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Item 1. Business

2022-02-25 compared with 2021-02-23 · 313 added, 258 removed, 511 unchanged (53% of the section changed)

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

The primary focus of our business is to maximize the value of our existing mineral assets, both in the production of coal from our mining assets and the leasing and development of our oil & gas mineral ownership.

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

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

We manage and report our coal operations primarily under two regions, Illinois Basin and Appalachia.

We 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 believe that our diverse and rich resource base 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.

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.

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Reserve additions and the associated cash flows are expected to increase from the development of our existing mineral interests and through acquisitions of additional mineral interests.

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

We currently have 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, 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.

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

ARLP, a Delaware limited partnership, completed its initial public offering on August 19, 1999, and is listed on the NASDAQ Global Select Market under the ticker symbol "ARLP."

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

Simplification Transactions

On July 28, 2017, the conflicts committee ("Conflicts Committee") of the board of directors ("Board of Directors") of MGP and AGP's board of directors approved a transaction to simplify our partnership structure.

Pursuant to that transaction, which closed on the same date, MGP contributed to ARLP all of its incentive distribution rights ("IDRs") and its 0.99% managing general partner interest in ARLP in exchange for 56,100,000 ARLP common units and a non-economic general partner interest in ARLP.

In conjunction with this transaction and on the same economic basis as MGP, SGP also contributed to ARLP its 0.01% general partner interest in both ARLP and the Intermediate Partnership in exchange for 28,141 ARLP common units collectively (the "Exchange Transaction").

On February 22, 2018, our Board of Directors and the board of directors of AHGP's general partner approved a simplification agreement (the "Simplification Agreement") pursuant to which, among other things, through a series of transactions (the "Simplification Transactions"):

AHGP would become a wholly owned subsidiary of ARLP,

all of the issued and outstanding AHGP common units would be canceled and converted into the right to receive the ARLP common units held by AHGP and its subsidiaries,

in exchange for a number of ARLP common units calculated pursuant to the Simplification Agreement, MGP's 1.0001% general partner interest in our Intermediate Partnership and MGP's 0.001% managing member interest in our subsidiary, Alliance Coal, would be contributed to us, and

MGP would remain ARLP's sole general partner and would be a wholly owned subsidiary of AGP, and thus no control, management, or governance changes with respect to our business would occur.

The Simplification Agreement and the transactions contemplated thereby were approved by the written consent of approximately 68% of the holders of AHGP common units outstanding as of April 25, 2018, the record date for the consent solicitation.

On May 31, 2018, ARLP, AHGP, and the other parties to the Simplification Agreement completed the transactions contemplated by the Simplification Agreement.

Prior to the Simplification Transactions, MGP was a wholly owned indirect subsidiary of AHGP.

Alliance GP, LLC ("AGP"), which is indirectly wholly owned by Mr.

Craft, was the general partner of AHGP prior to the Simplification Transactions and became the direct owner of MGP as a result of those transactions.

See discussions under Partnership Simplification regarding changes in ownership of ARLP and MGP as a result of the Exchange Transaction and Simplification Transactions.

As part of the Simplification Transactions, (i) each AHGP common unit that was issued and outstanding at the effective time of the Simplification Transactions was canceled and converted into the right to receive a portion of the ARLP common units held by AHGP and its subsidiaries, and (ii) SGP became the sole limited partner in AHGP.

Each outstanding AHGP common unit, other than certain AHGP common units held by the Owners of SGP, converted into the right to receive approximately 1.4782 ARLP common units held by AHGP and its subsidiaries.

The remaining AHGP common units held by the Owners of SGP were canceled and converted into the right to receive 29,188,997 ARLP common units which equaled (i) the product of the number of certain AHGP common units held by the Owners of SGP multiplied by 1.4782, minus (ii) 1,322,388 ARLP common units.

In addition, ARLP issued 1,322,388 ARLP common units to the Owners of SGP in exchange for causing SGP to contribute to ARLP its remaining limited partner interest in AHGP, which included AHGP's indirect ownership of a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal, resulting in an overall exchange ratio to the Owners of SGP equal to that of the other AHGP unitholders.

Upon the issuance of ARLP common units to the Owners of SGP in exchange for the limited partner interest in AHGP, ARLP became a) the sole limited partner of AHGP and b) through AHGP, the indirect owner of a 1.0001% general partner interest in the Intermediate Partnership and a 0.001% managing member interest in Alliance Coal.

AllDale I & II Acquisition

On January 3, 2019 (the "Acquisition Date"), ARLP acquired the general partner interests and all of the limited partner interests not owned by Cavalier Minerals JV, LLC ("Cavalier Minerals") in AllDale Minerals, LP ("AllDale I") and AllDale Minerals II, LP ("AllDale II", and collectively with AllDale I, "AllDale I & II") for $176.2 million, which was funded with cash on hand and borrowings under our revolving credit facility (the "AllDale Acquisition").

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.

AllDale Acquisition provides ARLP with diversified exposure to industry leading operators and is consistent with our general business strategy to pursue accretive acquisitions.

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 net royalty acres in the Midland Basin, with exposure to more than 400,000 gross acres (the "Wing Acquisition").

The Wing Acquisition enhanced our ownership position in the Permian Basin, expanded our exposure to industry leading operators, and furthered our business strategy to grow our Minerals segment.

Following the Wing Acquisition, we hold approximately 55,500 net royalty acres in premier oil & gas resource plays including net royalty acres from our investment in AllDale Minerals III, LP ("AllDale III").

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.

("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.

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for more information.

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

The following diagram depicts our simplified organization and ownership as of December 31, 2021:

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Coal is used primarily for the generation of electric power and production of steel but is also used for chemical, food, and cement processing.

We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and for the production of steel (metallurgical).

We 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, 2020, we had approximately 1.7 billion tons of coal reserves in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia.

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 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 2021, we sold 32.3 million tons of coal and produced 32.2 million tons.

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

The coal we sold in 2021 was approximately 14.2% low-sulfur coal, 50.3% medium-sulfur coal, and 35.5% high-sulfur coal.

In 2020, approximately 94.2% of our tons sold were purchased by United States electric utilities and 3.3% were sold into the international markets through brokered transactions.

In 2021, approximately 81.6% of our tons sold were purchased by domestic electric utilities and 12.5% were sold into the international markets through brokered transactions.

The balance of our tons sold was to third-party resellers and industrial consumers.

For tons sold to United States electric utilities, 100% were sold to utility plants with installed pollution control devices.

For tons sold to domestic electric utilities, 99.9% 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 five years.

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

Year Ended December 31,

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

Designated reserves noted on the map and reserves associated with our mining complexes may be owned or held by Alliance Resource Properties, our land holding company, with intercompany leases to our mining complexes.

Illinois Basin Operations:

WARRIOR COMPLEX

SEBREE-ONTON COMPLEX

TUNNEL RIDGE COMPLEX

METTIKI COMPLEX

GIBSON COMPLEX

Onton Mine (Idled)

Tunnel Ridge Mine

Mountain View Mine

Gibson South Mine

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Slope & Shaft

Mining Access:

Slope & Shaft

Mining Method:

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Mining Method:

& Continuous Miner

Medium/High-Sulfur

Low/Medium-Sulfur

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Barge, Railroad,

Transportation:

Barge & Truck

Sulfur - Metallurgical

Transportation:

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Transportation:

Barge, Railroad

Appalachian Operations:

PENN RIDGE RESERVES

MC MINING COMPLEX

HAMILTON COMPLEX

TRANSFER TERMINAL

Excel Mine No.

Mining Access:

Slope & Shaft

TUNNEL RIDGE COMPLEX

Hamilton Mine

Rail or Truck to Ohio River Barge

Mining Method:

Tunnel Ridge Mine

Transloading Facility

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Slope & Shaft

& Continuous Miner

Mining Access:

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Mining Method:

Appalachian Operations:

Mining Method:

HENDERSON/UNION

Transportation:

Barge & Railroad

& Continuous Miner

MC MINING COMPLEX

& Continuous Miner

Medium/High-Sulfur

Excel Mine No.

Medium/High-Sulfur

Transportation:

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Mining Method:

Continuous Miner

Medium/High-Sulfur

METTIKI COMPLEX

RIVER VIEW COMPLEX

Transportation:

Barge & Truck

Mountain View Mine

River View Mine

DOTIKI RESERVES

Mining Access:

Slope & Shaft

Mining Method:

Transportation:

Barge, Railroad,

Mining Access:

Slope & Shaft

& Continuous Miner

Mining Method:

Medium/High-Sulfur

Sulfur - Metallurgical

Transportation:

Barge & Truck

Medium/High-Sulfur

Transportation:

Barge, Railroad

We lease most of our coal reserves from private parties and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal reserve area.

leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price.

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.

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Our Illinois Basin mining operations are located in western Kentucky, southern Illinois, and southern Indiana.

As of December 31, 2020, we had 1,670 employees, and we operate four active mining complexes in the Illinois Basin.

As of December 31, 2021, we have 1,862 employees, and we operate four active mining complexes in the Illinois Basin.

Gibson Complex.

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Production from the Gibson South mine is shipped by truck or transported by rail on the CSX Transportation, Inc.

("CSX") and Norfolk Southern Railway Company ("NS") railroads from the Gibson North rail loadout facility directly to customers or to various transloading facilities, including our Mt.

("CSX") or Norfolk Southern Railway Company ("NS") railroads from our rail loadout facility directly to customers or various transloading facilities, including our Mt.

Vernon Transfer Terminal, LLC ("Mt.

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Production from the mine began in April 2014.

Gibson County Coal also operated the Gibson North mine, an underground mine also located near the city of Princeton in Gibson County, Indiana.

The Gibson North mine began production in November 2000 and utilized continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal.

The Gibson North mine was idled in December 2015 in response to market conditions but resumed production in May 2018.

In November 2019, the Gibson North mine was again idled in response to market conditions and in May 2020, the Gibson North mine was reclaimed and sealed.

Hamilton Complex.

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

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

Initial development production from the continuous miner units began in 2013, longwall mining began in October 2014 and we acquired complete ownership and control in 2015.

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, and NS rail directly to customers or to various transloading facilities, including our Mt.

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.

Vernon transloading facility, for barge deliveries.

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Warrior's preparation plant has throughput capacity of 1,200 tons of raw coal per hour.

Warrior's production is shipped via the CSX and Paducah & Louisville Railway, Inc.

("PAL") railroads and by truck directly to customers or potentially to various transloading facilities, including our Mt.

Warrior's production is shipped via the CSX or Paducah & Louisville Railway, Inc.

("PAL") railroads or by truck directly to customers or potentially to various transloading facilities, including our Mt.

Vernon transloading facility, for barge deliveries.

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The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 200,000 tons.

During 2020, the terminal loaded approximately 425,000 tons for customers of Gibson County Coal and Hamilton.

Alliance Resource Properties .

Alliance Resource Properties, LLC and collectively with its subsidiaries ("Alliance Resource Properties") own or control coal reserves that they lease to certain of our subsidiaries that operate our mining complexes, including Gibson South, Hamilton, River View and Warrior.

In December 2014 and February 2015, WKY CoalPlay, LLC or its subsidiaries ("WKY CoalPlay"), which are related parties, entered into coal lease agreements with

us regarding coal reserves located in Henderson and Union Counties, Kentucky ("Henderson/Union Reserves") and Webster County, Kentucky.

For more information about the WKY CoalPlay transactions, please read "Item 8.

Financial Statements and Supplementary Data — Note 21 – Related-Party Transactions."

Dotiki Complex.

Our subsidiary, Webster County Coal, LLC ("Webster County Coal"), operated Dotiki, an underground mining complex located near the city of Providence in Webster County, Kentucky.

The complex opened in 1966, and we purchased the mine in 1971 and operated it until it ceased production in August 2019.

For information regarding Dotiki's remaining coal reserves, please read "Item 2.

Properties – Coal Reserves."

Hopkins Complex.

The Hopkins complex, which we acquired in January 1998, is located near the city of Madisonville in Hopkins County, Kentucky.

Our subsidiary, Hopkins County Coal, LLC ("Hopkins County Coal") operated the Elk Creek underground mine until it ceased production in April 2016.

We have begun performing reclamation activities at the complex.

For information regarding Hopkins' remaining coal reserves, please read "Item 2.

Properties Coal Reserves."

Pattiki Complex.

Our subsidiary, White County Coal, LLC ("White County Coal"), operated Pattiki, an underground mining complex located near the city of Carmi in White County, Illinois.

We began construction of the complex in 1980 and operated it until it ceased production in December 2016.

We have begun performing reclamation activities at the complex.

For information regarding Pattiki's remaining coal reserves, please read "Item 2.

Properties – Coal Reserves."

Sebree - Onton Complex .

On April 2, 2012, we acquired substantially all of Green River Collieries, LLC's assets related to its coal mining business and operations located in Webster and Hopkins Counties, Kentucky, including the Onton No.

9 mining complex ("Onton mine").

The Onton mine was operated by our subsidiary, Sebree Mining, LLC ("Sebree").

The Onton mine was idled in November 2015 in response to market conditions.

For information regarding Onton's remaining coal reserves, please read "Item 2.

Properties – Coal Reserves."

In 2021, the terminal loaded approximately 1.4 million tons for customers of Gibson County Coal and Hamilton.

Appalachian Operations

Our Appalachian mining operations are located in eastern Kentucky, Maryland, and West Virginia.

As of December 31, 2020, we had 860 employees, and we operate three mining complexes in Appalachia with one mine currently under development.

As of December 31, 2021, we had 895 employees, and we operate three mining complexes in Appalachia.

MC Mining Complex.

The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky.

We acquired the mine in 1989.

Our subsidiary, MC Mining, LLC ("MC Mining"), owns the mining complex and controls the reserves, and our subsidiary, Excel Mining, LLC ("Excel") conducts all mining operations.

We acquired the original mine in 1989.

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.

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 preparation plant has throughput capacity of 1,000 tons of raw coal per hour.

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 to various transloading facilities on the Ohio River for barge deliveries, or by truck directly to customers or to various docks on the Big Sandy River for barge deliveries.

Our subsidiary, Excel, completed development activity for MC Mining's Excel Mine No.

5 in May 2020 and transitioned its employees and equipment to the new mine in July 2020.

MC Mining controls the estimated 15 million tons of coal reserves assigned to the Excel Mine No.

5 and Excel will conduct all mining operations.

The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal with an expected annual production capacity of 1.3 million tons.

MC Mining utilizes its existing underground mining equipment and preparation plant to produce and process coal from the Excel Mine No.

5 and ships coal produced from the mine to various transloading facilities on the Ohio River and the Big Sandy River for barge deliveries or directly to customers via the CSX railroad and by truck.

The development plan for the new Excel Mine No.

5 provided a seamless transition from the current MC Mining operation.

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.

Mettiki Complex.

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

Mettiki (WV) began continuous miner development of the Mountain View mine in July 2005 and began longwall mining in November 2006.

The Mountain View mine produces medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical coal market or otherwise, or directly to

the coal blending facility at the Virginia Electric and Power Company Mt.

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

Storm Power Station.

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8 coal seam, located near Wheeling, West Virginia.

Tunnel Ridge began construction of the mine and related facilities in 2008.

Development mining began in 2010, and longwall mining operations began at Tunnel Ridge in May 2012.

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.

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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.

Our subsidiary, Penn Ridge Coal, LLC ("Penn Ridge"), holds coal reserves in Washington County, Pennsylvania, estimated to include approximately 61.5 million tons of proven and probable high-sulfur coal in the Pittsburgh No.

Development of the project is regulatory and market dependent and its timing is open-ended pending obtaining all required regulatory approvals, sufficient coal sales commitments to support the project, and final approval by the Board of Directors.

Coal Marketing and Sales

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Although some utility customers have appeared to favor a shorter-term contracting strategy, in 2021 approximately 77.9% and 75.1% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2021 to 2026.

As of February 1, 2021, our nominal commitment under contract was approximately 24.1 million tons in 2021.

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

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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Depending on the language of the contract, some contracts may terminate upon an event of force majeure that extends for a certain period.

The international coal market has been a substantial part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America, although the share of our export sales fell significantly in 2020 due to reduced demand in the international coal market.

Our sales into the international coal market are considered exports and

are made through brokered transactions.

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, 2021, 2020, and 2019, export tons represented approximately 12.5%, 3.3%, and 17.9% of tons sold, respectively.

We use the end-usage point as the basis for attributing tons to individual countries.

Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known.

Reliance on Major Customers

In 2020, our key customers were American Electric Power, Louisville Gas and Electric Company, and Tennessee Valley Authority.

We generally define key customers as those from which we derive 10% or more of our total revenues during 2020.

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

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

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.

Financial Statement and Supplemental Data—Note 23 – Concentration of Credit Risk and Major Customers."

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Our principal competitors include American Consolidated Natural Resources Inc., CONSOL Energy, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy LP, and Peabody Energy Corporation.

We also compete directly with a number of smaller producers in the Illinois Basin and Appalachian regions.

In addition, we compete with companies that produce coal from one or more foreign countries.

We seek to export a portion of our coal into the international coal markets and historically the prices we obtain for our export coal have been influenced by a number of factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

Potential changes to international trade agreements, trade concessions, or other political and economic arrangements may benefit coal producers operating in countries other than the United States.

We may be adversely impacted on the basis of price or other factors by foreign trade policies or other arrangements that benefit competitors.

In addition, coal is sold internationally in United States dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage.

If our competitors' currencies decline against the United States dollar or against foreign purchasers' local currencies, those competitors may be able to offer lower prices for coal to those purchasers.

Furthermore, if the currencies of overseas purchasers were to significantly decline in value in comparison to the United States dollar, those purchasers may seek decreased prices for the coal we sell to them.

Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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

Costs and other factors, such as safety and environmental considerations, have affected and may continue to affect the overall demand for coal as a fuel.

Competition from natural-gas-fired plants that are relatively more efficient, less expensive to construct, and less difficult to permit than coal-fired plants has displaced and may continue to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.

Federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for our coal.

Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal.

For additional information, please see "Item 1A.

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Coal Transportation

Our coal is transported from our mining complexes to our customers by barge, rail, and truck.

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.

As a consequence, 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 are able to accommodate multiple transportation options.

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.

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Mineral Interest Activities

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

AR Midland acquired its mineral interests in the Wing Acquisition.

Our mineral 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.

("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 55,500 net royalty acres, including 3,988 net royalty acres owned through our equity interests in AllDale III.

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

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 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.

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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As an owner of mineral interests, we incur the initial cost to acquire our interests but thereafter only incur our proportionate share of production and ad valorem taxes.

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

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

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:

Year Ended December 31,

Natural gas (MMcf)

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

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

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

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 Wing Acquisition demonstrates our commitment to continued acquisition of mineral interests in the nation's highest growth oil & gas plays.

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.

Anadarko Basin—SCOOP and STACK Plays

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AllDale III also owns mineral interests in the Haynesville Shale formation located in northwest Louisiana.

Minerals Competition

There is intense competition for acquisition opportunities in the oil & gas industry, and we compete with other companies that have greater resources.

Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

Our ability to acquire additional mineral interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Many of our competitors not only own and acquire mineral interests but also explore for and produce oil & gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis.

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 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 two-thirds 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, 2021, 2020 and 2019.

Year Ended December 31,

(tons in millions)

Illinois Basin

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

Illinois Basin:

Mining Access:

Slope & Shaft

Mining Access:

Slope & Shaft

Mining Access:

Slope & Shaft

Mining Method:

Medium/High-Sulfur

Low/Medium-Sulfur

Transportation:

Barge, Railroad,

Transportation:

Barge & Truck

Transportation:

Barge, Railroad

HENDERSON/UNION

Appalachian Basin:

MOUNTAIN VIEW

Mining Access:

Slope & Shaft

Mining Access:

Slope & Shaft

Mining Method:

Continuous Miner

Mining Access:

Slope & Shaft

Mining Method:

Medium/High-Sulfur

Mining Method:

& Continuous Miner

Transportation:

Barge & Truck

& Continuous Miner

Medium/High-Sulfur

Transportation:

Barge, Railroad

Sulfur - Metallurgical

Transportation:

Mining Access:

Slope & Shaft

Mining Method:

Mining Access:

Slope & Shaft

Medium/High-Sulfur

Mining Method:

Transportation:

Barge, Railroad

Mining Access:

Slope & Shaft

Mining Method:

Medium/High-Sulfur

& Continuous Miner

Transportation:

Barge & Truck

Transportation:

Barge & Railroad

& Continuous Miner

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:

● Hopkins County, Kentucky

● Webster County, Kentucky

● Union County, Kentucky

● Henderson County, Kentucky

● Hamilton County, Illinois

● Jefferson County, Illinois

● Gibson County, Indiana

Alliance Resource Properties leases some of the reserves and resources in Union and Henderson Counties from WKY CoalPlay, LLC ("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 21 – 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.

Leasing of these properties is dependent upon further development by our operating subsidiaries or third-party mining complexes, which is regulatory and market dependent.

Appalachia Basin

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).

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.

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.

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Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternative fuels and other forms of energy, may affect the demand for oil & gas.

Minerals - Seasonal Nature of Business

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.

For additional information, please see "Item 1A.

Risk Factors".

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 operating areas.

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 our operators in meeting well-drilling objectives and can increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.

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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 mining 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 miner and equipment tracking systems and proximity detection systems.

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 in order to establish ourselves as the supplier of choice for our customers.

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.

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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.

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.

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

For example, in June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.

Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's request for information.

The comment period for the request for information closed in September 2020.

It is uncertain whether MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.

Separately, in November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments.

● 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.

● In August 2019, MSHA published a request for information regarding exposure to respirable crystalline silica, most commonly found in the mining environment through quartz.

The request solicited information regarding best practices to protect miners’ health from exposure to quartz, including examination of a new reduced permissible exposure limit, potential new or developing protective technologies, and/or technical and educational assistance.

The comment period for the request for information closed in October 2019.

● In November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments.

The comment period for the proposed rule closed in December 2020.

It is uncertain whether MSHA will present a final rule addressing this issue.

● 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, MHSA reopened the rulemaking record for additional public comments.

A virtual hearing was held in January 2022 and the comment period closed in February 2022.

It is uncertain whether MSHA will present a final rule addressing any of the above issues or any of the other various proposed rules or requests for information or whether any such rule 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.

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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 and to some survivors of a miner who dies from this disease.

The BLBA levied a tax on coal sold of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims.

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

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

The Revenue Act of 1987

extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.

The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018.

On January 1, 2019, the excise tax rates reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase was set to expire on December 31, 2020.

However, in December 2020, the excise tax rate increase was extended another year, through December 31, 2021.

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.

Workers ' Compensation and Black Lung

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In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977.

The fee for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively.

This fee is currently scheduled to be in effect until September 30, 2021, and requires Congressional action to reauthorize.

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.

We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary.

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However, we cannot assure you that such claims will not be asserted in the future.

In April 2015, the United States Environmental Protection Agency ("EPA") finalized rules on coal combustion residuals ("CCRs");

In April 2015, the U.S.

Environmental Protection Agency ("EPA") finalized rules on coal combustion residuals ("CCRs");

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

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

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.

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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It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral and in some cases it is unclear what level of collateral will be required.

By example, the Office of Workers' Compensation Programs issued new criteria in 2019, but has yet to provide information to self-insured operators regarding the bonding levels and collateral thresholds that will be required.

In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us.

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For additional information, please see "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources— Off-Balance Sheet Arrangements ."

Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources— Cash Requirements ."

Air Emissions

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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 2020, we sold 93.0% of our total tons to electric utilities in the United States, of which 100% was sold to utility plants with installed pollution control devices.

In 2021, we sold 81.6% 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 Clean Air Interstate Rule ("CAIR"), discussed below.

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In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies.

In subsequent litigation, the United States Supreme Court struck down the MATS rule based on the EPA's failure to take costs into consideration.

In subsequent litigation, the U.S.

Supreme Court struck down the MATS rule based on the EPA's failure to take costs into consideration.

Circuit Court allowed the current rule to stay in place until the EPA issued a new finding.

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In May 2020, EPA issued a final rule that reverses the Agency’s prior determination from 2000 and 2016 that it was "appropriate and necessary"

to regulate hazardous air pollutants ("HAP") from coal-fueled Electric Generating Units ("EGUs") under the MATS rule.

Notwithstanding the invalidation of this threshold regulatory determination, the final rule leaves in place all of the HAP emission control requirements imposed by the MATS rule based on the conclusion that the EGU source category cannot meet the statute's stringent requirements for delisting a source category from HAP regulation.

Many electric generators have already announced retirements due to the MATS rule.

to regulate hazardous air pollutants from coal-fueled Electric Generating Units ("EGUs") under the MATS rule.

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

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

Circuit , the MATS rule has forced generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units.

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 have filed litigation against one or both of these rulemakings, and the NAAQS may be subject to revision under the Biden Administration.

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.

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.

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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.

In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through Federal Implementation Plans ("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.

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 new source review ("NSR") program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment.

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In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions.

Depending on the ultimate resolution of these cases, demand for coal could be affected.

The EPA 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 New Source Performance Standards ("NSPS") under the CAA require the reduction of certain pollutants and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions."

These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels.

Although the Trump Administration revised prior regulations in September 2020 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, President Biden signed an executive order on his first day in office calling for the suspension, revision, or rescission of the September 2020 rule and the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities.

These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels.

Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards.

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.

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 has 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 announced that climate change will be a focus of his administration.

For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors.

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These commitments could further reduce demand and prices for fossil fuels.

Although the United States had withdrawn from the Paris Agreement, President Biden has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction targets under the agreement.

However, the impact of these orders, and the terms of any legislation or regulation to implement the United States’ commitment under the Paris Agreement, remain unclear at this time.

Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-

fired electric generating facilities.

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.

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.

The impact of these actions remain unclear at this time.

Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels.

Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the United States Supreme Court's 2007 decision that the EPA has authority to regulate GHG emissions.

Although the United States Supreme Court's holding did not expressly involve the EPA's authority to regulate GHG emissions from stationary sources, such as coal-fueled power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.

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.

Although the U.S.

Supreme Court's holding did not expressly involve the EPA's authority to regulate GHG emissions from stationary sources, such as coal-fueled power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.

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

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

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

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

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

Judicial challenges led the United States Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.

Judicial challenges led the U.S.

Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the U.S.

Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.

Then, in October 2017 the EPA proposed to repeal the CPP.

The EPA subsequently proposed the ACE rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction".

The EPA subsequently proposed the Affordable Clean Energy ("ACE") rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction".

The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals;

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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 and we cannot predict the outcome of the litigation.

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.

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Other states may adopt similar requirements, and federal legislation is a possibility in this area.

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 affect our current and prospective customers or those of our mineral interest producers, they may reduce the demand for fossil-fuel energy and may affect the long-term demand for our coal and the oil & gas producers from the properties in which we hold mineral interests.

Finally, while the United States Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law.

Finally, while the U.S.

Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law.

As a result, despite this favorable ruling, tort-type liabilities remain a concern.

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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.

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

however, these regulations may be subject to further regulation under the Biden Administration.

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.

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Auctions for carbon dioxide allowances under the program began in September 2008.

Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers.

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.

It is likely that these regional efforts will continue based on current trends and concerns related to the reduction of GHG emissions.

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

It is possible that future international, federal, and state initiatives to control GHG emissions could result in increased costs associated with fossil-fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs.

Such increased costs for fossil-fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, or those of the operators of our mineral interests, which could have a material adverse effect on our business, financial condition, and results of operations Finally, activists may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.

Finally, activists may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.

For more information, see our Risk Factor titled "Our operations are subject to a series of risks resulting from climate change."

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Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

In order for us or the operators of the properties in which we hold oil & gas mineral interests to conduct certain activities, an operator may need to obtain a permit for the discharge of fill material from the United States Army Corps of Engineers ("Corps of Engineers") and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA.

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 U.S.

Army Corps of Engineers ("Corps of Engineers") and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA.

Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments.

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1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia.

This action was the

first time that such power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C.

This action was the first time that such power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C.

Circuit Court of Appeals in 2013.

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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.

It is also possible that Biden Administration could propose a broader definition of WOTUS.

Should any rule expanding the definition of what constitutes a water of the United States take effect as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

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.

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.

Hazardous Substances and Wastes

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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 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 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.

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.

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In October 2020, EPA published a final rule.

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.

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

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The federal Endangered Species Act ("ESA") and counterpart state legislation protect species threatened with possible extinction.

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

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.

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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Human Capital

To conduct our operations, as of December 31, 2020, we employed 2,902 full-time employees, including 2,530 employees involved in active mining operations, 203 employees in other operations, and 169 corporate employees.

To conduct our operations, as of December 31, 2021, we employed 2,990 full-time employees, including 2,604 employees involved in active coal mining operations, 219 employees in other operations, and 167 corporate employees.

Our workforce is entirely union-free.

Our typical employee has approximately nine years of experience with the Partnership and more than 34% of all employees remain employed for more than five years.

However, we reduced our headcount by 19% during 2020 primarily due to the effects of the COVID-19 pandemic.

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.

To attract and retain the most qualified personnel across all functions of our business we offer competitive compensation packages.

In making decisions regarding employee compensation, we review current compensation levels for each position within other companies in the coal industry and other peers and use our discretion to determine an appropriate total compensation package, which generally includes a base salary, incentive bonus, medical, dental and life insurance and participation in our profit sharing and savings plan.

Depending on the position, incentive bonuses can be based on production and safety goals at specific coal operations or company-wide performance goals, among other factors.

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, possible incentive compensation, medical, dental and life insurance 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.

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which reflects both the frequency and severity of injuries incurred.

Our NFDL rating of 1.06 for the nine months ended September 30, 2020, was approximately 68.6% lower than the preliminary industry average over the same time period.

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.

The average concentration of those samples was 59% below the regulatory standard.

We are also regularly inspected by MSHA.

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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.

In light of the COVID-19 pandemic in 2020, we have also taken steps to enhance protections from, and minimize risks associated with, the spread of COVID-19, including, but not limited to, staggering shift patterns to promote social distancing, enhanced cleaning procedures, promotion of recommended hygiene practices, limited workplace access, "touch-free"

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.

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