Item 1. Business
ITEM 1. BUSINESS
Introduction
We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic and international utilities and industrial users as well as royalty income from oil & gas mineral interests located in strategic producing regions across the United States. The primary focus of our business is to maximize the value of our existing mineral assets, both in the production of coal from our mining assets and the leasing and development of our coal and oil & gas mineral ownership. In addition, we are positioning ourselves as a reliable energy provider for the future as we pursue opportunities that support the advancement of energy and related infrastructure. We intend to pursue strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. We believe that our diverse and rich resource base and strategic investments will allow us to continue to create long-term value for unitholders.
We are the largest coal producer in the eastern United States with seven operating underground mining complexes in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia as well as a coal-loading terminal in Indiana on the Ohio River. We manage and report our coal operations under two regions, Illinois Basin and Appalachia. We market our coal production to major domestic and international utilities and industrial users.
We own mineral and royalty interests in approximately 67,700 net royalty acres, including approximately 4,000 net royalty acres attributable to our equity interest in AllDale III, in premier oil & gas producing regions in the United States, primarily the Permian, Anadarko, and Williston Basins. While we own both oil & gas mineral and royalty interests, we refer to them collectively as mineral interests throughout our discussions of our business as the majority of our holdings are mineral interests. We market our oil & gas mineral interests for lease to Operators in those regions and generate royalty income from the leasing and development of those mineral interests. Reserve additions and the associated cash flows are expected to increase from the development of our existing mineral interests and through acquisitions of additional mineral interests.
We have approximately 663.2 million tons of coal mineral reserves and 1.06 billion tons of coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania and West Virginia. Substantially, all of our coal mineral resources and 557.7 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties, which are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. We market our coal mineral reserves and resources to the coal mining operations that are able to access them and generate royalty income from the leasing and development of those coal mineral reserves and resources.
We have invested in energy and infrastructure opportunities including Ascend, Francis, Infinitum, and NGP ET IV as described below.
In addition, through our technology company, Matrix Group, we develop and market industrial, mining and technology products and services worldwide.
ARLP, a Delaware limited partnership, completed its initial public offering on August 19, 1999, and is listed on the NASDAQ Global Select Market under the ticker symbol "ARLP." We are managed by our sole general partner, MGP, a Delaware limited liability company, which holds a non-economic general partner interest in ARLP.
Oil & Gas Acquisitions
The following acquisitions enhance our ownership position in the Permian Basin and further our business strategy to grow our Oil & Gas Royalties segment.
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Acquisition Agreement
On January 27, 2023, we entered into a one-year collaborative agreement with a third party effective January 1, 2023, committing up to $35.0 million for the acquisition of oil & gas mineral interests in the Midland and Delaware basins. Under the agreement, the third party assisted us in the identification, evaluation, and acquisition of target oil & gas mineral interests. In exchange for these services, the third party received a participation share, partially funded by the third party, and was paid a periodic management fee. We acquired $13.2 million oil & gas mineral interests under the agreement in 2023. On February 19, 2024, we renewed this agreement for an additional one-year term, committing up to $25.0 million.
JC Resources
On February 22, 2023, we acquired approximately 2,682 oil & gas net royalty acres in the Delaware Basin from JC Resources, a related party entity owned by Mr. Craft, for $72.3 million.
Skyland
On December 7, 2023, we acquired approximately 2,372 oil & gas net royalty acres predominantly in the Anadarko Basin, along with acreage in the Williston and Delaware Basins from Skyland and Haymaker for a combined purchase price of $14.5 million.
Growth Investments and Opportunities
The following investments in the advancement of energy and related infrastructure further our business strategy to develop strategic relationships and invest in attractive opportunities that leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation. For more information on our acquisitions and investments, please read "Item 8. Financial Statements and Supplementary Data—Note 3 – Acquisitions","—Note 11 – Variable Interest Entities" and "—Note 12 – Equity Investments" of this Annual Report on Form 10-K.
Francis
On April 5, 2022, we made a $20.0 million convertible note investment in Francis which converted to a preferred equity interest on April 1, 2023. Francis currently is active in the installation, management and operation of metered-for-fee, public-access EV charging stations. Francis also develops and constructs EV charging stations for third-party customers.
Ascend
On September 6, 2023, we purchased $25.0 million of Series D Preferred Stock in Ascend. Ascend is a U.S.-based manufacturer and recycler of sustainable, closed-loop engineered battery materials for electric vehicles. Ascend is currently constructing North America's first commercial-scale manufacturing facility located near Hopkinsville, Kentucky, that when complete, will produce enough cathode materials for 750,000 electric vehicles per year.
Infinitum
On September 8, 2023, we increased our investment in Infinitum to $66.6 million by purchasing $24.6 million of Series E Preferred Stock. Infinitum is a Texas-based startup developer and manufacturer of electric motors featuring printed circuit board stators which have the potential to result in motors that are smaller, lighter, quieter, more efficient and capable of operating at a fraction of the carbon footprint of conventional electric motors.
Matrix Group
Matrix Group provides a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties. On January 16, 2024, Matrix Design entered into an agreement with Infinitum to jointly develop and distribute high-efficiency motors and advanced motor controllers designed specifically for the mining industry. Under the agreement, Matrix Design will integrate Infinitum's motor technology into mining equipment of our operating subsidiaries to provide performance validation in production environments for jointly
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developed products and to improve our operational efficiency, and market the jointly developed technology and products to third parties worldwide.
The following diagram depicts our simplified organization and ownership as of December 31, 2023:
Our internet address is www.arlp.com , and we make available free of charge on our website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, Forms 3, 4 and 5 for our Section 16 filers and other documents (and amendments and exhibits, such as press releases, to such filings) as soon as reasonably practicable after we electronically file with or furnish such material to the SEC. Information on our website or any other website is not incorporated by reference into this report and does not constitute a part of this report.
The SEC maintains a website that contains reports, proxy and information statements, and other information for issuers, including us. The public can obtain any documents that we file with the SEC at www.sec.gov .
Coal Mining Operations
Coal is used primarily for the generation of electric power and the production of steel but is also used for chemical, food, and cement processing. We produce bituminous coal from our underground mines that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). We have established long-term relationships with customers through exemplary and consistent performance.
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At December 31, 2023, our mining operations had access to approximately 663.2 million tons of coal mineral reserves and 1.06 billion tons of coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia. Substantially, all of our coal mineral resources and 557.7 million tons of our coal mineral reserves are owned or leased by Alliance Resource Properties and are currently leased or subleased or held for lease or sublease to our mining operations or others. We produce a diverse range of thermal and metallurgical coal with varying sulfur and heat contents, which enables us to satisfy the broad range of specifications required by our customers. In 2023, we sold 34.4 million tons of coal and produced 34.9 million tons. Of the 34.4 million tons sold, approximately 60% were leased from Alliance Resource Properties. The coal we sold in 2023 was approximately 3.6% low-sulfur coal, 33.4% medium-sulfur coal, and 63.0% high-sulfur coal. In 2023, approximately 80.9% of our tons sold were purchased by domestic electric utilities and 15.7% were sold into the international markets through brokered transactions. The balance of our tons sold was to third-party resellers and industrial consumers. For tons sold to domestic electric utilities, 100.0% were sold to utility plants with installed pollution control devices. The Btu content of our coal ranges from 11,450 to 13,200.
The following chart summarizes our coal production by region for the last three years.
Year Ended December 31,
Coal Regions
2023
2022
2021
(tons in millions)
Illinois Basin
25.2
24.3
22.2
Appalachia
9.7
11.2
10.0
Total
34.9
35.5
32.2
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The following map shows the location of our coal mining operations:
Illinois Basin Operations:
D. WARRIOR COMPLEX
G. METTIKI COMPLEX
A. GIBSON COMPLEX
Warrior Mine
Mountain View Mine
Gibson South Mine
Mining Type: Underground
Mining Type: Underground
Mining Type: Underground
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
Mining Method: Longwall
Mining Method: Room & Pillar
Coal Type: Medium/High-Sulfur
& Continuous Miner
Coal Type: Low/Medium-Sulfur
Transportation: Barge, Railroad,
Coal Type: Low/Medium
Transportation: Barge, Railroad
& Truck
Sulfur - Metallurgical
& Truck
Transportation: Railroad
E. MOUNT VERNON
& Truck
B. RIVER VIEW COMPLEX
TRANSFER TERMINAL
a) River View Mine
Rail or Truck to Ohio River Barge
H. MC MINING COMPLEX
b) Henderson County Mine
Transloading Facility
Excel Mine No. 5
Mining Type: Underground
Mining Type: Underground
Mining Access: Slope & Shaft
Appalachian Operations:
Mining Access: Slope & Shaft
Mining Method: Room & Pillar
F. TUNNEL RIDGE COMPLEX
Mining Method: Room & Pillar
Coal Type: Medium/High-Sulfur
Tunnel Ridge Mine
Coal Type: Low-Sulfur
Transportation: Barge & Truck
Mining Type: Underground
Transportation: Barge, Railroad,
Mining Access: Slope & Shaft
& Truck
C. HAMILTON COMPLEX
Mining Method: Longwall
Hamilton Mine
& Continuous Miner
Mining Type: Underground
Coal Type: Medium/High-Sulfur
Mining Access: Slope & Shaft
Transportation: Barge
Mining Method: Longwall
& Continuous Miner
Coal Type: Medium/High-Sulfur
Transportation: Barge, Railroad
& Truck
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We lease most of our coal mineral reserves and resources from Alliance Resource Properties or private parties and generally have the right to maintain leases in force until the exhaustion of mineable and merchantable coal located within the leased premises or a larger coal mineral reserve or resource area. These leases provide for royalties to be paid to the lessors at a fixed amount per ton or as a percentage of the sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are normally credited against the production royalties owed to a lessor once coal production has commenced.
Illinois Basin Operations
Our Illinois Basin mining operations are located in western Kentucky, southern Illinois, and southern Indiana. As of December 31, 2023, we have 2,189 employees and we operate four active mining complexes in the Illinois Basin.
Gibson Complex
Our subsidiary, Gibson, operates the Gibson South mine, located near the city of Princeton in Gibson County, Indiana. The Gibson South mine is an underground mine and utilizes continuous mining units employing room-and-pillar mining techniques to produce low/medium-sulfur coal. The Gibson South mine's preparation plant has throughput capacity of 1,800 tons of raw coal per hour. Production from the Gibson South mine is shipped by truck or transported by rail on the CSX or NS railroads from our rail loadout facility directly to customers or various transloading facilities, including our Mt. Vernon transloading facility, for barge delivery. Production from the mine began in April 2014. Gibson production in 2023 was 5.3 million tons.
River View Complex
Our subsidiary, River View, operates the River View mine and the Henderson County mine. The River View mine is located in Union County, Kentucky and is currently the largest room-and-pillar coal mine in the United States. The River View mine began production in 2009 and utilizes continuous mining units to produce medium/high-sulfur coal from multiple seams. The Henderson County mine is located in Henderson County, Kentucky and is currently under development, with full production expected to begin in 2024 from the No. 9 seam.
Both mines will utilize the existing preparation plant, refuse disposal, and loadout facilities. River View's preparation plant has throughput capacity of 2,700 tons of raw coal per hour. Coal produced from the River View complex is transported by overland belt to a barge loading facility on the Ohio River. River View coal production in 2023 was 9.9 million tons.
Hamilton Complex
Our subsidiary, Hamilton, operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois. The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal. Longwall mining began in October 2014 and we acquired complete ownership and control in 2015. Hamilton's preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Hamilton has the ability to ship coal from the Hamilton mine via the CSX, Evansville Western Railway, or NS rail directly to customers or various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries. Hamilton coal production in 2023 was 5.6 million tons.
Warrior Complex
Our subsidiary, Warrior, operates an underground mining complex located near the city of Madisonville in Hopkins County, Kentucky. The Warrior complex was opened in 1985, and we acquired it in February 2003. Warrior utilizes continuous mining units employing room-and-pillar mining techniques to produce medium/high-sulfur coal. Warrior's preparation plant has throughput capacity of 1,200 tons of raw coal per hour. Warrior's production is shipped via the CSX or PAL railroads or by truck directly to customers or potentially to various transloading facilities, including our Mt. Vernon transloading facility, for barge deliveries. Warrior coal production in 2023 was 4.4 million tons.
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Mt. Vernon Transfer Terminal, LLC
Our subsidiary, Mt. Vernon, leases land and operates a coal-loading terminal on the Ohio River at Mt. Vernon, Indiana. Coal is delivered to Mt. Vernon by both rail and truck. The terminal has a capacity of 8.0 million tons per year with existing ground storage of approximately 200,000 tons. In 2023, the terminal loaded approximately 3.6 million tons for customers of Gibson and Hamilton.
Appalachian Operations
Our Appalachian mining operations are located in eastern Kentucky, Maryland, and West Virginia. As of December 31, 2023, we had 1,014 employees and we operate three mining complexes in Appalachia.
Tunnel Ridge Complex
Our subsidiary, Tunnel Ridge, operates the Tunnel Ridge mine, an underground longwall mine in the Pittsburgh No. 8 coal seam, located near Wheeling, West Virginia. Longwall mining operations began at Tunnel Ridge in May 2012. The Tunnel Ridge preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Coal produced from the Tunnel Ridge mine is medium/high-sulfur coal and is transported by conveyor belt to a barge loading facility on the Ohio River. Tunnel Ridge has the ability through a third-party facility to transload coal from barges for rail shipment on the Wheeling and Lake Erie Railway with connections to the CSX and the NS railroads. Tunnel Ridge coal production in 2023 was 7.7 million tons.
Mettiki Complex
The Mettiki Complex comprises the Mountain View mine located in Tucker County, West Virginia operated by our subsidiary Mettiki (WV) and a preparation plant located near the city of Oakland in Garrett County, Maryland operated by our subsidiary Mettiki (MD). Mettiki (WV) began longwall mining in November 2006. The Mountain View mine produces low/medium-sulfur coal, which is transported by truck either to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical coal market or otherwise, or directly to the coal blending facility at the Virginia Electric and Power Company Mt. Storm Power Station. The Mettiki (MD) preparation plant has throughput capacity of 1,350 tons of raw coal per hour. Coal processed at the preparation plant can be trucked to the blending facility at Mt. Storm or shipped via the CSX railroad, which provides the opportunity to ship into the domestic and international thermal and metallurgical coal markets. Mettiki WV coal production in 2023 was 0.8 million tons.
MC Mining Complex
The MC Mining Complex is located near the city of Pikeville in Pike County, Kentucky. We acquired the original mine in 1989. Our subsidiary, MC Mining, through our subsidiary, Excel operates the Excel Mine No. 5. Excel completed the development of Mine No. 5 in May 2020 and transitioned its employees and equipment from Mine No. 4 in July 2020. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The existing preparation plant, which has throughput capacity of 1,000 tons of raw coal per hour, is utilized by Mine No. 5. Substantially all of the coal produced at MC Mining in 2023 met or exceeded the compliance requirements of Phase II of the Federal CAA (see "—Environmental, Health and Safety Regulations— Air Emissions " below). Coal produced from the mine is shipped via the CSX railroad directly to customers or various transloading facilities on the Ohio River for barge deliveries, or by truck directly to customers or various docks on the Big Sandy River for barge deliveries. MC Mining coal production in 2023 was 1.2 million tons.
Coal Marketing and Sales
We sell coal to an established customer base through opportunities as a result of existing business relationships or through formal bidding processes. As is customary in the coal industry, we have entered into long-term coal supply agreements with many of our customers. These arrangements are mutually beneficial to our customers and us in that they provide greater predictability of sales volumes and sales prices. Although some utility customers have appeared to favor a shorter-term contracting strategy, in 2023 approximately 93.4% and 92.0% of our sales tonnage and total coal sales, respectively, were sold under long-term contracts with committed term expirations ranging from 2024 to 2029. Our initial 2024 guidance includes 32.5 million priced and committed tons for delivery in 2024. The contractual time commitments
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for customers to nominate future purchase volumes under these contracts are typically sufficient to allow us to balance our sales commitments with prospective production capacity.
The provisions of long-term contracts are the results of both bidding procedures and extensive negotiations with each customer. As a result, the provisions of these contracts vary significantly in many respects, including, among other factors, price adjustment features, price, and contract reopener terms, permitted sources of supply, force majeure provisions, and coal qualities and quantities. A portion of our long-term contracts is subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both. These provisions, however, may not ensure that the contract price will reflect every change in production or other costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can, in some instances, lead to the early termination of a contract. Some of the long-term contracts also permit the contract to be reopened for renegotiation of terms and conditions other than pricing terms, and where a mutually acceptable agreement on terms and conditions cannot be concluded, either party may have the option to terminate the contract. Long-term contracts typically stipulate procedures for the transportation of coal, quality control, sampling, and weighing. Most contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics such as heat, sulfur, ash, moisture, grindability, volatility, and other qualities. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. While most of the contracts specify the approved seams and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is stipulated, the buyers often have the option to vary the volume within specified limits. Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include but are not limited to unexpected significant geological conditions and weather events that may disrupt transportation. Depending on the language of the contract, some contracts may terminate upon an event of force majeure that extends for a certain period.
The international coal market has been a part of our business with indirect sales to end-users in Europe, Africa, Asia, North America, and South America. Our sales into the international coal market are considered exports and the majority are made through brokered transactions. During the years ended December 31, 2023, 2022, and 2021, export tons represented approximately 15.7%, 12.5%, and 12.5% of tons sold, respectively. Because title to our export shipments typically transfers to our brokerage customers at a point that does not necessarily reflect the end-usage point, we attribute export tons to the country with the end-usage point, if known.
Reliance on Major Customers
In 2023, we derived more than 10% of our total revenue from each of American Electric Power and Tennessee Valley Authority. We did not derive 10% or more of our revenues from any other single customer. For more information about these customers, please read "Item 8. Financial Statement and Supplemental Data—Note 22 – Concentration of Credit Risk and Major Customers."
Coal Competition
The coal industry is intensely competitive. The most important factors on which we compete are coal price, coal quality (including sulfur and heat content), reliability and diversity of supply, and transportation costs from the mine to the customer. We are the largest coal producer in the eastern United States. Our principal competitors include American Consolidated Natural Resources Inc., CONSOL Energy, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy LP, and Peabody Energy Corporation. We also compete directly with smaller producers in the Illinois Basin and Appalachian regions. In addition, we seek to export a portion of our coal into the international coal markets and we compete with companies that produce coal from one or more foreign countries.
The price per ton for our export coal sales is influenced by many factors, such as global economic conditions, weather patterns, and global supply and demand, among others. The price per ton for our domestic coal sales are primarily linked to coal consumption patterns of domestic electricity-generating utilities, which in turn are influenced by economic activity, government regulations, weather, and technological developments, as well as the location, quality, price and availability of competing sources of fuel and alternative energy sources such as natural gas, nuclear energy, petroleum and renewable energy sources for electrical power generation.
For additional information, please see "Item 1A. Risk Factors."
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Coal Transportation
Our coal is transported from our mining complexes to our customers by barge, rail, and truck, reflecting important flexibility advantages in supplying our customers. Depending on the proximity of the customer to the mining complex and the transportation available for delivering coal to that customer, transportation costs can be a substantial part of the total delivered cost of a customer's coal. Consequently, the availability and cost of transportation constitute important factors in the marketability of coal. We believe our mines are located in favorable geographic locations that minimize transportation costs for our customers, and in many cases, we can accommodate multiple transportation options. Our customers typically negotiate and pay the transportation costs from the mining complex to the destination, which is the standard practice in the industry. Approximately 50.2% of our 2023 sales volume was initially shipped from the mining complexes by barge, 32.1% was shipped from the mining complexes by rail, and 17.7% was shipped from the mining complexes by truck. The rates set by and available capacity of the transportation company serving a particular mine or customer may affect, either adversely or favorably, our marketing efforts concerning coal produced from the relevant mining complex. With respect to our export volumes from the United States to other countries, we generally sell coal to our customers at an export terminal in the United States and we are responsible for the cost of transporting coal to the export terminals. Our export customers generally negotiate and pay for ocean vessel transportation.
Mineral Interest Activities
Our mineral interest activities include both oil & gas and coal mineral interests. Our oil & gas mineral interest business includes all activities related to the oil & gas mineral interests held directly or indirectly by Alliance Minerals and includes Alliance Minerals' equity interest in AllDale III. Our mineral interests are primarily located on private lands in three basins, which are also our areas of focus for future development by operators. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK), and Williston (Bakken) Basins. Our developed and undeveloped net acres standardized to a 1/8th royalty equate to more than 67,745 oil & gas net royalty acres, including 3,969 oil & gas net royalty acres owned through our equity interest in AllDale III.
Our coal mineral interests include substantially all of our coal mineral resources and 557.7 million tons of coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to internal mining complexes or (b) near other internal and external coal mining operations but not yet leased. Our coal mineral interests are located in both the Illinois Basin and the Appalachia Basin.
Oil & Gas Royalties
When our oil & gas mineral interests are leased, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to receive a fixed percentage of the revenue or production from the oil & gas produced from the acreage underlying our interests, free of lease operating expenses and capital costs. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities, or by making an extension payment. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. As an owner of mineral interests, we incur the initial cost to acquire our interests but thereafter only incur our proportionate share of production and ad valorem taxes. Unlike owners of working interests in oil & gas properties, we are not obligated to fund drilling and completion costs, lease operating expenses, or plugging and abandonment costs associated with oil & gas production.
The following chart summarizes the production of our oil & gas mineral interests for the year ended December 31, 2023, 2022, and 2021, not including our equity interest in AllDale III:
Year Ended December 31,
2023
2022*
2021*
Production:
Oil (MBbls)
1,418
1,061
898
Natural gas (MMcf)
5,759
4,814
3,460
Natural gas liquids (MBbls)
726
541
402
BOE (MBbls)
3,105
2,404
1,877
* Recast to reflect the JC Resources Acquisition as if we, rather than JC Resources, acquired the mineral interests in 2019. Please see "Item 8. Financial Statement and Supplemental Data—Note 1 – Organization and Presentation and Note 3 – Acquisitions" for more information.
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The following map shows the location of our oil & gas mineral interests:
Permian Basin—Delaware and Midland Basins
The Permian Basin ranges from West Texas into southeastern New Mexico and is currently the most active area for horizontal drilling in the United States. The Permian Basin is further subdivided into the Delaware Basin in the west and the Midland Basin in the east. Based on geologic data and the ongoing development by operators, our mineral interests in the Permian Basin contain multiple producing zones of economic horizontal development including but not limited to the Wolfcamp, Spraberry, and Bone Spring formations. Our purchases of acreage located entirely in the Permian Basin through the Belvedere, Jase and JC Resources Acquisitions demonstrate our commitment to continued acquisition of mineral interests in the nation's highest growth oil & gas plays.
Anadarko Basin—SCOOP and STACK Plays
The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens, and McClain Counties. Based on geologic data and the ongoing development by operators, our mineral interests in the SCOOP play contain multiple producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney, and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend, Anadarko Basin, Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo, and Blaine Counties. Based on geologic data and the ongoing development by operators, our mineral interests in the STACK play contain multiple producing zones of economic horizontal development including but not limited to the Meramec and Woodford formations.
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Williston Basin—Bakken
The Williston Basin stretches from western North Dakota into eastern Montana. Based on geologic data and ongoing development by operators, our mineral interests contain multiple producing zones of economic horizontal development including the Bakken and Three Forks formations.
Other
Our other interests are comprised primarily of mineral interests owned in the Appalachia Basin that stretches throughout most of Ohio, West Virginia, and Pennsylvania, and extends into other states. The Appalachia Basin's most active plays in which we have acreage are the Marcellus Shale and Utica plays, which cover most of Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the interests held in the Appalachia Basin, we own a small number of mineral interests in the Tuscaloosa Marine Shale play in Mississippi. AllDale III also owns mineral interests in the Haynesville Shale formation located in northwest Louisiana.
Coal Royalties
Our Coal Royalties segment includes approximately 557.7 million tons of reserves and substantially all of the 1.06 billion tons of our coal mineral resources. Our coal mineral reserves and resources are located in the Appalachia and Illinois Basins in the United States. We lease our reserves and resources to our mining complexes under long-term leases. Approximately 60% of our royalty-based leases have initial terms of five to 40 years, with substantially all lessees having the option to extend the lease for additional terms.
Under our standard royalty lease, we grant the lessees the right to mine and sell our reserves and resources in exchange for royalty payments based on a percentage of the sale price or a fixed royalty per ton of coal mined and sold. Lessees calculate royalty payments due to us and are required to report tons of coal mined and sold as well as the sales prices of the extracted coal.
The following chart summarizes the coal sales associated with our coal mineral interests for the years ended December 31, 2023, 2022 and 2021.
Year Ended December 31,
Coal Regions
2023
2022
2021
(tons in millions)
Illinois Basin
19.9
21.2
18.9
Appalachia
0.3
0.6
1.3
Total
20.2
21.8
20.2
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The following map shows the location of our coal mineral interests:
Illinois Basin:
Appalachian Basin:
A. GIBSON RESERVES AND RESOURCES
E. HENDERSON/UNION RESOURCES
H. TUNNEL RIDGE RESERVES AND RESOURCES
B. HAMILTON RESERVES AND RESOURCES
F. DOTIKI RESOURCES
I. MOUNTAIN VIEW RESERVES AND RESOURCES
C. RIVER VIEW RESERVES
G. SEBREE SOUTH RESOURCES
J. PENN RIDGE RESOURCES
D. WARRIOR RESERVES
Illinois Basin
Alliance Resource Properties, either directly or through its subsidiaries, holds coal mineral reserves and resources in the following counties in the Illinois Basin:
● Hopkins County, Kentucky
● Webster County, Kentucky
● Union County, Kentucky
● Henderson County, Kentucky
● Hamilton County, Illinois
● Gibson County, Indiana
Alliance Resource Properties leases some of the reserves and resources in Union and Henderson Counties from WKY CoalPlay or its subsidiaries, which are related parties. For more information about our WKY CoalPlay transactions, please read "Item 8. Financial Statements and Supplementary Data—Note 20 – Related-Party Transactions."
Approximately 477.0 million tons of proven and probable reserves and 977.2 million tons of measured, indicated and inferred coal mineral resources are controlled by Alliance Resource Properties in the Illinois Basin and are leased/subleased to our mining complexes or held for lease/sublease in the future as follows:
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Gibson Reserves and Resources
Approximately 4.4 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Gibson.
Hamilton Reserves and Resources
Approximately 564.5 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Hamilton.
River View Reserves
Approximately 303.1 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, River View.
Warrior Reserves
Approximately 50.0 million tons of the reserves are currently leased/subleased or held for lease/sublease to our subsidiary, Warrior.
Henderson/Union Resources
Approximately 412.7 million tons of the resources are not under lease or currently anticipated to be leased by our operating companies. Leasing of these properties is dependent upon further development by our operating subsidiaries or third-party mining complexes, which is regulatory and market dependent.
Dotiki Resources
Approximately 76.0 million tons of the resources are currently leased/subleased or held for lease/sublease to our subsidiary, Webster.
Sebree South Resources
Approximately 43.5 million tons of the resources are currently leased/subleased to our subsidiary, Sebree.
Appalachia Basin
Alliance Resource Properties, either directly or through its subsidiaries, holds coal mineral reserves and resources in the following counties in the Appalachian Basin:
● Brooke County, West Virginia
● Grant County, West Virginia
● Ohio County, West Virigina
● Tucker County, West Virginia
● Washington County, Pennsylvania
Approximately 80.7 million tons of reserves and 85.4 million tons of coal mineral resources are controlled by Alliance Resource Properties in the Appalachian Basin and are leased/subleased to our mining complexes or held for lease/sublease in the future as follows:
Tunnel Ridge Reserves and Resources
Approximately 75.0 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Tunnel Ridge.
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Mountain View Reserves and Resources
Approximately 13.1 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to our subsidiary, Mettiki (WV).
Penn Ridge Resources
Approximately 78.0 million tons of the resources are not under a lease. The resources are near our Tunnel Ridge mining complex and leasing of these resources is dependent upon further development by Tunnel Ridge or third-party mining complexes, which is regulatory and market dependent.
Minerals Interest Competition
Many companies are engaged in the search for and the acquisition of coal and oil & natural gas interests, and there is a limited supply of desirable coal and oil & natural gas reserves. Our ability to acquire additional oil & gas mineral interests in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our competitors not only own and acquire oil & gas mineral interests but also explore for and produce oil & gas and, in some cases, conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information that is superior to the information that is available to us. In addition, because we have fewer financial and human resources than many companies in the oil & gas industry, we may be at a disadvantage in bidding for oil & gas properties. Further, oil & gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal, and fuel oils. Changes in the availability or price of oil & gas or other forms of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternative fuels and other forms of energy, may affect the demand for oil & gas.
We also face competition from land companies, coal producers, and international steel companies in purchasing coal mineral reserves and resources as well as royalty-producing properties. Our mining complexes in which we lease our reserves compete with coal producers in various regions of the United States for domestic sales on the basis of coal price at the mine, coal quality, transportation cost from the mine to the customer, and the reliability of supply. Continued demand for our coal and the prices that our lessees obtain are also affected by the demand for electricity and steel, as well as government regulations, technological developments, and the availability and the cost of generating power from alternative fuel sources, including nuclear, natural gas, wind, solar, and hydroelectric power.
For additional information, please see "Item 1A. Risk Factors".
Oil & Gas Minerals Interest - Seasonal Nature of Business
Generally, demand for oil increases during the summer months and decreases during the winter months while demand for natural gas increases during the winter and summer months and decreases during the spring and fall months. Certain buyers of natural gas use natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit drilling and producing activities and other oil & gas operations in a portion of our leasing areas. These seasonal anomalies can pose challenges for the Operators in meeting well-drilling objectives and can increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay operations.
Other Operations
Matrix Group
Matrix Group provides a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties around the world. Matrix Group's products and services include data network, communication and tracking systems, mining proximity detection systems, industrial collision avoidance systems, and data and analytics software. In addition, Matrix Design has entered into an agreement with Infinitum to jointly develop and distribute high-efficiency motors and advanced motor controllers designed specifically for the mining industry. Under the agreement, Matrix Design will integrate Infinitum's motor technology into mining equipment of our operating subsidiaries to provide performance validation in production environments for jointly
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developed products and to improve our operational efficiency. Matrix Design will also work with Infinitum to market the jointly developed technology products to third parties worldwide. We acquired Matrix Design in September 2006. Over the past 15 years, Matrix Group has become a leader in collision avoidance and proximity detection technologies, providing safety and productivity solutions for mining companies worldwide, while extending its reach into other industrial applications.
Growth Investments and Opportunities
Our subsidiary, AROP II, LLC, and its subsidiary, AROP II Investments, LLC, makes strategic investments in attractive opportunities that support the advancement of energy and related infrastructure. We intend to pursue opportunities that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. Our strategy is to continue to identify and make strategic investments in the advancement of energy and related infrastructure opportunities that may create new platforms for future lines of business with long-term growth and cash flow generation. As of December 31, 2023, we have made investments of $25 million in Ascend, $20 million in Francis, $66.6 million in Infinitum and $6.6 million (of a $25 million commitment) in NGP ET IV. In 2023, revenues from these investments were immaterial.
Ascend is a U.S.-based manufacturer and recycler of sustainable, closed-loop engineered battery materials for electric vehicles. Ascend is currently constructing North America's first commercial-scale manufacturing facility located near Hopkinsville, Kentucky, that when complete, will produce enough cathode materials for 750,000 electric vehicles per year.
Francis is currently active in the installation, management and operation of metered-for-fee, public-access EV charging stations. Francis also develops and contracts EV charging stations for third-party customers.
Infinitum is a Texas-based developer and manufacturer of electric motors featuring printed circuit board stators that have the potential to result in motors that are smaller, lighter, quieter, more efficient and capable of operating at a fraction of the carbon footprint of conventional electric motors.
NGP ET IV focuses on investments that are part of the global transition toward a lower carbon economy by partnering with top-tier management teams and investing growth equity in companies that drive or enable the growth of renewable energy, the electrification of our economy, or the efficient use of energy.
Environmental, Health, and Safety Regulations
Our coal operations, and those of the operators on the properties in which we hold oil & gas mineral interests, are subject to extensive regulation by federal, state, and local authorities on matters such as:
● employee health and safety;
● permits and other licensing requirements for mining or exploration and production activities;
● air quality standards;
● water quality standards;
● storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;
● plant and wildlife protection that could limit or prohibit mining or exploration and production activities;
● restrict the types, quantities, and concentration of materials that can be released into the environment in the performance of mining or exploration and production activities;
● initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of waste ponds, mining areas, drilling pits, and plugging of abandoned wells;
● storage and handling of explosives;
● wetlands protection;
● surface subsidence from underground mining; and
● the effects, if any, that mining has on groundwater quality and availability.
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Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil, and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. The regulatory burden on fossil-fuel industries increases the cost of doing business and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators' costs and adversely affect our performance.
In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected the demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be differently interpreted or more stringently enforced, any of which could have a significant impact on our mining operations, our customers' ability to use coal, or the value of or amount of royalties received from our mineral interests. For more information, please see the risk factors described in "Item 1A. Risk Factors" below.
We are committed to conducting mining operations in compliance with applicable federal, state, and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of MSHA where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to promptly remediate any identified condition. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.
Expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based on permit requirements and the estimated costs and timing assumptions of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.
Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and time-consuming and may delay or prevent the commencement or continuation of mining operations.
The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenges, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.
We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines, and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.
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Mine Health and Safety Laws
The operation of our mines is subject to FMSHA, and regulations adopted pursuant thereto. FMSHA imposes extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, most of the states where we operate have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the United States for the protection of employee safety and have a significant effect on our operating costs. Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.
FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires the imposition of a civil penalty for each cited violation. Negligence and gravity assessments, along with other factors, can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order, or carry out violations of the FMSHA, or its mandatory health and safety standards.
The MINER Act significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties, and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:
● sealing off abandoned areas of underground coal mines;
● mine safety equipment, training, and emergency reporting requirements;
● substantially increased civil penalties for regulatory violations;
● training and availability of mine rescue teams;
● underground "refuge alternatives" capable of sustaining trapped miners in the event of an emergency;
● flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
● post-accident two-way communications and electronic tracking systems.
MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.
MSHA has finalized a number of rules related to controlling exposure to coal mine dust, which has resulted in progressively stricter exposure limits imposed by MHSA regulations. These requirements impose a number of dust monitoring obligation and mine ventilation requirements on our operations. Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. MSHA previously published a request for information regarding engineering controls and best practices to lower miners' exposure to respirable coal mine dust; however, to date no further action has been taken and we cannot predict what actions, if any, MSHA may take in response to this information request.
MSHA has also published, and may continue to publish, various proposed rules or requests for information, which may result in additional rulemaking. For example:
● In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that closed in November 2016 for this matter, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's 2016 request for information. The comment period for the request for information for the Diesel Exhaust Partnership closed in September 2020 and it is uncertain whether this will result in additional rulemaking.
● In July of 2023, MSHA published a proposed rule on respirable crystalline silica, most commonly found in the mining environment through quartz. The proposed rule would amend the existing MSHA standards to lower the permissible exposure limit of respirable crystalline silica, as well as set forth new or revised standards for
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exposure sampling, corrective actions, medical surveillance for metal and non-metal miners, and respiratory protection requirements. The comment period on the proposed rule ended in August of 2023 and the final rule is expected in April 2024.
● In November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments. The comment period for the proposed rule closed in December 2020 and the final rule is expected in August 2024.
● In September 2021, MSHA published a proposed rule requiring that mine operators employing six or more miners develop and implement a written safety program for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface Mobile Equipment). The comment period for the proposed rule closed in November 2021. However, MSHA reopened the rulemaking record for additional public comments. A virtual hearing was held in January 2022 and the comment period closed in February 2022. The final rule was released in December 2023, with an effective date of January 19, 2024. All mines subject to the rule are required to develop, implement, and periodically update a written safety program for surface mobile equipment (excluding belt conveyors) at surface mines and surface areas of underground mines. Compliance with the rule must be achieved by July 17, 2024.
It is uncertain whether any of the above or other various proposed rules or requests for information would have material impacts on our operations or our costs of operation.
Subsequent to the passage of the MINER Act, Illinois, Kentucky, Pennsylvania, and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations. Other states may pass similar legislation or administrative regulations in the future.
Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers. Although we have not quantified the full impact, implementing and complying with these new federal and state safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.
Black Lung Benefits Act
The BLBA requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses under circumstances including where no responsible coal mine operator has been identified for claims. In addition, the BLBA provides that some claims for which coal operators not affiliated with us had previously been responsible are or will become obligations of the government trust funded by the excise tax referenced in this paragraph. The Federal government established such a trust fund and as of January 1, 2022, the trust fund was funded by an excise tax on industry-wide production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable gross sales price. The Inflation Reduction Act of 2022 raised the excise tax, effective October 1, 2022, up to $1.10 per ton of coal from underground mines and up to $0.55 per ton of coal from surface mines, neither amount to exceed 4.4% of the gross sales price. The coal we sell into international markets is generally not subject to the excise tax referenced in this paragraph. The Company recognized expenses related to the BLBA excise tax of $30.5 million for the year ended December 31, 2023.
Workers ' Compensation and Black Lung
We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers' compensation laws also provide for the potential compensation of survivors of workers who suffer employment-related deaths. We generally self-insure this potential expense using our actuary estimates of the cost of present and future claims. In addition, coal mining companies are subject to federal legislation and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker's pneumoconiosis, or black lung. We also provide for these claims through self-insurance programs. The DOL's OWCP is responsible for authorizing coal mine operators to self-insure for federal black lung and for setting applicable security amounts. In January 2023, the OWCP issued a Notice of Proposed Rulemaking to update its regulations authorizing coal producers to self-insure and for determining appropriate security amounts, and announced that it plans to solicit public comments for that proposal. A change in requirements for security posted to self-insure black lung liabilities could result in the Company being required to post additional security for its obligations. Our pneumoconiosis benefits liability is calculated using the
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service cost method based on the actuarial present value of the estimated pneumoconiosis benefits obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents, and discount rates. For more information concerning our requirement to maintain bonds to secure our workers' compensation obligations, see the discussion of surety bonds below under "—Bonding Requirements."
The Patient Protection and Affordable Care Act, enacted in 2010, includes significant changes to the federal black lung program retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes have caused a significant increase in our costs expended in association with the federal black lung program. We may also be liable under various state statutes with respect to black lung claims.
Surface Mining Control and Reclamation Act
The SMCRA and similar state statutes establish operational, reclamation, and closure standards for all aspects of surface mining as well as many aspects of deep mining. Although we have minimal surface mining activity and no mountaintop removal mining activity, SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.
SMCRA and similar state statutes require, among other things, that mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. We believe we are in compliance in all material respects with applicable regulations relating to reclamation. We have accrued $150.4 million for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Please read "Item 8. Financial Statements and Supplementary Data—Note 18 – Asset Retirement Obligations."
In addition, the Abandoned Mine Lands Program, which is part of SMCRA and relates to industry-wide operations, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The fee expired on September 30, 2021, and was reauthorized through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021. The fee, as reauthorized, for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30, 2034. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties, and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have "owned" or "controlled" the third-party violator. Sanctions against the "owner" or "controller" are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. We are not aware of any currently pending or asserted claims against us relating to the "ownership" or "control" theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.
Bonding Requirements
Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers' compensation, to pay certain black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral and in some cases it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire, surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow. For additional information, please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources— Cash Requirements ."
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Air Emissions
The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining, as well as oil & gas, operations. The CAA imposes permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There has been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of SIPs, could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in fossil fuels' share of power generating capacity could have a material adverse effect on our business, financial condition, and results of operations.
In addition to the GHG issues discussed below, the air emissions programs that may affect our operations or the operations of those on the properties in which we hold mineral interests, directly or indirectly, include but are not limited to the following:
● The EPA ' s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility ' s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA ' s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or " scrubbers, " or by reducing electricity-generating levels. In 2023, we sold 80.9% of our total tons to electric utilities in the United States, substantially all of which was sold to utility plants with installed pollution control devices. These requirements would not be supplanted by a replacement rule for the CAIR, discussed below.
● The CAIR called for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the CSAPR, a replacement rule for CAIR, which would have required twenty-eight states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers. The full impacts of CSAPR are presently unknown due to the implementation of MATS, discussed below, and the impact of the continuing coal plant retirements.
● In May 2020, EPA issued a final rule that reversed the Agency’s prior determination from 2000 to 2016 that it was " appropriate and necessary " to regulate hazardous air pollutants from coal-fueled EGUs under the MATS rule, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. However, in February 2023, EPA published a final revocation of the May 2020 finding. Then, in April 2023, the EPA issued a proposed rule to amend the MATS rule, to reflect developments in control technologies and plant performance. Although the impacts of the potential final rule are unknown, the MATS rule has forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units and many electric power generators have already announced retirements due to the uncertainty surrounding the MATS rule. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR updates and MATS and the effects they may have on our business and our results of operations, financial condition, or cash flows.
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● The CAA requires the EPA to periodically reevaluate the available health effects information to determine whether the NAAQS should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine PM, ozone, nitrogen oxide, and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in "attainment" but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide. In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone; however, various entities filed litigation against one or both of these rulemakings, and the Biden Administration announced that it would reconsider and potentially revise the NAAQS. With respect to ozone, a draft assessment released in April 2022 indicated a preliminary conclusion that the December 2020 decision would stand. However, on August 21, 2023, the EPA announced a new review of the ozone NAAQS to reflect updated ozone science in combination with the reconsideration of the December 2020 decision. The Agency is expected to release its Integrated Review Plan in the fall of 2024. New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments could indirectly reduce the demand for coal. Separately, the implementation of new standards by states has the potential to delay or otherwise impact oil & gas production activities, which could reduce the profitability of our mineral interests.
● The EPA ' s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA ' s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations. In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs, which was followed by a supplemental memorandum in July 2021 for SIPs for the second implementation period.
● The EPA ' s NSR program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program. Several of these lawsuits have been settled, but others remain pending. In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions. The EPA has announced that it will review the NSR program. Depending on the ultimate resolution of the EPA's litigation and review, demand for coal could be affected.
● The EPA's NSPS under the CAA require the reduction of certain pollutants and methane emissions from certain stimulated oil & gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as "green completions." These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels. Although the Trump Administration revised prior regulations in September 2020 to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. In December 2023, EPA issued its final methane rules, known as OOOOb and OOOOc, that establish new source and first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas
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processing plants, and transmission and storage facilities. The final rules include nationwide emissions guidelines for states to limit methane emissions from existing crude oil and natural gas facilities and states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The rules also revise requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys and establishes a "super-emitter" response program to timely mitigate emissions events. It is likely that the final rule and its requirements will be subject to legal challenges. Moreover, compliance with the new rules may effect the amount oil & gas companies owe under the Inflation Reduction Act, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2025 and thereafter. Compliance with the EPA’s new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. Oil & gas production on the properties in which we hold mineral interests could be adversely affected to the extent the rules and any of their requirements impose increased operating costs on the oil & gas industry.
GHG Emissions
Combustion of fossil fuels, such as the coal we produce and the oil & gas produced from our mineral interests, results in the emission of GHGs, such as carbon dioxide and methane. Combustion of fuel for mining equipment used in coal production also emits GHGs. Future regulation of GHG emissions in the United States could occur pursuant to future United States treaty commitments, new or existing domestic legislation, or regulation by the EPA. Although no comprehensive climate change regulation has been adopted at the federal level in the United States, President Biden has made it clear that climate change will be a focus of his administration. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Internationally, the Paris Agreement requires member states to submit non-binding, individually determined emissions reduction targets. These commitments could further reduce demand and prices for fossil fuels. President Biden recommitted the United States to the Paris Agreement in February 2021 and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy wide net GHG emissions by 2030. The international community gathered again at the COP26 during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. Also at COP26, more than forty countries pledged to phase out coal, although the United States did not sign the pledge. In December 2023, the United Arab Emirates hosted the COP28 where parties signed onto an agreement to transition "away from fossil fuels in energy systems in a just, orderly and equitable manner" and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. The full impact of these actions remains unclear at this time. Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal, and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal and oil & gas could be negatively impacted, which would have an adverse effect on our operations.
The EPA has begun to regulate GHG emissions from stationary sources, such as coal-fueled power plants, under existing federal CAA. In August 2015, the EPA issued its final CPP Rule, which established carbon pollution standards for power plants. The CPP was subsequently challenged by multiple states and industry participants in the Court of Appeals for the D.C. Circuit and, in February 2016, the implementation of the CPP was stayed by the U.S. Supreme Court. Then, in September 2019, the EPA repealed the CPP and finalized the ACE rule. The ACE rule specified that heat rate improvement measures qualified as the BSER for existing coal-fired power plants, clarified the roles of the EPA and the states in the implementation of the ACE, and revised the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. In January 2021, however, the D.C. Circuit vacated the ACE rule concluding that the EPA's "repeal of the CPP rested critically on a mistaken reading of the CAA." Although the D.C. Circuit ultimately agreed to stay its mandate, such that the CPP remained repealed, in June 2022, the U.S. Supreme Court in West Virginia v. EPA reversed and remanded the D.C. Circuit's decision and found that the EPA had acted outside the bounds of the agency’s authority in the promulgation of the CPP. Notwithstanding the litigation, the
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CPP and the ACE led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has not yet adopted legislation to restrict carbon dioxide emissions from existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v. EPA, but we cannot predict whether such legislation will be passed in the future or what the potential impacts of such legislation would be.
Several rulemakings have been issued under the NSPS that constrain the GHG emissions of fossil-fuel-fired power plants. In October 2015, EPA published its final rule on performance standards for GHG emissions from new, modified, and reconstructed EGUs, which required use of efficient supercritical pulverized coal boilers that use partial post-combustion carbon capture and storage technology and imposed a new emission standard. The October 2015 rule was challenged by several states, industry participants and other parties in the D.C. Circuit and, in April 2017, the Court granted EPA’s motion to hold the litigation in abeyance while EPA reviewed the rule. Then, in December 2018, the EPA issued a proposed rule to replace the October 2015 rule, including revising the BSER for newly constructed coal-fired EGUs. Although the EPA has not taken further action on the December 2018 proposed rule, in May 2023, the EPA published a proposed NSPS rule for GHG emissions from new, modified, and reconstructed fossil fuel-fired EGUs and emissions guidelines for existing fossil fuel-fired EGUs. The final rule is expected in 2024.
There are further uncertainties surrounding the potential impacts and costs associated with the reduction of GHG emissions, such as: protests and challenges to the permitting of new fossil-fuel infrastructure by environmental organizations and state regulators; state tort liability; and state adoption of "renewable energy standards" or "renewable portfolio standards," which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. For example, several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio and, in December 2021, President Biden issued an executive order setting a goal for a carbon pollution-free electricity sector across the country by 2035. To the extent these requirements or similar requirements that may be enacted or adopted in the future affect our current and prospective customers or those of our mineral interest producers, they may reduce the demand for our coal and the oil & gas produced from the properties in which we hold mineral interests. For more information, see our risk factor titled "We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change."
In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the NEPA. These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In April 2022, the CEQ issued a final rule, considered "Phase I" of the Biden Administration’s two-phased approach to modifying the NEPA, revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporating the consideration of direct, indirect, and cumulative effects of major federal actions, including GHG emissions. In July 2023, the CEQ announced a "Phase 2" Notice of Proposed Rulemaking, the "Bipartisan Permitting Reform Implementation Rule," which revises the implementing regulations of the procedural provisions of NEPA and implements the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The public comment period for the proposed rule closed in September 2023, and the final rule is expected in the second quarter of 2024. And, in January 2023, the CEQ released guidance, effective upon publication, to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA.
Many states and regions have adopted GHG initiatives and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, the RGGI calls for the implementation of a cap-and-trade program aimed at reducing carbon dioxide emissions from power plants in participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Similar to RGGI, five western states launched the Western Regional Climate Initiative, although only California, Washington and certain Canadian provinces are currently active participants. We cannot predict what other regional greenhouse gas reduction initiatives may arise in the future.
It is possible that future international, federal, and state initiatives to control GHG emissions could result in increased costs associated with fossil-fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for fossil-fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, or those of the operators of our mineral interests, which could have a material adverse effect on our business, financial condition, and results of operations. Finally, activists
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may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts. For more information, see our Risk Factor titled "Our operations are subject to a series of risks resulting from climate change."
Water Discharge
The CWA and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact such wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future "fill" permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. For more information about asset retirement obligations, please read "Item 8. Financial Statements and Supplementary Data—Note 18 - Asset Retirement Obligations." Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.
For us or the operators of the properties in which we hold oil & gas mineral interests to conduct certain activities, an operator may need to obtain a permit for the discharge of fill material from the Corps of Engineers and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.
The EPA also has statutory "veto" power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an "unacceptable adverse effect." This authority has been upheld by the D.C. Circuit. Any future use of the EPA's Section 404 "veto" power could create uncertainty with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues. In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on a fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.
States also have the ability to review the Corps of Engineers’ Section 404 permitting process, pursuant to CWA Section 401, which is also subject to ongoing litigation. In October 2021, the Northern District of California federal court vacated a 2020 rule revising the Section 401 certification process. The Supreme Court stayed this vacatur and, in September 2023, the EPA finalized its Clean Water Act Section 401 Water Quality Certification Improvement Rule, effective on November 27, 2023. While the full extent and impact of these actions is unclear at this time, any disruption in the ability to obtain required permits may result in increased costs and project delays.
TMDL regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody can receive and still meet state water quality standards, and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines could require more costly water treatment and could adversely affect our coal production.
Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings have been subject to substantial litigation. Although the EPA and Corps of Engineers did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico vacated the 2020 rule in decisions announced during the third quarter of 2021. In January 2023, the EPA and Corps of Engineers published a final revised definition of WOTUS founded upon a pre-2015 definition, including updates to incorporate existing Supreme Court decisions. However, continued uncertainty remains as to the government's
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jurisdictional reach as the rule is likely to be subject to legal challenge. Judicial developments further add to this uncertainty. In October 2022, the Supreme Court heard oral arguments in Sackett v. EPA regarding the scope and authority of the CWA and the definition of WOTUS and in May 2023, issued a ruling invalidating certain parts of the January 2023 rule, and further limiting the federal government’s jurisdiction over wetlands and tributaries. A revised WOTUS rule was issued in September 2023. Due to the injunction in certain states, however, the implementation of the September 2023 rule currently varies by state.
Hazardous Substances and Wastes
The CERCLA, otherwise known as the "Superfund" law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.
The RCRA and analogous state laws impose requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. Similarly, most wastes associated with the exploration, development, and production of oil & gas are exempt from regulation as hazardous wastes under RCRA, though these wastes typically constitute "solid wastes" that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require such wastes to become subject to more stringent storage, handling, treatment, or disposal requirements, which could impose significant additional costs on the operators of the properties in which we own oil & gas mineral interests. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.
RCRA impacts the coal industry in particular because it regulates the disposal of certain CCB. On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as "non-hazardous" waste and avoids the stricter, more costly, regulations under RCRA's "hazardous" waste rules. While the classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers' operating costs and potentially reduce their ability to purchase coal. The CCB rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating the closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site-specific circumstances. Certain provisions of the revised CCB rule were vacated by the D.C. Circuit in 2018. The EPA proposed a coal ash rule in May 2023 and the final rule is expected in April 2024. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities that sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA required the remaining facilities to cease receipt of waste within 135 days of completion of public comment, or around July 2022. And, in January 2023, the EPA issued six proposed determinations to deny facilities' requests to continue disposal into unlined surface impoundments. The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. The combined effect of the CCB rules and the ELG regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.
On November 3, 2015, the EPA published the final rule ELG, revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technological improvements in the steam electric power industry over the last three decades. The combined effect of the CCB and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards. In November 2019, the EPA proposed revisions to the 2015 ELG
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rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs. In October 2020, EPA published a final rule. In August 2021, EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits. In March 2023, the EPA proposed a rule to establish more stringent ELG regulations and the final rule is expected in April 2024. It is unclear what impact these regulations will have on the market for our products.
Endangered Species Act
The federal ESA and counterpart state legislation protect species threatened with possible extinction. The USFWS works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related and oil & gas exploration and production activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. In February 2023, the USFWS published a proposed rule that revised the requirements for an incidental take permit application. A final rule is scheduled for release in the first quarter of 2024. Additionally, in June 2022, the USFWS and the National Marine Fisheries Service published a final rule rescinding the 2020 regulatory definition of "habitat." If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered or to redesignate a species from threatened to endangered, we or the operators of the properties in which we hold oil & gas mineral interests could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.
Other Environmental, Health, and Safety Regulations
In addition to the laws and regulations described above, we are subject to regulations regarding underground and above-ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulations. In addition, our use of explosives is subject to the Federal Safe Explosives Act. We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition, or results of operations.
Human Capital
To conduct our operations, as of December 31, 2023, we employed 3,595 full-time employees, including 3,038 employees involved in active coal mining operations, 408 employees in other operations, and 193 corporate employees. In 2023 we reviewed the work duties of our employees and reclassified 68 of our technical services employees from corporate employees to employees involved in other operations. Our workforce is entirely union-free. Our typical employee has approximately six years of experience with the Partnership and more than 40% of all employees remain employed for more than five years.
To attract and retain the most qualified personnel across all functions of our business we offer competitive compensation packages. In making decisions regarding employee compensation, we review current compensation levels for each position within other companies in the coal industry and other peers and use our discretion to determine an appropriate total compensation package, which generally includes some combination of base salary, incentive compensation, health and welfare benefits and participation in our profit sharing and savings plan. Depending on the position and employer, incentive compensation bonuses can be based on production and safety goals at a specific coal operation or broader performance goals across the Partnership, among other factors. We intend for each employee's total compensation to be competitive in the marketplace.
Workplace safety is fundamental to our culture. By providing a work environment that rewards safety and encourages employee participation in the safety process, we have a demonstrated history as a leader in safety performance in the coal mining industry. We are focused on improving employee safety through regular training and continuous monitoring of our progress through various industry-standard metrics. In addition, we collected approximately 13,800 respirable dust samples from the mining environment where our miners regularly work and travel. The average concentration of those samples was 56% below the regulatory standard. We are also regularly inspected by MSHA. For more information about citations or orders for violations of standards under the FMSHA, as amended by the MINER Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.
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We are focused on the health of our employees. In addition to providing medical, dental, and vision benefits for our employees, we also provide on-site medical clinics to provide medical services to our employees and their families. Furthermore, at each of our coal operations and corporate offices, we provide a human resource representative to assist employees with various human resource matters. The Partnership also administers our medical plan, which allows us to control costs and work directly on behalf of our employees with healthcare providers. To date, we have been able to continue providing health and welfare benefits with no out-of-pocket premiums for our employees and 100% coverage with direct contract providers.
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