiction under the CWA, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

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into the environment.

These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site.

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.

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The CCB rule was subject to legal challenge and ultimately remanded to the EPA.

On August 28, 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances.

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 is expected to finalize additional rules addressing those specific provisions in 2022 and 2023.

Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities who sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule.

While the EPA issued one conditional approval, the EPA is requiring the remaining facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022.

The EPA is expected to finalize additional rules addressing those specific provisions in June 2023.

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 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.

The combined effect of the CCB rules and the Effluent Limitations Guidelines and Standards ("ELG") regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards.

Such retirements may adversely affect the demand for our coal.

On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards ("ELG"), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016.

The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades.

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.

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In August 2021, EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits.

EPA expects to issue a proposed rule for public comment in fall 2022.

EPA expects to issue a proposed rule for public comment in the summer of 2023.

It is unclear what impact these regulations will have on the market for our products.

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Fish and Wildlife Service (the "USFWS") works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil & gas exploration and production activities.

In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration;

namely, the USFWS plans to rescind the 2018 rule that revised the process for designating critical habitat for threatened and endangered species under the ESA and second, alongside the National Marine Fisheries Service, the USFWS proposes to rescind the 2020 regulatory definition of "habitat."

Final action on these proposed rules will occur in 2022.

In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration and, 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.

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Our workforce is entirely union-free.

Our typical employee has approximately eight years of experience with the Partnership and more than 50% of all employees remain employed for more than five years.

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.

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Workplace safety is fundamental to our culture.

By providing a work environment that rewards safety and encourages employee participation in the safety process, we strive to be the leader in safety performance in the coal mining industry.

We are focused on improving employee safety through regular training and continuous monitoring of our progress, including through the mining industry standard of "non-fatal days lost,"

or "NFDL,"

which reflects both the frequency and severity of injuries incurred.

Our NFDL rating of 3.26 for the year ended December 31, 2021, was below the preliminary industry average over the same time period.

In addition, we collected over 13,000 respirable dust samples of the mining environment where our miners regularly work and travel.

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 13,000 respirable dust samples from the mining environment where our miners regularly work and travel.

The average concentration of those samples was 55% below the regulatory standard.

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Furthermore, at each of our coal operations and corporate offices, we provide a human resource representative to assist employees with various human resource matters.

The Partnership also administers our medical plan, which allows us to control costs and work directly on behalf of our employees with health care providers enabling us in part, to continue providing health benefits with no out-of-pocket premiums for our employees.

We also have developed steps to enhance protections from, and minimize risks associated with, the spread of COVID-19, as needed.

Such steps include or have included, without limitation, staggering shift patterns to promote social distancing, enhanced cleaning procedures, promotion of recommended hygiene practices, limited workplace access, "touch-free"

check-in/check-out stations, wellness screening at mine locations, and requiring face coverings where appropriate.

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 benefits with no out-of-pocket premiums for our employees.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business