ALLIANCE RESOURCE PARTNERS LP

Introduction

We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic utilities, industrial users and international customers, as well as royalty income from oil & gas mineral interests located in key producing regions across the United States. Our core objective is to maximize the value of our mineral asset base—both through coal production from our mining operations and through the leasing and development of our coal and oil & gas mineral interests. Our strategy is to provide reliable, baseload fuel for electricity generating customers while positioning the Partnership for long-term growth through investments in energy and related infrastructure. Leveraging our relationships with electric utilities, industrial customers, and government partners, we intend to pursue strategic opportunities that complement our operational strengths. We believe our diverse resource portfolio and targeted investments will continue to create long-term value for our unitholders.

We are the second largest coal producer in the eastern United States and as of December 31, 2025, we operated seven underground mining complexes across Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia and a coal-loading terminal on the Ohio River in Indiana. 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 customers.

We also own mineral and royalty interests in approximately 70,000 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 their development of those mineral interests. We expect reserve additions and the related cash flows to grow through further development of our existing mineral interests as well as acquisitions of additional mineral interests.

We also hold coal mineral reserves and resources in Illinois, Indiana, Kentucky, Pennsylvania and West Virginia. Substantially all of our coal mineral resources and a majority of our coal mineral reserves are owned or leased by Alliance Resource Properties, which are (a) leased or subleased to our mining complexes or (b) near other internal and external coal mining operations but not yet leased. We generate intercompany royalty income through the leasing and development of our coal mineral reserves and resources.

Beyond our core mineral platform, we have invested in growth-oriented businesses and energy-related technologies. Our subsidiary, Matrix Group, develops and markets industrial, mining and technology products and services worldwide and our subsidiary, Bitiki, mines bitcoin. We have also made investments in emerging energy and infrastructure opportunities, including Infinitum, NGP ET IV and Gavin Generation.

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

Elk Range

On October 31, 2025, we acquired approximately 190 oil & gas net royalty acres in the Midland and Delaware Basins from 89 Energy for a purchase price of $10.0 million. This acquisition enhances our ownership position in the Permian Basin and furthers our business strategy to grow our Oil & Gas Royalties segment. For more information on this acquisition please read “Item 8. Financial Statements and Supplementary Data—Note 4 - Acquisitions” of the Annual Report on Form 10-K.

The following investments in growth-oriented businesses and energy related technologies further our business strategy to develop strategic relationships and invest in strategic 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 investments, please read “Item 8. Financial Statements and Supplementary Data—Note 3 – Variable Interest Entities” and “—Note 10 – Investments” of the Annual Report on Form 10-K.

Infinitum

On December 31, 2025, we increased our investment in Infinitum to $82.5 million by purchasing $14.9 million of Series F Preferred Stock. Infinitum is a Texas-based startup 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.

Gavin Generation

In February 2025, we committed to invest up to $25 million in limited partner interests in Gavin Generation. As of December 31, 2025, we have funded $17.3 million of this commitment after giving effect to returns on our investment. Gavin Generation owns, indirectly, an interest in a joint venture holding company formed with a third party that indirectly owns and operates a coal-fired power plant.

Structure

The following diagram depicts our simplified organization and ownership as of December 31, 2025 and does not include each of our subsidiaries. See Exhibit 21.1 to this Annual Report on Form 10-K for a listing of our subsidiaries.

Available Information

Our internet address iswww.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 atwww.sec.gov.

Coal Mining Operations

Coal remains an essential fuel source for electric power generation and a critical input for steel production, with additional uses in chemical, food, and cement processing. Our operations produce bituminous coal from underground mines, which we sell primarily into the thermal and metallurgical markets. We have established and maintained long-term relationships with customers through consistent delivery performance and reliable contract fulfillment.

At December 31, 2025, our mining operations, which are held by Alliance Coal, had access to approximately 586.3 million tons of coal mineral reserves and 1.07 billion tons of coal mineral resources in Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia. Substantially, all of our coal mineral resources and 509.6 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, enabling us to meet a broad range of customer specifications. In 2025, we sold 33.0 million tons of coal and produced 33.2 million tons. Of the 33.0 million tons sold, 73% were leased from Alliance Resource Properties. The coal we sold in 2025 was approximately 18.7% low-sulfur coal, 51.8% medium-sulfur coal, and 29.5% high-sulfur coal. Demand for our coal remained concentrated in the domestic power sector, where 89.2% of our 2025 tons sold were purchased by domestic electric utilities and 8.6% were sold into the international markets through brokered transactions. The balance of our tons sold was to third-party resellers and industrial consumers domestically. For tons sold to domestic electric utilities, 100% were sold to utility plants with installed pollution control devices. The Btu content of our coal ranges from 11,400 to 13,200, positioning our products to meet customer requirements across multiple end-use applications.

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

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

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, 2025, we had 2,013 employees and we operated four mining complexes in the Illinois Basin. Production from these operations supplies a diverse group of domestic utilities and industrial customers, supported by multiple rail, truck, and barge transportation options.

Gibson Complex

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 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 coal production in 2025 was 5.5 million tons.

River View Complex

River View operates the River View mine located near Uniontown in Union County, Kentucky and the Henderson County mine located near Corydon in Henderson County, Kentucky. The River View mine began production in 2009 and utilizes continuous mining units to produce medium/high-sulfur coal. The Henderson County mine began full production in 2024 and utilizes continuous mining units to produce medium/high-sulfur coal.

Both mines utilize the existing preparation plant, refuse disposal, and loadout facilities. The 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 complex coal production in 2025 was 9.6 million tons.

Hamilton Complex

Hamilton operates the Hamilton mine, located near the city of McLeansboro in Hamilton County, Illinois. The Hamilton mine is an underground longwall mining operation producing medium/high-sulfur coal. Longwall mining began in October 2014 and we acquired complete ownership and control in 2015. The preparation plant has throughput capacity of 2,000 tons of raw coal per hour. Hamilton’s production is shipped 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 2025 was 6.5 million tons.

Warrior Complex

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. The 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 2025 was 4.5 million tons.

Mt. Vernon Transfer Terminal, LLC

Mt. Vernon leases land and operates a coal-loading terminal on the Ohio River at Mt. Vernon in Posey County, 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 2025, the terminal loaded approximately 1.6 million tons for customers of Gibson and Hamilton.

Appalachian Operations

Our Appalachian mining operations are located in eastern Kentucky, western Maryland, western Pennsylvania, and northern West Virginia. As of December 31, 2025, we had 882 employees and we operated three mining complexes in Appalachia. Production from these operations supply both thermal and metallurgical markets and benefit from access to barge and rail networks serving domestic and international customers.

Tunnel Ridge Complex

Tunnel Ridge operates the Tunnel Ridge mine, an underground longwall mine located near the city of Wheeling in Ohio County, West Virginia. Longwall mining operations began at Tunnel Ridge in May 2012. The 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 also 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 2025 was 5.2 million tons.

Mettiki Complex

Mettiki operates the Mountain View mine located in Tucker County, West Virginia and a preparation plant located near the city of Oakland in Garrett County, Maryland. Mettiki (WV) began longwall mining in November 2006. The Mountain View mine produces low/medium-sulfur coal, which is transported by truck to the Mettiki (MD) preparation plant for processing for shipment into the metallurgical or thermal coal markets. The 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 the Virginia Electric and Power Company, Mt. Storm Power Station, or shipped via the CSX railroad, which provides the opportunity to ship into the domestic and international metallurgical and thermal coal markets. Mettiki (WV) coal production in 2025 was 1.2 million tons.

On January 29, 2026, the decision was made to cease longwall production and primarily satisfy remaining contractual commitments from existing inventory. We will continue to evaluate options concerning the mine’s future.

MC Mining Complex

MC Mining is located near the city of Pikeville in Pike County, Kentucky. MC Mining operates the Excel Mine No. 5. We acquired the original mine in 1989, and we completed the development of Mine No. 5 in May 2020. The underground operation utilizes continuous mining units employing room-and-pillar mining techniques to produce low-sulfur coal. The preparation plant has throughput capacity of 1,000 tons of raw coal per hour. Coal produced from MC Mining can be 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 2025 was 0.7 million tons.

Coal Marketing and Sales

We market our coal through established customer relationships and competitive bidding processes, with a significant portion of our volumes sold under long-term coal supply agreements. These contracts provide enhanced predictability of sales volumes and pricing for both us and our customers. While some utility customers have favored shorter-term contracting in recent years, during 2025 approximately 86.5% of our total coal sales were under long-term contracts with committed term expirations ranging from 2026 to 2030. The nomination schedules under these agreements generally provide sufficient visibility for us to balance our contracted commitments with anticipated production levels.

Our long-term contracts vary significantly in structure and terms due to customer-specific requirements and negotiated outcomes. Key provisions may include price adjustment mechanisms tied to market indices or changes in regulatory compliance costs, sourcing and quality specifications, reopener rights, and force majeure terms. Certain agreements allow for volume flexibility within defined ranges. Although price adjustment provisions help mitigate cost variability, they may not fully reflect all changes in our production or operating costs. Failure to reach agreement on a price adjustment or other negotiated terms can lead to early termination of a contract

Quality assurance remains an integral part of our contracting framework. Most long-term agreements require us to deliver coal within prescribed specifications for heat content, sulfur, ash, moisture, grindability, volatility, and other attributes. Failure to meet these requirements may result in price adjustments, rejection of shipments, or contract termination. Contracted coal may be sourced from specific approved seams or multiple mines, depending on customer requirements and our operational flexibility.

We also participate in international coal markets, primarily through brokered transactions shipping to end-users in Europe, Africa, Asia, North America, and South America. During the year ended December 31, 2025, export tons represented approximately 8.6% of tons sold. For reporting purposes, we attribute export tons to the final destination when known, although title often transfers to brokers before delivery to end-markets.

Reliance on Major Customers

Our customer base includes several large domestic electric utilities. In 2025, we derived more than 10% of our total revenue from each of Louisville Gas and Electric Company and American Electric Power Company Inc. 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 20 – Concentration of Credit Risk and Major Customers.”

Coal Competition

We operate in a highly competitive coal market. Our competitiveness is influenced by several factors, including pricing, coal quality, supply reliability, transportation logistics, diversity of supply, and proximity to customers. We are the second largest coal producer in the eastern United States. Our principal competitors include American Consolidated Natural Resources Inc., Core Natural Resources, Inc., Alpha Metallurgical Resources, Inc., Foresight Energy Resources LLC, 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 international coal markets and we compete with companies that produce coal from foreign countries.

Domestic coal pricing is primarily driven by coal consumption patterns of domestic electricity-generating utilities. These patterns depend on overall economic conditions, governmental regulatory developments, weather, and technological developments, as well as competition from alternative generation sources—including natural gas, nuclear energy, and renewables—as well as the relative delivered cost of those fuels compared to coal. Export pricing is influenced by many factors, such as global economic conditions, weather patterns, and global supply and demand, among others.

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 45.8% of our 2025 sales volume was initially shipped from the mining complexes by barge, 34.8% was shipped from the mining complexes by rail, and 19.4% 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 approximately 70,000 oil & gas net royalty acres, including approximately 4,000 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 the majority of our coal mineral reserves which are owned or leased by Alliance Resource Properties and are (a) leased or subleased to our 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 lease bonus and retain a royalty interest that entitles us to a fixed percentage of production or revenue from the acreage underlying our interests. These royalties are free of operating and capital costs associated with drilling or completing wells and producing oil & gas from those wells. As a result, our exposure is limited to 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.

Leases may be extended beyond the initial term through continuous drilling or production operations, or through extension payments. When production or drilling activity ceases, the lease typically terminates, providing us the opportunity to re-lease the acreage to other operators. This recurring re-lease cycle supports long-term value realization across both developed and undeveloped acreage positions.

The following chart summarizes the production of our oil & gas mineral interests for the years ended December 31, 2025, 2024, and 2023, not including our equity interest in AllDale III:

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 mineral interest purchases have historically been Permian Basin-weighted in pursuit of the highest risk-adjusted returns. While the Permian Basin remains our primary focus area, we continue to consider acquisitions in other basins which may provide superior risk-adjusted returns.

Anadarko Basin—SCOOP and STACK Plays

The SCOOP play (South Central Oklahoma Oil Province) is located in central Oklahoma in Grady, Garvin, Stephens, and McClain Counties. Based on geologic data and the ongoing development by operators, our mineral interests in the SCOOP play contain multiple producing zones of economic horizontal development including multiple Woodford benches and the Springer Shale. In addition, operators are also currently testing other formations in the area including the Sycamore, Caney, and Osage, which is also referred to as SCORE (Sycamore Caney Osage Resource Expansion). The STACK play (derived from Sooner Trend, Anadarko Basin, Canadian and Kingfisher Counties) is located in central Oklahoma in Kingfisher, Canadian, Caddo, and Blaine Counties. Based on geologic data and the ongoing development by operators, our mineral interests in the STACK play contain multiple producing zones of economic horizontal development including but not limited to the Meramec and Woodford formations.

Williston Basin—Bakken

The Williston Basin stretches from western North Dakota into eastern Montana. Based on geologic data and ongoing development by operators, our mineral interests contain multiple producing zones of economic horizontal development including the Bakken and Three Forks formations.

Other

Our other oil & gas mineral 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 509.6 million tons of reserves and substantially all of the 1.07 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. These assets support our internal mining operations. 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, 2025, 2024 and 2023.

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

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:

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 21 – Related-Party Transactions.”

Approximately 423.5 million tons of proven and probable reserves and 972.5 million tons of measured, indicated and inferred coal mineral resources are controlled by Alliance Resource Properties in the Illinois Basin and are leased/subleased to our mining complexes or held for lease/sublease in the future as follows:

Gibson Reserves and Resources

Approximately 2.4 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to Gibson.

Hamilton Reserves and Resources

Approximately 534.4 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to Hamilton.

River View Reserves and Resources

Approximately 280.3 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to River View.

Warrior Reserves and Resources

Approximately 44.6 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to Warrior.

Henderson/Union Resources

Approximately 415.2 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 Webster.

Sebree South Resources

Approximately 43.0 million tons of the resources are currently leased/subleased to 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:

Approximately 86.1 million tons of reserves and 85.6 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 82.5 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to Tunnel Ridge.

Mountain View Reserves and Resources

Approximately 11.2 million tons of the reserves and resources are currently leased/subleased or held for lease/sublease to 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 Interests Competition

Competition for mineral interests—both coal and oil & gas interests—remains significant, driven by a limited supply of high-quality resource acreage and increasing interest from mineral aggregators, operators, private equity sponsors, and land companies. Our ability to expand our mineral interests portfolio depends on our continued success in identifying attractive opportunities, evaluating potential returns, and executing transactions in a competitive acquisition environment that often involve auction processes.

In the oil & gas sector, we compete not only with companies that acquire mineral interests, but also with integrated enterprises that explore for and produce hydrocarbons and, in some cases, operate midstream, refining, or marketing businesses. These competitors may have access to technical data, development insights, and operational information that exceed what is available to us as a mineral owner, providing them with advantages in underwriting or valuing mineral opportunities. In addition, many competitors possess greater financial and human resources than us, which may better position them to compete for larger or premium-priced assets. Demand for oil & gas itself remains sensitive to relative fuel economics, regulatory developments, conservation trends, and the availability of alternative energy sources.

We also face competition in the acquisition of coal mineral reserves and resources. Competitors include land companies, domestic coal producers, and international steel producers seeking to secure long-term supply. For the reserves we lease to our mining complexes, competitive pressures mirror those affecting the coal industry more broadly—primarily the coal price at the mine, coal quality, transportation cost from the mine to the customer, development costs, and the reliability of supply. Demand for our coal and the prices that our lessees obtain are further influenced by the demand for electricity and steel, as well as government regulations, technological developments, and the relative cost and availability of alternative generation sources, including nuclear, natural gas, wind, solar, and hydroelectric power. All of these factors may impact the royalties attributable to the production of our reserves.

Oil & Gas Minerals Interests - 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.

AROP II’s strategy is to make strategic investments in what we believe to be attractive opportunities that support the growth and development of technology and 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 growth and development of technology, energy and related infrastructure and other opportunities that may create new platforms for future lines of business, which, if successful, could lead to long-term growth and cash flow generation.

Matrix Group

Matrix Group provides a variety of technology products and services for our mining operations and certain industrial and mining technology products and services to third parties around the world. Matrix Group’s products and services include data network, communication and tracking systems, mining proximity detection systems, industrial collision avoidance systems, and data and analytics software. In addition, Matrix Design has entered into an agreement with Infinitum to jointly develop and distribute high-efficiency motors and advanced motor controllers designed specifically for the mining industry. Under the agreement, Matrix Design will integrate Infinitum’s motor technology into mining equipment of our operating subsidiaries to provide performance validation in production environments for jointly developed products and to improve our operational efficiency. Matrix Design will also work with Infinitum to market the jointly developed technology products to third parties worldwide. We acquired Matrix Design in September 2006. 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.

Bitiki

Bitiki began crypto-mining activities during the second half of 2020. Bitiki also hosts third-party crypto-miners for a fee. As of December 31, 2025, we had 3,702 active miners and 1,056 hosted machines. We hold 592.01 bitcoin valued at $51.8 million as of December 31, 2025.

As of December 31, 2025, we have investments in Infinitum, NGP ET IV, and Gavin Generation. Please read “Item 8. Financial Statements and Supplementary Data—Note 3 – Variable Interest Entities” and “—Note 10 – Investments” for more information on our growth investments.

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:

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 remediate any identified condition as soon as practicable. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based on permit requirements and the estimated costs and timing assumptions of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and time-consuming and may delay or prevent the commencement or continuation of mining operations.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenges, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.

We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines, and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although, like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Mine Health and Safety Laws

The operation of our mines is subject to FMSHA and regulations adopted pursuant thereto. FMSHA imposes extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, the states where we operate have individual 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 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. Effective January 15, 2025, MSHA amended 30 CFR Part 100 regarding criteria and procedures for proposed assessment of civil penalties for violations. As provided by the Inflation Adjustment Act, the increased penalty levels apply to any penalties assessed after January 15, 2025.

The MINER Act significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties, 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:

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards contained in the 30 Code of Federal Regulations (30 CFR).

MSHA has finalized a number of rules related to controlling exposure to respirable dusts within the mining environment, including coal mine dust and silica, which has resulted in progressively stricter exposure limits imposed by MSHA regulations. These requirements impose a number of dust monitoring obligations and mine ventilation requirements on our operations. Compliance with these rules can result, and has resulted, 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 and additional medical evaluations.

MSHA has also published, and may continue to publish, requests for information on various mining topics that may result in additional rules applicable to our operations. Recent requests include topics such as engineering controls and exposure of underground miners to diesel exhaust. Recent MSHA rulemaking actions include, for example:

existing MSHA respirable coal dust standards, as well as set forth new or revised silica standards for exposure sampling, corrective actions, medical surveillance for metal and non-metal miners, medical evaluations conducted by a physician or other licensed health care professional for miners required to wear a respirator, and respiratory protection programs for all mines. Compliance for metal and nonmetal mines goes into effect in April 2026. Compliance for coal mine operators was set to go into effect on April 14, 2025, but a U.S. Circuit Court of Appeals issued a temporary stay on April 4, 2025. As a result, enforcement remains uncertain, subject to this ongoing litigation. In addition, on November 26, 2025, MSHA indicated that the agency would reconsider portions of the rule, which could affect future requirements and associated compliance costs.

It is uncertain whether any of the above or various other 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, several states 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 has 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 that is funded by an excise tax on industry-wide production of 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 Partnership recognized expenses related to the BLBA excise tax of $31.7 million for the year ended December 31, 2025. Please read “Item 8. Financial Statements and Supplementary Data—Note 13 – Accrued Workers’ Compensation and Pneumoconiosis Benefits.”

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 December 2024, the OWCP issued a final rule revising its regulations authorizing coal producers to self-insure and for determining appropriate security amounts. This change in requirements for security posted to self-insure black lung liabilities could result in the Partnership being required to post additional security for its obligations, which could reduce the amount of our borrowing capacity under our available financing arrangements by the amount of such additional security. Traditionally, our pneumoconiosis benefits liability has been calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis benefits obligation. Our actuarial calculations have been based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents, and discount

rates. The impact of OWCP’s new actuarial assumptions is presently under review but can result in the Partnership’s estimated pneumoconiosis benefits obligations increasing significantly. 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, included 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 increased, and may continue to increase, our costs. 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 never had mountaintop removal mining activity and we currently have no surface 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 require mine operators to replace water supplies and repair or compensate for surface structure damage caused by mining operations, including longwall mining and other mining methods. We have accrued $157.6 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 15 – 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 or estimated black lung claims, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and for our competitors to secure new surety bonds without posting collateral and, in some cases, it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow. For additional information, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Cash Requirements.”

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining, as well as oil & gas, operations. The CAA imposes permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There has been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of SIPs, could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition, and results of operations.

In addition to the GHG issues discussed below, the air emissions programs that may affect our operations or the operations of those on the properties in which we hold mineral interests, directly or indirectly, include but are not limited to the following:

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. On January 6, 2026, the EPA finalized a significant revision to the Regional Haze Rule, extending the deadline for the next round of periodic SIP revisions from July 31, 2028, to July 31, 2031. On January 9, 2026, the agency fully disapproved Colorado’s regional haze SIP. In February 2026, the EPA issued updated, non-binding guidance for regional haze SIPs for the second implementation period addressing how states should evaluate “energy and non-air quality environmental impacts” in reasonable progress determinations. The guidance encourages states to consider potential impacts on electrical grid reliability, including impacts of any electric generating unit closure that would become federally enforceable if approved into a SIP, and advises that the EPA does not support states encouraging or forcing an electric generating facility to close in order to comply with regional haze requirements.

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 new or existing domestic legislation, or regulation by the EPA; however, in February 2026, the Trump administration finalized a rule repealing the “Endangerment Finding.” This served as the basis for the majority of EPA’s GHG related regulations. It is uncertain what impact the repeal of the Endangerment Finding will have on such regulations, and at least one lawsuit has been filed in federal court challenging the EPA’s rule revoking its Endangerment Finding.

At this time, no comprehensive climate change regulation has been adopted at the federal level in the United States. However, 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, either as part of cap and trade, carbon tax, or climate “superfund” laws. For example, in December 2024, New York adopted a law requiring companies that emitted over 1 billion tons of GHG emissions into the atmosphere between 2000 and 2018, with sufficient connections to the state of New York, to pay into a “climate superfund” to support climate-related adaptation and mitigation projects. We have been identified by New York as a potentially responsible party under

the law, which is being challenged in court; but, to date, we have not received any cost recovery demands. Vermont has passed its own climate “superfund” law, other states, such as Illinois, are attempting to pass their own climate “superfund” laws, and many 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, and the outcome of any legal challenges, the demand for coal and oil & gas could be negatively impacted, which would have an adverse effect on our operations.

The EPA has sought to regulate GHG emissions from stationary sources, such as coal-fueled power plants, based on its authority under the CAA. In August 2015, the EPA issued its final CPP Rule, which established carbon pollution standards for power plants. Following legal challenges, the EPA repealed the CPP and finalized the ACE rule, which was also subject to legal challenge. In June 2022, the U.S. Supreme Court inWest Virginia v. EPA found that the EPA had acted outside the bounds of the agency’s authority in promulgating of the CPP. In May 2024, the EPA finalized a rule that repealed the ACE rule and established GHG standards and guidelines that require coal fired power plants to (1) convert to natural gas co-firing by January 1, 2030 and then retire by 2039, (2) install by 2032 carbon capture and sequestration technology capable of capturing 90% of all CO 2 emissions, or (3) cease operations by 2032. The May 2024 rule was challenged in the D.C. Circuit Court, but the U.S. Supreme Court denied the challengers’ request to stay implementation of the rule pending the outcome of the litigation. On June 17, 2025, the EPA issued a proposed rule that would repeal all GHG emissions standards for fossil fuel-fired power plants, including the May 2024 rule.

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. Following legal challenge, the EPA undertook a review of the October 2015 rule and 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. In May 2024, however, the EPA issued a final NSPS rule for GHG emissions from new and reconstructed fossil fuel-fired combustion turbines, which notably, formally withdrew the December 2018 proposed amendments to the NSPS for GHG emissions from coal-fired EGUs. On June 17, 2025, the EPA issued a proposed rule that would repeal all GHG emissions standards for fossil fuel-fired power plants, including the May 2024 final NSPS rule.

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 or regulatory penalties or fines; 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. 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. However, as a result of recent court rulings and the change in presidential administrations, there is significant uncertainty with respect to current and future NEPA regulations. For example, in April 2025, the U.S. Department of Interior issued a new “alternative arrangements” policy for NEPA reviews of proposed fossil fuel projects, providing for shorter environmental review. Also in May 2025, the U.S. Supreme Court held inSeven County Infrastructure Coalition v. Eagle County, Colorado that courts must grant agencies “substantial judicial deference” with respect to the scope and content of their NEPA reviews when considering NEPA challenges, and that an agency may decline to evaluate environmental effects from separate projects upstream or downstream from the project at issue. Further, in September 2025, the White House Council on Environmental Quality issued new guidance to federal agencies implementing NEPA, encouraging agencies to limit their NEPA reviews, rely more heavily on sponsor-prepared documents, and streamline the NEPA process. While the impact of these developments is unclear at this time, any disruption in our ability to obtain permits could result in costs that could have a material adverse effect on our business, financial condition and results of operations.

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. However, in November 2025, Pennsylvania officially withdrew from RGGI. Similar to RGGI, five western states launched the Western Climate Initiative. We cannot predict what other regional GHG reduction initiatives may arise in the future.

It is possible that future international, federal, and state initiatives to control GHG emissions could result in increased costs associated with fossil-fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for fossil-fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, or those of the operators of our mineral interests, which could have a material adverse effect on our business, financial condition, and results of operations. Finally, activists may try to hamper fossil-fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding, and insurance, as well as pursuing tort litigation for various alleged climate-related impacts. For more information, see our Risk Factor titled “Our operations are subject to a series of risks resulting from climate change.”

Water Discharge

The CWA and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact such wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. For more information about asset retirement obligations, please read “Item 8. Financial Statements and Supplementary Data—Note 15 - 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 has authority under Section 404(c) of the Clean Water Act to prohibit, deny, restrict, or withdraw the specification of certain disposal sites for dredged or fill material if it determines that such discharges would have unacceptable adverse effects on specified resources. The EPA has initiated a Section 404(c) proceeding in connection with a proposed mining project, and related litigation remains pending. The scope and application of this authority continue to be subject to regulatory and judicial review.

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 U.S. 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. The Water Quality Certification Improvement Rule was challenged by various states and a coalition of industry groups, and the challenge remains ongoing. Also, in January 2026, the EPA released a proposed rule to revise its CWA Section 401 certification rule following a May 2025 memorandum raising concerns with the existing rule implementing Section 401 promulgated in November 2023. The January 2026 proposed rule seeks to limit the scope of Section 401 reviews and clarify the regulations to ensure such reviews are completed within the one-year statutory

deadline. The proposal is not final and may be modified, challenged, or withdrawn, and any resulting rule or litigation could affect CWA Section 401 certification requirements. The full extent and impact of any such 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. The scope of federal jurisdictional reach over WOTUS under the CWA has been subject to significant uncertainty and litigation for many years. In September 2023, the EPA and the Corps of Engineers issued a final rule conforming the regulatory definition of WOTUS to the U.S. Supreme Court’s 2023 decision inSackett v. EPA, which narrowed the scope of federally jurisdictional waters to “relatively permanent, standing, or continuously flowing bodies of water” and wetlands with a “continuous surface connection” to such waters. However, the rule is currently subject to litigation. As a result, the September 2023 rule is currently in effect in only 24 states, and the EPA and the Corps of Engineers are using the pre-2015 definition of WOTUS in the other 26 states. In November 2025, the EPA and the Corps of Engineers issued a proposed rule to further update and narrow the definition of WOTUS. In addition, the U.S. Supreme Court’s 2020 decision inCounty of Maui v. Hawaii Wildlife Fund held that, in certain cases, certain discharges from a point source to groundwater could fall within the scope of the CWA and require a permit.

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 CCR. On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCR. Under the finalized regulations, CCR is regulated as “non-hazardous” waste and avoids the stricter, more costly, regulations under RCRA’s “hazardous” waste rules. While the classification of CCR 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 CCR rule was subject to legal challenge and ultimately remanded to the EPA. In May 2024, the EPA finalized changes to the CCR regulations for inactive surface impoundments at inactive electric utilities. The final rule expands the scope of impoundments subject to regulation and established groundwater monitoring, corrective action, closure, and post closure care requirements for all CCR management units. Although the rule has been challenged by industry groups, the U.S. Supreme Court rejected the challengers’ request to stay the rule so the rule remains effective as promulgated. Most recently,

on February 6, 2026, EPA announced a final rule that provides additional time to meet facility evaluation requirements for identifying CCR management units and to comply with groundwater monitoring provisions. The combined effect of the CCR 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 EPA has from time to time updated the applicable ELG regulations and most recently, in May 2024, finalized a new ELG rule applicable to steam electric power generating facilities that sets new discharge limits for flue gas desulfurization wastewater, bottom ash transport water, combustion residual leachate, and legacy wastewaters. Subsequently, in December 2025, the EPA finalized a Deadline Extensions Rule that extends certain compliance deadlines under the 2024 ELG rule and provides additional flexibilities, including updated transfer provisions and site-specific alternative compliance dates To the extent the 2024 ELG rule, which applies to a major portion of the electric power industry, remains in effect, it may impact 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 recent years, there has been uncertainty with respect to ESA regulation. Most recently, in November 2025, the USFWS and NMFS issued four proposed rules that would substantially revise ESA implementing regulations and largely reinstate the 2019-2020 regulatory framework under the prior Trump Administration. The proposals would modify the standards for listing and delisting species, revise the approach to designating critical habitats and amend the interagency consultation process to streamline and clarify federal review obligations. They would also restore the prior species-specific approach to protective regulations for threatened species rather than automatically applying blanket prohibitions. 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 SDWA, 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

As of December 31, 2025, we employed 3,575 full-time employees, including 2,895 employees in active coal mining operations, 236 employees at Matrix Design, 237 employees supporting other operating activities, and 207 corporate employees. None of our workforce is subject to a collective bargaining agreement. Retention remains a strength across our workforce, with more than 47% of all employees serving more than five years and our typical employee has approximately four years of experience with the Partnership.

We aim to attract and retain a skilled workforce through competitive, performance-based compensation packages and comprehensive benefits. To benchmark our compensation practices, we regularly review current compensation levels for each position against peers in the coal industry and comparable sectors. Total compensation generally includes some combination of base salary, incentive compensation, health and welfare benefits and participation in our profit sharing and savings plan. Incentive compensation varies by role and may include metrics tied to production and safety goals at a

specific coal operation or broader Partnership-wide objectives. Our goal is to maintain compensation programs that are competitive in the marketplace and aligned with long-term performance and safety priorities.

Workplace safety is foundational to our culture and operations. We prioritize initiatives designed to promote employee engagement in safety processes and to drive continuous improvement. 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 collect respirable dust samples from the mining environment where our miners regularly work and travel, in accordance with regulatory requirements. We are also regularly inspected by MSHA. For more information about citations or orders for violations of standards under the FMSHA, as amended by the MINER Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.

We support the health and well-being of our workforce by offering medical, dental, and vision benefits for our employees. In addition, we offer on-site medical clinics at each of our coal operations and corporate offices to provide convenient access to healthcare and medical services for employees and their families. Dedicated human resources representatives are also stationed at each of our coal operations and corporate offices to assist employees with benefits, training, and other personnel-related matters. Our in-house administration of the medical plan allows us to actively manage costs while improving service delivery for employees. 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.