Alliance Resource Partners LP: Form 10-K for the period ended Dec 31, 2025

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.

Other Growth Investments

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

(tons in millions)

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.

(tons in millions)

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:

• 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 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:

• Brooke County, West Virginia
• Grant County, West Virginia
• Ohio County, West Virginia
• Tucker County, West Virginia
• Washington County, Pennsylvania

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.

Other Growth Investments

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.

Other Growth Investments

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.

• 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 energy transition 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.
• Gavin Generation is a limited partnership that 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.

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;
• restriction of the types, quantities, and concentration of materials that can be released into the environment in the performance of mining or exploration and production activities;
• initiation of 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.

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:

• 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 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:

• In July 2025, MSHA published eighteen notices of proposed rulemaking aimed at streamlining mine operations. A central theme of these proposals is the limitation of district manager authority. Other proposals focus on loosening existing requirements, such as revising standards for flame safety lamps and blacksmith shops, and updating diesel particulate matter provisions to reflect current enforcement practices while maintaining existing exposure limits.
• In April 2024, MSHA adopted a rule on respirable crystalline silica, most commonly found in the mining environment through quartz. The rule, Lowering Miners’ Exposure to Respirable Crystalline Silica & Improving Respiratory Protection, became final on June 17, 2024. The final rule added additional requirements to the

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.

• In December 2024, MSHA adopted a rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments, adopting various voluntary consensus standards to promote innovation in mine safety and health technologies. The rule became final on December 10, 2024, with an effective date of January 9, 2025. Compliance with the revised standards may require us to upgrade, retrofit, or replace certain equipment at our facilities to meet the newly adopted consensus standards.

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:

• The EPA periodically reviews and may revise the NAAQS, which can require additional SIP obligations and emissions controls. In addition, the EPA’s regional haze program requires SIPs intended to protect visibility in certain protected areas, and the EPA may disapprove SIPs and impose a FIP requiring additional controls. These air quality programs, and related rulemaking and litigation, may increase our customers’ operating and capital costs and may contribute to reduced utilization or retirements of coal-fired generating units, which could adversely affect demand and prices for our coal and adversely affect our business and results of operations.
• A range of federal and state air emissions programs under the CAA regulate sulfur dioxide, nitrogen oxides, particulate matter, and other pollutants from coal-fired electric generating units and other industrial sources. These programs include the EPA’s Title IV Acid Rain Program and interstate transport requirements implemented through SIPs and federal rules addressing the interstate movement of ozone and particulate-forming emissions. Compliance with these requirements may be achieved through a combination of emissions allowances and/or emissions budgets, installation or operation of pollution control technologies, fuel switching, and/or reduced utilization. In 2025, we sold 89.2% 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.
• In May 2020, the 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, the EPA published a final revocation of the May 2020 finding. Then, in May 2024, the EPA published a final rule to amend the MATS rule, which further limits the emission of non-mercury hazardous air pollutant metals from existing coal-fired power plants, tightens the emission standard for mercury for existing lignite-fired power plants, and strengthens emissions monitoring and compliance requirements. However, in February 2026, the EPA issued a final rule repealing the amendments finalized in 2024, reverting to the initial emission standards and compliance options established in 2012. Broadly, the MATS program has required many electric power generators to make capital investments to retrofit power plants and may contribute to retirements of older coal-fired generating units. Such retirements could reduce 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.
• 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. 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.

• 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 proposed revisions in February 2024 to its NSR preconstruction permitting regulations to address concerns raised in petition for reconsideration litigation. Depending on the ultimate resolution of the EPA’s litigation and any potential final rule, 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, require that most wells use reduced emission completions, also known as “green completions,” and establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and pneumatic controllers and storage vessels. In December 2023, the 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 processing plants, and transmission and storage facilities. However, in March 2025, the EPA announced plans to reconsider OOOOb and OOOOc. Additionally, in November 2025, the EPA finalized an interim rule extending the compliance deadlines for certain provisions provided in OOOOb and OOOOc. Litigation challenging the EPA’s final interim rule extending such compliance deadlines for new and existing oil and gas sources remains pending. To the extent that these rules are implemented as originally promulgated, 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 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 in West 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 CO2 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 in Seven 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 in Sackett 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 in County 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.

Summary Risk Factors

Our business is subject to a number of risks, including risks that could prevent us from achieving our business objectives or could adversely affect our business, financial condition, results of operations, cash flows, and prospects. These risks are discussed more fully below and include but are not limited to risks related to:

Risks Inherent in an Investment in Us

• Cash distributions are not guaranteed
• Ownership of limited partner interests could be diluted
• Sales of our common units could cause decline in the market price of our common units
• Our unitholders do not elect the general partner
• The control of our general partner may be transferred to a third party
• Unitholders may be required to sell their units to our general partner
• Cost reimbursements due to our general partner could be substantial
• Your liability as a limited partner may not be limited under certain circumstances
• Our general partner’s fiduciary duties are limited, and our general partner has discretion in determining the level of cash reserves and has potential conflicts of interest
• Some executive officers and directors face potential conflicts of interest

Risks Related to Our Business

• Declining global economic conditions could adversely impact us
• Financing may not be available to us on favorable terms or at all
• Our indebtedness could adversely impact us
• We depend upon the leadership of key personnel
• Legal proceedings could adversely impact us
• Our customers may not honor their contracts or may not enter into new contracts for our products
• Some of our contracts may be renegotiated or terminated
• We depend upon a few customers for significant portions of our revenues
• The credit risk of our customers could adversely impact us
• Cyber or terrorist attacks could adversely impact us
• Establishment of labor unions at our operations could adversely affect our profitability

Risks Related to Our Industries

• Changes in coal prices and/or oil & gas prices, including as a result of global geopolitical tensions, could impact our results of operations
• Competition within the coal and oil & gas industry could adversely affect our ability to sell coal
• Changes in taxes or tariffs and trade measures could adversely impact us
• Changes in consumption patterns by utilities could affect our ability to sell coal and/or impact the price of our natural gas
• Unanticipated mine operating conditions could affect our profitability
• Inability to obtain and renew permits and surety bonds necessary for operations could limit our ability to continue or expand our operations
• Fluctuations in transportation costs and availability could reduce demand for our products
• The ability to recruit, hire and retain skilled labor could impact the profitability of our operations
• Disruptions in supply chains, inflationary pressures and unexpected increases in raw material costs could impact the profitability of our operations
• Unavailability of economic coal mineral reserves and resources could limit our ability to continue or expand our operations
• Estimates of our coal mineral reserves and resources and our oil & gas reserves could be inaccurate and could result in decreased profitability
• Extensive environmental laws and regulations could reduce demand for coal as a fuel source
• Legislative and regulatory compliance is costly and could impact our business, and certain legislative and regulatory initiatives relating to our business could have negative impacts
• Mine facilities may be located in a leased portion of the surface properties which introduces a risk of disruption to our operations
• Dependency on unaffiliated operators to explore and drill on our oil & gas properties limits our ability to control the timing and quantity of production
• Delays in royalty payments, optional royalty payments and the suspension of the right to receive royalty payments could impact our business
• Availability of transportation and facilities for the products could impact our business
• Lack of hedging arrangements exposes us to the impact of commodity prices
• Expansions and acquisitions, as well as the integration of such expansions or acquisitions, have inherent risks that could adversely impact us
• Inability to obtain commercial insurance at acceptable rates could have a negative impact on our business

Tax Risks to Our Common Unitholders

• Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the IRS treating us as a corporation or legislative, judicial, or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the Partnership
• Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take
• Tax gain or loss on the disposition of our units could be more than expected and create tax liabilities for our unitholders
• Limitation on unitholders’ ability to deduct interest expense incurred by us could create tax liabilities for our unitholders
• Tax Exempt entities and non-U.S. unitholders face unique tax issues from owning our common units that may result in adverse tax consequences for them
• IRS challenging our allocation of depreciation and amortization deductions and methods of prorating items of income, gain, loss, and deduction could cause adverse tax consequences

Risks Inherent in an Investment in Us

Cash distributions to unitholders are not guaranteed.

The payment and amount of any future distribution will be subject to the sole discretion of the Board of Directors and will depend upon many factors, including our financial condition and prospects, our capital requirements and access to financing, covenants associated with our debt obligations, and other factors that our Board of Directors may deem relevant, and there can be no assurance that we will pay a distribution in the future. The amount of cash we can distribute to holders of our common units or other partnership securities each quarter principally depends on the amount of cash we generate from our operations, which fluctuates from quarter to quarter. In addition, the actual amount of cash available for distribution may depend on other factors, including capital allocation decisions, financing availability, restrictions in debt agreements, and the amount of cash reserves, if any, established by the general partner, in its discretion, for the proper conduct of our business.

Furthermore, since the amount of cash we have available for distribution is not solely a function of profitability, which will be affected by non-cash items, we may make cash distributions during periods when we record net losses and may be unable to make cash distributions during periods when we record net income. Please read “—Risks Related to our Business” for a discussion of further risks affecting our ability to generate available cash.

We may issue an unlimited number of limited partner interests, on terms and conditions established by our general partner, without the consent of our unitholders, which will dilute your ownership interest in us and could increase the risk that we will not have sufficient available cash to make distributions.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ proportionate ownership interest in us will decrease;
• the amount of cash available for distribution on each unit could decrease;
• the relative voting strength of each previously outstanding unit could be diminished;
• the ratio of taxable income to distributions could increase; and
• the market price of our common units could decline.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, including sales by our existing unitholders.

The sale or disposition of a substantial number of our common units by our existing unitholders in the public markets could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sales would be made in the public market or private placements, nor do we know what impact such potential or actual sales would have on our unit price in the future.

An increase in interest rates could cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities could cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities could cause the trading price of our common units to decline.

The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.

The credit and risk profile of our general partner or its owners may be factors in credit evaluations of us as a master limited partnership. This is because our general partner can exercise significant influence or control over our business activities, including our cash distribution policy, acquisition strategy, and business risk profile.

Our unitholders do not elect our general partner or vote on our general partner’s officers or directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner and will have no right to elect our general partner on annual or other continuing bases. If our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66.7% of our outstanding units.

Our unitholders’ voting rights are also restricted by a provision in our partnership agreement that provides that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or a sale of its equity securities without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the members of our general partner to sell or transfer all or part of their ownership interest in our general partner to a third party. The new owner or owners of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by the Board of Directors and officers.

Unitholders may be required to sell their units to our general partner at an undesirable time or price.

If at any time less than 20.0% of our outstanding common units are held by persons other than our general partner and its affiliates, our general partner will have the right to acquire all, but not less than all, of those units at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. Our general partner may assign this purchase right to any of its affiliates or us.

Cost reimbursements due to our general partner could be substantial and could reduce our ability to pay distributions to unitholders.

Before making any distributions to our unitholders, we will reimburse our general partner and its affiliates for all expenses they have incurred on our behalf. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees. For additional information, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence—Related-Party Transactions—Expense Reimbursements.”

Your liability as a limited partner may not be limited, and our unitholders could have to repay distributions or make additional contributions to us under certain circumstances.

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the Partnership, except for those contractual obligations of the Partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been established in many jurisdictions.

Under certain circumstances, our unitholders could have to repay amounts wrongfully distributed to them. Under Delaware law, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the Partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that may otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates and which reduce the obligations to which our general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partner to the limited partners. Our partnership agreement:

• permits our general partner to make many decisions in its “sole discretion.” This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates, or any limited partner;
• provides that our general partner is entitled to make other decisions in its “reasonable discretion”;
• generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; and
• provides that our general partner and our officers and directors will not be liable for monetary damages to us, our limited partners, or assignees for errors of judgment or any acts or omissions if our general partner and those other persons acted in good faith.

All limited partners are bound by the provisions in the partnership agreement, including the provisions discussed above.

Our general partner’s discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires our general partner to deduct from available cash reserves that in its reasonable discretion are necessary for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its interests to the detriment of our unitholders.

Conflicts of interest could arise in the future as a result of relationships between our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its interests and those of its affiliates over the interests of our unitholders. The nature of these conflicts includes the following considerations:

• Remedies available to our unitholders for actions that, without the limitations, could constitute breaches of fiduciary duty are limited. Unitholders are deemed to have consented to some actions and conflicts of interest that could otherwise be deemed a breach of fiduciary or other duties under applicable state law.
• Our general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders.
• Our general partner’s affiliates are not prohibited from engaging in other businesses or activities, including those in direct competition with us, except as provided in the omnibus agreement (please see Exhibits 10.1 and 10.2 to this Annual Report on Form 10-K).
• Our general partner determines the amount and timing of our asset purchases and sales, capital expenditures, borrowings, and reserves, each of which can affect the amount of cash that is distributed to unitholders.
• Our general partner determines whether to issue additional units or other equity securities in us.
• Our general partner determines which costs are reimbursable by us.
• Our general partner controls the enforcement of obligations owed to us by it.
• Our general partner decides whether to retain separate counsel, accountants, or others to perform services for us.
• Our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or from entering into additional contractual arrangements with any of these entities on our behalf.
• In some instances, our general partner may direct us to borrow funds to permit the payment of distributions.

Some of our executive officers and directors face potential conflicts of interest in managing our business.

Certain of our executive officers and directors are also officers and/or directors of AGP. These relationships could create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders’ best interests. These officers and directors face potential conflicts regarding the allocation of their time, which could adversely affect our business, results of operations, and financial condition.

Risks Related to Our Business

Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets could have material adverse impacts on our business and financial condition that we currently cannot predict.

Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:

• the demand for electricity in the United States and globally could decline if economic conditions deteriorate, which could negatively impact the revenues, margins, and profitability of our business;
• any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
• our future ability to access the capital markets could be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including the development of our coal mineral reserves and resources.

Growing our business could require significant amounts of financing that may not be available to us on acceptable terms, or at all.

We plan to fund capital expenditures for our growth initiatives with existing cash balances, future cash flows from operations, borrowings under revolving credit and securitization facilities, and cash provided from the issuance of debt or equity. At times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans could be negatively impacted by constraints in the capital markets as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we could be unable to refinance our current debt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet our funding needs. Furthermore, additional growth projects and expansion opportunities could develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.

Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then-current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations, and cash flows. If we are unable to finance our growth initiatives as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.

Our indebtedness could limit our ability to borrow additional funds, make distributions to unitholders, or capitalize on business opportunities.

We had long-term indebtedness of $463.5 million as of December 31, 2025. Our leverage may:

• adversely affect our ability to finance future operations and capital needs;
• limit our ability to pursue acquisitions and other business opportunities;
• make our results of operations more susceptible to adverse economic or operating conditions; and
• make it more difficult to self-insure for our workers’ compensation or black lung obligations or post collateral security therefor.

In addition, we have unused borrowing capacity under our Revolving Credit Facility. Future borrowings, under our credit facilities or otherwise, could increase our leverage.

Our payments of principal and interest on any indebtedness will reduce the cash available for distribution on our units. We will be prohibited from making cash distributions:

• during an event of default under any of our indebtedness; or
• if after such distribution, we fail to meet a coverage test based on the ratio of our consolidated cash flow to our consolidated fixed charges.

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, engage in some transactions, and capitalize on business opportunities, including the sale or disposition of certain of our mineral assets. For example, if prior to June 15, 2026, a Specified Minerals Disposition (as defined in the indenture governing the 2029 Senior Notes and which involves our oil and gas mineral interests) occurs, we will be required to make an offer to purchase up to 40% of the aggregate principal amount of 2029 Senior Notes.

Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions. Please see “Item 8. Financial Statements and Supplementary Data—Note 6 – Long-Term Debt” for further discussion.

We depend on the leadership and involvement of Joseph W. Craft III and other key personnel for the success of our business.

We depend on the leadership and involvement of Mr. Craft. Mr. Craft has been integral to our success, due in part to his ability to identify and develop internal growth projects and accretive acquisitions, make strategic decisions, and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, financial condition, and results of operations.

We and our subsidiaries are subject to various legal proceedings, which could have a material adverse effect on our business.

We are party to a number of legal proceedings incident to our normal business activities. There is the potential that an individual matter or the aggregation of multiple matters could have an adverse effect on our cash flows, results of operations, or financial position. Please see “Item 3. Legal Proceedings” and “Item 8. Financial Statements and Supplementary Data—Note 16 – Commitments and Contingencies” for further discussion.

The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.

In 2025, we sold approximately 84.6% of our coal sales tonnage under contracts having a term greater than one year, which we refer to as long-term sales contracts. These contracts have historically provided a relatively secure market for the production committed under the terms of the contracts. From time to time industry conditions could make it more difficult for us to enter into long-term sales contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.

Some of our long-term sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of our long-term sales contracts contain provisions that allow the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term sales contracts may provide only limited protection during adverse market conditions. In some circumstances, the failure of the parties to agree on a price under a reopener provision can also lead to the early termination of a contract.

Several of our long-term sales contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer’s reasonable control. Such events could include labor disputes, mechanical malfunctions, and changes in government regulations, including changes in environmental regulations rendering the use of our coal inconsistent with the customer’s environmental compliance strategies. Additionally, most of our long-term sales contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments, or termination of the contracts. In the event of early termination of any of our long-term sales contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition, and results of operations could be adversely affected.

We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of the coal we produce.

In 2025, we derived more than 10% of our total revenues from each of Louisville Gas and Electric Company and American Electric Power Company, Inc. If we were to lose this or any of our significant customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or change the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition, and results of operations.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

Terrorist attacks or cyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.

Like most companies in our industry, we have become increasingly dependent upon access to and the use of our digital technologies, including information systems, infrastructure, and cloud applications and services, to operate our businesses, process and record financial and operating data, communicate with our business partners, analyze mine and mining information, and estimate quantities of reserves and resources, as well as other activities related to our businesses. We also depend on the information systems and infrastructure of third-party vendors, contractors, and partners to support various aspects of our operations. Additionally, certain networks and systems are managed by external service providers which operate outside our direct control. This reliance introduces risks, including potential system failures, security breaches, and external attacks. Strategic targets, such as energy-related assets, could be at greater risk of future terrorist or cyber-attacks than other targets in the United States.

Deliberate attacks, natural disasters, user error, or other security breaches or failures in, on or to our systems or infrastructure, or the systems or infrastructure of third parties on whom we rely could lead to the unauthorized access to, unauthorized disclosure of, restricted access to, or corruption or loss of our proprietary data and potentially sensitive data, including data related to personal information, critical operations and financial records. We have in the past been, and may in the future be, subject to cyber incidents, along with our third-party vendors, contractors and partners. Such incidents may also result in disruptions to critical systems, data corruption, delays in production or delivery, difficulty in completing and settling transactions, misdirected wire transfers, challenges in maintaining our books and records, environmental damage, communication interruptions, increased safety risk for personnel, other operational disruptions, and third-party liability. Additionally, we may face regulatory scrutiny or penalties resulting from data privacy or cybersecurity violations in the aftermath of such incidents. The expanding regulatory framework for data protection increases the challenges of securing our information. Adhering to these changing requirements could cause us to incur substantial costs, and any real or perceived non-compliance may lead to regulatory penalties, legal action, and damage to our reputation.

While we maintain insurance, our insurance may not adequately protect us against all damages as a result of these occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations, cash flows and reputation Although we have implemented and maintain commercially reasonable security controls including by implementing detection and prevention systems, regular cybersecurity assessments, employee training programs, and incident response plans, there are no guarantees that these will be successful in preventing security threats from materializing, detecting such threats, or mitigating their impact. As cybersecurity threats grow increasingly more sophisticated, the risk of successful breaches, disruptions, or vulnerabilities persists despite our proactive efforts and we could be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. While we have not experienced significant losses from cyberattacks so far and take steps to address emerging threats, no security system offers complete protection. Such incidents could lead to the loss of sensitive information or critical resources, regulatory penalties, reputational damage, data privacy liabilities, and substantial costs for remediation and system upgrades, all of which could have a material adverse impact on our reputation, financial position, operations, and cash flows.

We face various risks related to pandemics and similar outbreaks, which have had and may in the future have material adverse effects on our business, financial position, results of operations, and/or cash flows.

Pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease or any other public health crisis may cause disruptions to our business and operations, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) restrictions recommended or imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.

The extent to which any future pandemic may adversely impact our results of operations, cash flows and financial condition depends on future developments, which are highly uncertain and unpredictable.

Although none of our employees are members of unions, our workforce may not remain union-free in the future.

None of our employees are represented under collective bargaining agreements. However, our workforce may not remain union-free in the future, and legislative, regulatory, or other governmental action could make it more difficult to remain union-free. If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations could still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

Risks Related to Our Industries

Prices for oil & gas, as well as coal, are volatile and can fluctuate widely based on a number of factors beyond our control. An extended decline in the prices of such commodities could negatively impact our results of operations.

Our results of operations are primarily dependent upon the prices of oil & gas and coal, as well as our ability to improve productivity and control costs. The prices for oil & gas and coal depend upon factors beyond our control, including:

• overall domestic and global economic conditions;
• the supply of and demand for domestic and foreign coal;
• the supply of and demand for oil & gas;
• weather conditions and patterns that affect demand for coal and oil & gas, or our ability to produce coal or the ability of operators to produce oil & gas from our mineral interests;
• supply chain and cost of raw materials for coal and oil & gas operations;
• the adverse impact of pandemics, outbreaks and other public health events;
• the proximity to and capacity of transportation facilities;
• competition from other coal suppliers;
• domestic and foreign governmental regulations and taxes;
• the price and availability of alternative fuels;
• the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;
• international developments impacting the supply of coal;
• international developments impacting the supply of oil & gas; and
• the impact of domestic and foreign governmental laws and regulations.

Any adverse change in these factors could result in weaker demand and lower prices for our products. A substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenues to the extent we are not protected by the terms of existing coal supply agreements.

Competition within the coal industry could adversely affect our ability to sell coal. In addition, foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete with other coal producers in various regions of the United States for domestic coal sales. In addition, we face competition from foreign and domestic producers that sell their coal in the international coal markets. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources), and reliability of supply. Some competitors could have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers could impact our ability to retain or attract customers and could adversely impact our revenues and cash available for distribution.

We sell coal in the export thermal and metallurgical coal market, both of which are significantly affected by international demand and competition. Consolidation in the coal industry or current or future bankruptcy proceedings of coal competitors could adversely affect us. The prices of and demand for our coal could significantly decline, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows, and could reduce our revenues and cash available for distribution.

In addition, we face competition from foreign producers that sell their coal in the export market. Potential changes to international trade agreements, trade concessions, or other political and economic arrangements could benefit coal producers operating in countries other than the United States. We could be adversely impacted on the basis of price or other factors by foreign trade policies or other arrangements that benefit competitors. In addition, we periodically sell our coal internationally in United States dollars and, as a result, general economic conditions in foreign markets and changes in foreign currency exchange rates could provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the United States dollar or foreign purchasers’ local currencies, those competitors could be able to offer lower prices for coal to those purchasers. Furthermore, if the currencies of overseas purchasers were to significantly decline in value in comparison to the United States dollar, those purchasers may seek decreased prices for the coal we sell. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Changes in taxes or tariffs and other trade measures by the United States and foreign governments could adversely affect our results of operations, financial position, and cash flows.

We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.

New tariffs and other trade measures could adversely affect our results of operations, financial position, and cash flows. In response to tariffs imposed by the United States, several countries have imposed tariffs on United States goods and services, including coal. These tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal and metallurgical coal, limits on trade with the United States or other potentially adverse economic outcomes. Additionally, we sell coal into the export thermal and metallurgical markets. Accordingly, our international sales could also be impacted by the tariffs and other restrictions on trade between the United States and other countries. We cannot predict the impact that new or changes in tariffs and other trade measures imposed by the United States or other countries on United States goods, but such new or changes in trade measures could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution. Please see risk factor titled “Unexpected increases in raw material costs could significantly impair our operating profitability.” for additional information.

Global geopolitical tensions have caused, and may cause in the future, significant market disruptions that may lead to increased volatility in the price of commodities, including oil & gas, coal, and other sources of energy.

Volatility in coal and oil & gas prices has been and may continue to be heightened as a result of the Russian-Ukrainian conflict, hostilities in the Middle East and the potential impact to global shipping and the evolving situation in Venezuela. These events have caused volatility in the aforementioned commodity markets. Such conflicts and the resulting volatility may significantly affect prices for our coal and oil & gas or the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers.

Global geopolitical conflicts, trade and monetary sanctions, as well as any escalation of the conflict and future developments, could significantly affect worldwide market prices and demand for our coal and oil & gas and cause turmoil in the capital markets and generally in the global financial system. Additionally, the geopolitical and macroeconomic consequences of such conflicts and any associated sanctions cannot be predicted but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for products, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations.

Changes in consumption patterns by utilities regarding the use of coal, including plans by utilities to shut down or move away from coal-fired generation, have affected our ability to sell the coal we produce and may do so in the future.

Our business is closely linked to the demand for electricity, and any changes in coal consumption by domestic or international electric power generators would likely impact our business over the long term. The domestic electric power sector accounts for the vast majority of the total domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas, and fuel oil as well as alternative sources of energy. Our primary competition is from natural gas-fired plants that are relatively more efficient and less difficult to permit than coal-fired plants.

Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources such as tax credits, could make alternative fuel sources more competitive with coal. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as MATS, have in the past led to the retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the United States. A decrease in coal consumption by the domestic electric utility industry could adversely affect the demand for or the price of coal, which could negatively impact our results of operations and reduce our cash available for distribution.

Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth in the past, and while demand growth has grown in recent years in the U.S., could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions, could have a material adverse effect on the demand for coal and our business over the long term.

We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation or regulatory fines or penalties related to climate change.

Increased attention to climate change risk has also resulted in governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. In addition, in December 2024, New York adopted a law requiring companies that emitted over one billion tons of GHG emissions into the atmosphere between 2000 and 2018, with sufficient connections to the state, to pay into a “climate superfund” to support climate-related adaptation and mitigation projects. We, among others, have been identified by New York as a potentially responsible party under the law but, to date, have not received any cost recovery demands. The law has been challenged by the Department of Justice pursuant to an Executive Order and the litigation remains pending at this time. It is uncertain whether we or others in our industry will ultimately be required to pay penalties as a result of the New York law, nor can we predict whether or not other states will adopt similar legislation in the future. To the extent we are required to pay such penalties, they could have a material adverse effect on our business, financial condition and results of operations. It is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants or subject to regulatory fines or penalties in the future.

Continued attention to sustainability matters may negatively impact our business, financial results, and unit price.

Companies across all industries, including companies in fossil-fuel industries, have faced increased scrutiny from stakeholders related to their sustainability practices in the past. Companies that did not adapt or comply with evolving investor or stakeholder expectations and standards, or were perceived to have not responded appropriately to sustainability issues, regardless of any legal requirement to do so, might have suffered reputational damage and the business, financial condition, and valuation of such companies could have been adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to sustainability matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increased attention to and demands for action related to climate change, changes in regulation relating to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, reduce demand for our coal and hydrocarbon products, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our unit price and access to capital markets.

Investors’, lenders’ and other stakeholders’ focus on sustainability-related metrics have increased and waned over time, in particular as governmental administrations both domestic and international change from time to time. Companies in general have received pressure from investors, lenders or other stakeholders to adopt climate or other sustainability-related metrics, and to the extent that those pressures impact the fossil fuel industry and, in particular, the coal industry as investors’, lenders’ and other stakeholders’ sentiments regarding sustainability change over time, we cannot guarantee that we will be able to meet such metrics because of potential costs, inaccurate assumptions or technical or operational obstacles. A failure or a perception of failure (whether or not valid) to pursue, implement or make progress against such metrics could result in governmental investigations or enforcement, private litigation and damage our reputation, cause our investors or consumers to lose confidence in us, and negatively impact our operations.

Certain organizations that provide sustainability and other corporate risk information and ratings to investors and unitholders have developed processes to evaluate companies and investment funds based on “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but consideration of sustainability evaluations has become more broadly accepted by some investors in the past. Such assessments were used by some investors to inform their investment decisions. Companies in the energy industry, and in particular those focused on coal, natural gas, or oil extraction, often do not fare as well under sustainability assessments compared to companies in other industries. Consequently, a low sustainability assessment could result in our securities, both debt and equity, being excluded from the portfolios of certain investment funds and investors, restricting our access to insurance or capital to fund our continuing operations and growth opportunities. Additionally, to the extent sustainability matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Certain public statements with respect to sustainability matters have been in the past subject to heightened scrutiny from public and governmental authorities, as well as other parties, related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential sustainability benefits. Certain regulators, such as the SEC (particularly under past presidential administrations) and various state agencies, as well as non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain sustainability statements, emission reduction claims, approaches to accounting for GHG emissions reductions or other sustainability-related goals, or standards were misleading, false, or otherwise deceptive. Any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further sustainability-related focus and scrutiny.

Additionally, certain employment or business practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve. We cannot be certain of the impact of such regulatory, legal and other developments on our business.

Litigation resulting from disputes with our customers could result in substantial costs, liabilities, and loss of revenues.

From time to time, we have disputes with our customers over the provisions of coal supply contracts relating to, among other things, coal pricing, quality, quantity, and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract. Disputes could occur in the future and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition, and results of operations.

Our profitability could decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our coal mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:

• mining and processing equipment failures and unexpected maintenance problems;
• unavailability of required equipment;
• prices for fuel, steel, explosives, and other supplies;
• fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;
• variations in the thickness of the layer, or seam, of coal;
• amounts of overburden, partings, rock, and other natural materials;
• weather conditions, such as heavy rains, flooding, ice, and other natural events affecting operations, transportation, or customers;
• accidental mine water discharges and other geological conditions;
• fires;
• seismic activities, ground failures, rock bursts or structural cave-ins or slides;
• employee injuries or fatalities;
• labor-related interruptions;
• increased reclamation costs;
• inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
• fluctuations in transportation costs and the availability or reliability of transportation;
• new or changes in legislation or regulations that have the effect of increasing our operating costs; and
• unexpected operational interruptions due to other factors.

These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.

Effective October 1, 2025, we renewed our property and casualty insurance program through September 30, 2026. Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance. Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. The maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 75- or 90-day waiting period for underground business interruption depending on the mining complex and an additional $25.0 million overall aggregate deductible. We retained a 2.50% participating interest in our current commercial property insurance program. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, the insurance industry has been subject to efforts by environmental activists to restrict coverages available for fossil-fuel companies.

We could be unable to obtain and renew permits necessary for our coal mining operations, which could reduce our production, cash flow, and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations may not be issued, maintained, or renewed, may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability. Please read “Item 1. Business—Environmental, Health and Safety Regulations—Mining Permits and Approvals.”

The EPA has been reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we could be unable to obtain or experience delays in securing, utilizing, or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position. Please read “Item 1. Business—Environmental, Health and Safety Regulations—Water Discharge.”

In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process or even an inability to obtain permits, permit modifications, or permit renewals necessary for our operations.

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for many of our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers could face difficulties in the future that could impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions in the transportation services provided by our primary rail or barge carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

States in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or maintain production and could adversely affect revenues.

Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID-19 pandemic), labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to participate in the export market for coal sales, which could adversely affect our sales and our results of operations.

Increases in raw material costs could significantly impair our operating profitability.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies, and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas, and coking coal consumed in the production of iron and steel fluctuate significantly and could change unexpectedly. Inflationary pressures, including as a result of the imposition or increase of existing tariffs, have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, and maintenance expenses. For example, on March 12, 2025, the U.S. government imposed a 25% tariff on steel imports, which was increased to 50% on June 4, 2025, and on April 2, 2025, the U.S. government announced a 10% tariff on product imports from almost all foreign countries and individualized higher tariffs on certain other countries. The U.S. government announced on February 20, 2026, that it would maintain the near global tariff under another statutory authority but will increase the tariff to 15%. Several tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused uncertainty and volatility in financial markets and may result in retaliatory measures on U.S. goods. While the ultimate impact of these tariffs is unknown at this time, a portion of our coal production is used by end users to produce steel, and we use a significant amount of steel in our own operations. To the extent that such tariffs depress demand for steel globally or increase the cost to purchase steel, our results of operations, financial position and cash flows may be materially and adversely effected. There could be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products, or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs and could adversely affect our profitability.

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of experienced coal miners has caused us to pay more in direct labor costs in our efforts to attract and maintain talent, and to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs. This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers and attracting new workers to the coal industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

Disruptions in supply chains, inflationary pressures and unexpected increases in raw material costs could significantly impair our operating profitability.

We are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demand for their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability and adversely affect our results of operations.

Inflationary pressures could significantly impair our operating profitability.

Certain countries have experienced and could in the future experience substantial, and in some periods extremely high, rates of inflation. Inflation and rapid fluctuations in inflation rates have had and may continue to have negative effects on the economies of certain countries, including the United States. Inflation rates may continue to increase in the future, and government measures to control inflation, adopted presently or in the future, remain uncertain. Measures taken by the governments to control inflation potentially include maintaining a tight monetary policy with high interest rates, thereby restricting the availability of credit and hindering economic growth. Inflation, measures to combat inflation and public speculation about possible additional actions have contributed materially to economic uncertainty in many countries. Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expenses and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduces demand for our coal or oil & gas and could adversely affect our results of operations.

The unavailability of an adequate supply of coal mineral reserves and resources that can be mined at competitive costs could cause our profitability to decline.

Our profitability depends substantially on our ability to mine coal mineral reserves and resources that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves and resources as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal mineral reserves and resources that are economically recoverable. Replacement reserves and resources may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves or resources that we acquire, which could adversely affect our profitability and financial condition. Exhaustion of reserves and resources at certain mines also could have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves and resources in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates, or the inability to acquire coal properties on commercially reasonable terms.

The estimates of our coal mineral reserves and resources could prove inaccurate and could result in decreased profitability.

The estimates of our coal mineral reserves and resources could vary substantially from the actual amounts of coal we are able to economically recover. The reserve and resource data set forth in “Item 2. Properties—Coal Mineral Resources and Reserves” represent engineering estimates. All of the coal mineral reserves presented in this Annual Report on Form 10-K constitute proven and probable mineral reserves. There are numerous uncertainties inherent in estimating quantities of reserves and resources, including many factors beyond our control. Estimates of coal mineral reserves and resources necessarily depend upon a number of variables and assumptions, any one of which could vary considerably from actual results. These factors and assumptions relate to:

• geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;
• the percentage of coal in the ground ultimately recoverable;
• historical production from the area compared with production from other producing areas;
• the assumed effects of regulation and taxes by governmental agencies;
• future improvements in mining technology; and
• assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.

Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect our actual coal reserves and resources. Actual production, revenues and expenditures with respect to our coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in the closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results.

Coal mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the United States, which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of our coal mineral reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. In addition, permitting, licensing, and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. Subsidence issues are particularly important to our operations engaged in longwall mining. Failure to timely and economically secure subsidence rights or any associated mitigation agreements could materially affect our results by causing delays or changes in our mining plan. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.

Extensive environmental laws and regulations affect coal consumers and could affect the demand for coal as a fuel source.

Federal, state, and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury, and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations could require further emission reductions and associated emission control expenditures. These laws and regulations could affect demand and prices for coal. There is also continuing pressure on federal and state regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as MATS, have led to the retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the United States. Please read “Item 1. Business—Environmental, Health and Safety Regulations—Air Emissions,” “—GHG Emissions” and “—Hazardous Substances and Wastes.”

Our industries are subject to extensive and costly laws and regulations, and such current and future laws and regulations, and uncertainties around the same, could increase current operating costs or otherwise negatively impact our operations.

The industries we participate in—coal mining and the third-party operations related to our oil & gas mineral interests—are subject to numerous federal, state, and local laws and regulations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability. Furthermore, in June 2024, the U.S. Supreme Court issued decisions affecting judicial review of federal agency-related actions that increase judicial scrutiny of agency authority, shift greater responsibility for statutory interpretation to courts, and expand the timeline in which a plaintiff can sue regulators. In particular, in Loper Bright Enterprises v. Raimondo, the U.S. Supreme Court overruled its prior ruling in Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., which held that when a statute is ambiguous or silent, courts should not substitute their own judgments regarding the actions of those agencies so long as the federal agencies’ interpretation of the enabling federal statute was reasonable (this was commonly known as “Chevron deference”). In Loper Bright, the U.S. Supreme Court held that courts must instead exercise their independent judgment when deciding whether an agency has acted within its statutory authority, and that courts may not defer to an agency interpretation simply because a statute is ambiguous. The overturning of the Chevron doctrine is likely to result in challenges to numerous agency interpretations in various areas of law including energy, environment, taxation, and labor, among others. If these challenges are upheld, they could have both favorable and unfavorable impacts on our business, financial condition, results of operations, and cash flows, depending on whether the interpretations that are overturned were more favorable toward the Partnership’s business and operations than subsequent revised agency interpretations. The likely increase of challenges to agency actions may also increase legal costs, create delays in permitting and project development, and create less certainty around agency actions, at least in the near term.

Our coal mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.

We are subject to numerous federal, state, and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining, and the effects that mining has on groundwater quality and availability. Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations could be costly and time-consuming and could delay the commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal. Please read “Item 1. Business—Environmental, Health and Safety Regulations.”

Federal and state laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase our operational expenses and have an adverse effect on our results of operation and financial position. For more information, please read “Item 1. Business—Environmental, Health and Safety Regulations—Mine Health and Safety Laws.”

Oil & gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for the operators, and failure to comply could result in the operators incurring significant liabilities, either of which could impact the operators’ willingness to develop our interests.

The operators on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil & gas wells below actual production capacity to conserve supplies of oil & gas. In addition, the production, handling, storage, and transportation of oil & gas, as well as the remediation, emission, and disposal of oil & gas wastes, by-products thereof, and other substances and materials produced or used in connection with oil & gas operations are subject to regulation under federal, state, and local laws and regulations primarily relating to the protection of worker health and safety, natural resources, and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on the operators, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all of the operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management. Laws and regulations governing exploration and production may also affect production levels. The operators must comply with federal and state laws and regulations governing conservation matters, including:

• provisions related to the unitization or pooling of the oil & gas properties;
• the establishment of maximum rates of production from wells;
• the spacing of wells;
• the plugging and abandonment of wells; and
• the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which could require increased capital costs for third-party oil & gas transporters. These transporters may attempt to pass on such costs to the operators, which in turn could affect profitability on the properties in which we own mineral interests.

The operators must also comply with laws and regulations prohibiting fraud and market manipulation in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity. The operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. While we cannot predict what actions future federal or state regulators may take with respect to environmental regulation, more expansive and stricter environmental legislation and regulations could be possible in the future. These current laws and regulations and other potential regulations could increase the operating costs of the operators and delay production and could ultimately impact the operators’ ability and willingness to develop our properties.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and fewer potential drilling locations, which could adversely affect revenues from our mineral interests.

Oil & gas production on the properties in which we hold mineral interests utilizes hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate the production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The SDWA regulates the underground injection of substances through the UIC program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil & gas commissions.

Several states where we own interests, including Texas and Oklahoma, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. In addition to state laws, local land-use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We cannot predict what additional state or local requirements may be imposed in the future on oil & gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where the operators conduct operations, the operators could incur substantial costs to comply with these requirements, which could be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

In the past, there was increased public concern regarding hydraulic fracturing around increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions were initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for the operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs and adversely affect revenues from our mineral interests. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Legislation or regulatory initiatives intended to address seismic activity could restrict the operators’ drilling and production activities, as well as their ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between the hydraulic-fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil & gas activity and induced seismicity.

In addition, a number of lawsuits have been filed in other states, including in Oklahoma and Texas, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states have adopted or are considering adopting additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, both Texas and Oklahoma have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. For example, the Oklahoma Corporation Commission (“OCC”) has released guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing activities, and has at times ordered well closures in response to seismic activities. In addition, the TRRC ordered the indefinite suspension of all deep oil & gas-produced water injection wells in the area, effective December 31, 2021. Relatedly, in December 2023, in response to continued seismicity within the area, the TRRC issued a notice to suspend the permits of all deep disposal wells within the Northern Culberson-Reeves Seismic Response Area and, in May 2024, the TRRC released a seismicity response plan curtailing permitted injection volumes for certain wells in the Stanton Seismic Response Area. Most recently, in May 2025, the TRRC released updated guidance for disposal well permits in the Permian Basis that placed new limits on maximum injection pressure and volumes to ensure safety.

The adoption or implementation of any new laws or regulations that restrict the operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations, or otherwise, or requiring the operators to shut down or limit the operation of disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Our coal operations, and the third-party operations related to our oil and gas mineral interests, are subject to a series of risks resulting from climate change.

Combustion of fossil fuels, such as the coal we produce and the oil & gas produced from our mineral interests, results in the emission of carbon dioxide into the atmosphere. Additionally, our coal mines may release methane to the atmosphere during operations. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events.

Although Congress has not passed comprehensive climate legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we, our customers, or operators of our mineral interests could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing. For more information, see our risk factor titled “We, our customers, or the operators of our oil & gas mineral interests could be subject to litigation related to climate change.”

There are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies have in the past become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies, although this trend has waned recently and several high-profile banks and institutional investors have withdrawn from various associations that aim to limit financing of industries that emit significant GHG emissions. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining or oil & gas production activities.

In addition, some states (such as California) have adopted or are considering adopting laws requiring the disclosure of certain climate-related risks and GHG emission reduction claims. Lawsuits have been filed challenging the implementation of these laws, but we cannot predict the outcome of these suits at this time. Other states are considering similar laws. Non-compliance with these new laws may result in the imposition of substantial fines or penalties. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.

We could become subject to new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies and related disclosure obligations whether as a result of newly adopted legislation or regulations or as a result of expanding our businesses and operations into areas already subject to more stringent standards, resulting in increased costs of compliance or costs of consuming, and thereby reducing demand for coal and oil & gas and the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us or oil & gas operators restricting or canceling mining or oil & gas production activities, incurring liability for infrastructure damages due to climate change, or having an impaired ability to continue to operate economically. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources, could cause prices and sales of our coal and/or oil & gas to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations, as well as those of the operators and their supply chain. Such physical risks may result in damage to our facilities or the operators’ facilities or otherwise adversely impact operations which could decrease production attributable to our mineral interests. We may not have insurance to cover these risks and the consequences for our or their operations could have a negative impact on the costs and revenues from operations.

Some of our operating subsidiaries lease a portion of the surface properties upon which their mining facilities are located.

Our operating subsidiaries do not, in all instances, own all of the surface properties upon which their mining facilities have been constructed. Certain of the operating companies have constructed and now operate all or some portion of their facilities on properties owned by third parties with whom our subsidiary has entered into a long-term lease. We have no reason to believe that there exists any risk of loss of these leasehold rights given the terms and provisions of the subject leases and the nature and identity of the third-party lessors; however, in the unlikely event of any loss of these leasehold rights, operations could be disrupted or otherwise adversely impacted as a result of increased costs associated with retaining the necessary land use.

Federal and state laws require bonds to secure our obligations related to statutory reclamation requirements and workers’ compensation and black lung benefits. Our inability to acquire or failure to maintain surety bonds that are required by federal and state law would have a material adverse effect on us.

Federal and state laws require us to maintain bonds to secure our obligations to repair and return property to its approximate original state after it has been mined (often referred to as “reclaim” or “reclamation”), to pay federal and state workers’ compensation and pneumoconiosis (or black lung) benefits, and to satisfy other miscellaneous obligations. These bonds provide assurance that we will perform our statutorily required obligations and are referred to as “surety” bonds. These bonds are typically renewable on a yearly basis. At December 31, 2025, our total of such bonds was $237.8 million. The amount of surety bonding we are required to maintain may be increased by the governmental agencies holding the bond.

We could have difficulty acquiring or maintaining surety bonds for a variety of reasons, including:

• substantial increases in the amount of bonding required;
• lack of availability, higher expense, or unreasonable terms of new surety bonds, including as a result of external pressures related to fossil-fuel companies;
• the ability of current and future surety bond issuers to increase required collateral, or limitations on the availability of collateral for surety bond issuers due to the terms of our credit agreements; and
• the exercise by third-party surety bondholders of their rights to refuse to renew the surety.

Failure to acquire or maintain the required bonds could subject us to fines and penalties, result in the loss of our mining permits, or imperil our ability to self-insure workers compensation and pneumoconiosis obligations, and could have a material adverse effect on us.

We depend on unaffiliated operators for all of the exploration, development, and production of the oil & gas properties in which we own mineral interests.

Because we depend on unaffiliated third-party operators for all of the exploration, development, and production of our oil & gas properties, we have little to no control over the operations related to our oil & gas properties. The operators of our properties are often not obligated to undertake any development activities. In the absence of a specific contractual obligation, any development and production activities will be subject to their sole discretion (subject, however, to certain implied obligations to develop imposed by state law). The success and timing of drilling and development activities on our oil & gas properties, and whether the operators elect to drill any additional wells on our acreage, depends on several factors that are largely outside of our control, including:

• the capital costs required for drilling activities by the operators of our oil & gas properties, which could be significantly more than anticipated;
• the ability of the operators of our properties to access capital;
• prevailing commodity prices;
• the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
• the operators’ expertise, operating efficiency, and financial resources;
• approval of other participants in drilling wells;
• the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;
• the selection of technology;
• the selection of counterparties for the marketing and sale of production; and
• the rate of production of the reserves.

The operators may elect not to undertake development activities or may undertake these activities in an unanticipated fashion, which could result in significant fluctuations in our oil & gas revenues.

We have little to no control over the timing of future drilling with respect to our oil & gas mineral interests.

All of our oil & gas mineral interests may not ultimately be developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue the development of an undeveloped drilling location will be made by the operator and not by us. We generally do not have access to the estimated costs of development of these reserves or the scheduled development plans of the operators. Our estimate of reserves assumes that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and could result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved undeveloped reserves as unproved reserves.

We could experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

A failure on the part of the operators of our properties to make royalty payments gives us the right to terminate the lease and enforce payment obligations under the lease. If we terminate any of our leases, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under the Bankruptcy Code, in which case our right to enforce or terminate the lease for any defaults, including non-payment, could be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have substantial time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery could be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

If the operators of our oil & gas properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, and/or results of operations could be adversely affected.

Upon a change in ownership of mineral interests, and at regular intervals pursuant to routine audit procedures at each of the operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full payments that would have been made during the suspense period, without interest. Certain of the Operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest. If a significant amount of our royalty interests is placed in suspense, our results of operations could be reduced significantly.

Our estimated oil & gas reserves are based on many assumptions that could turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil & gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil & gas and assumptions concerning future oil & gas prices, production levels, ultimate recoveries, and operating costs. As a result, the estimated quantities of proved reserves and projections of future production rates could be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2025, were audited by CGA, which conducted a detailed review of all of our properties at that time using the information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. In addition, certain assumptions regarding future oil & gas prices, production levels, and operating costs could prove incorrect. A meaningful portion of our reserve estimates is made without the benefit of lengthy production history, which is less reliable than estimates based on lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil & gas that are ultimately recovered being different from our reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the FASB, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil & gas index prices, calculated as the unweighted arithmetic average for the first day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs could differ materially from those used in the present value estimate, and future net present value estimates using then-current prices and costs could be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil & gas industry in general. Please see “Item 2. Properties—Oil & Gas Reserves” for more information on our reserves.

Drilling for and producing oil & gas are high-risk activities with many uncertainties that could materially adversely affect our business, financial condition, and results of operations.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our unitholders that wells drilled by the operators of our properties will be productive. Drilling for oil & gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or gas to return a profit at then realized prices after deducting drilling, operating, and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that oil or gas is present or that it can be produced economically. The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, the operators’ drilling and producing operations could be curtailed, delayed, canceled, or otherwise negatively impacted as a result of other factors, including:

• unusual or unexpected geological formations or earthquakes;
• loss of drilling fluid circulation;
• title problems;
• facility or equipment malfunctions;
• unexpected operational events;
• shortages or delivery delays of equipment and services;
• compliance with environmental and other governmental requirements; and
• adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources, and equipment, pollution, environmental contamination or loss of wells, and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or canceled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations, and free cash flow could be materially adversely affected.

The marketability of oil & gas production is dependent upon transportation and other facilities, certain of which neither we nor the operators of our properties control. If these facilities are unavailable, the operators’ operations could be interrupted and our results of operations and cash available for distribution could be materially adversely affected.

The marketability of the operators’ oil & gas production will depend in part upon the availability, proximity, and capacity of transportation facilities, including gathering systems, trucks, and pipelines, owned by third parties. Neither we nor, in general, the operators of our properties control these third-party transportation facilities and the operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact the operators’ ability to deliver to market or produce oil & gas and thereby cause a significant interruption in the operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production-related difficulties, they may be required to shut-in or curtail production. In addition, the amount of oil & gas that can be produced and sold may be subject to curtailment in certain other circumstances outside of our or the operators’ control, such as pipeline interruptions due to maintenance, excessive pressure, the inability of downstream processing facilities to accept unprocessed gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances could last from a few days to several months. In many cases, we and the operators are provided with limited notice, if any, as to when these curtailments will arise and the duration of such curtailments. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil & gas produced from our acreage, could adversely affect our financial condition, results of operations, and cash available for distribution.

We do not currently enter into hedging arrangements with respect to commodity production from our properties, and we will be exposed to the impact of decreases in the price of such commodities.

We have not entered into hedging arrangements to establish, in advance, a price for the sale of the oil & gas or the coal produced from our properties, and we may not enter into such arrangements in the future. As a result, although we could realize the benefit of any short-term increase in commodity prices, we will not be protected against commodity price decreases or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operations and cash available for distribution.

In the future, we may enter into hedging transactions with the intent of reducing volatility in our cash flows due to fluctuations in the price of oil & gas or coal. However, these hedging activities may not be as effective as we intend in reducing the volatility of our cash flows and, if entered into, are subject to the risks that the terms of the derivative instruments will be imperfect, a counterparty may not perform its obligations under a derivative contract, there could be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our hedging policies and procedures may not be properly followed and the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, we could be limited in receiving the full benefit of increases in commodity prices as a result of these hedging transactions. The occurrence of any of these risks could prevent us from realizing the benefit of a derivative contract.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

Since our formation and the acquisition of our predecessor in August 1999, we have expanded our coal operations by adding and developing mines in existing, adjacent, and neighboring properties. Similarly, the profitability of our business depends significantly upon acquisitions to grow our coal and oil & gas reserves, production, and free cash flow. Our future growth could be limited if we are unable to continue to make acquisitions in either our coal operations or our royalties segments, or if we are unable to successfully integrate the companies, businesses, or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.

Competition for acquisitions of coal and oil & gas mineral interests could increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing under acceptable terms. In addition, these acquisitions could be in geographic regions in which we do not currently hold properties, which could subject us to additional and unfamiliar legal and regulatory requirements. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.

The process of integrating acquired assets could involve unforeseen difficulties and could require a disproportionate amount of our managerial and financial resources. If we are unable to successfully integrate the companies, businesses, or properties we acquire, our profitability could decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:

• uncertainties in assessing the value, strengths, and potential profitability of expansion and acquisition opportunities;
• uncertainties in identifying the extent of all weaknesses, risks, contingent and other liabilities of, expansion and acquisition opportunities;
• the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;
• problems that could arise from the integration of the new operations; and
• unanticipated changes in business, industry, or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and could require us to incur indebtedness, seek equity capital, or both. Future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

The integration of any expansions or acquisitions that we complete will be subject to substantial risks.

Even if we make expansions or acquisitions that we believe will increase our coal or mineral revenue, any expansion or acquisition involves potential risks, including, among other things:

• the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, the operating expenses, and costs the operators would incur to develop the minerals;
• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate or uncollectable;
• mistaken assumptions about the overall cost of equity or debt;
• our ability to obtain satisfactory title to the assets we acquire;
• an inability to hire, train or retain qualified personnel to manage and operate our growing mineral assets; and
• the occurrence of other significant changes, such as impairment of properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.

We may not be able to effectively identify investment opportunities in the growth and development of energy and related infrastructure on favorable terms, or at all, and failure to do so may limit our future growth.

Part of our strategy includes positioning ourselves as a reliable energy provider for the future by pursuing strategic investments that leverage our core competencies and relationships with electric utilities, industrial customers, and federal and state governments. This strategy depends on our ability to successfully identify and evaluate investment opportunities. The number of opportunities may be limited, and we will compete with other investors for these limited opportunities, which could make them more expensive and the returns for our investments less attractive and possibly cause us to refrain from making them at all. Further, certain opportunities will depend on technological and other advancements that may not be within our control and may not come to fruition or be economically feasible in the near term, and we may fail to realize, and in some cases have failed to realize, the anticipated benefit of our investments. Any new opportunities also may depend on the viability of new assets or businesses that are contingent on public policy mechanisms including investment tax credits, subsidies, renewable portfolio standards and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable energy, demand-side, and other infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of investments generally, as well as our participation in them.

Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.

We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.

Tax Risks to Our Common Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and our not being subject to a material amount of entity-level taxation. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

Even though we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, and would likely be liable for state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because taxes would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced and the value of our units could be negatively impacted.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

Any modification to the U.S. federal income tax laws and the interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

If the IRS were to contest the U.S. federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions that we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders could be reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties and interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to pay taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If a unitholder sells units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease such unitholder’s tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to a unitholder if it sells such units at a price greater than its tax basis in those units, even if the price such unitholder receives is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its units, a unitholder may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and IRAs, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any distribution in excess of our cumulative net income. As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our units or result in audit adjustments to a unitholder’s tax returns.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based on ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Certain U.S. federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

In past years, members of the U.S. Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. Elimination of those provisions would have no impact on our financial statements or results of operations. However, elimination of such provisions could result in unfavorable tax consequences for our unitholders and, as a result, could negatively impact our unit price.

Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, our unitholders may be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.

We currently own assets and conduct business in multiple states that currently impose a personal income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, foreign, state, and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

Description of Processes for Assessing, Identifying, and Managing Cybersecurity Risks

We operate in an increasingly interconnected digital landscape and we recognize the importance of assessing, identifying, and managing material risks from cybersecurity threats. In the normal course of business, we may collect and store certain sensitive information, including proprietary and confidential business information, intellectual property, sensitive third-party information, employee information and other personal information. We rely on our own information systems and third-party information systems for the management of this information in addition to our management of business processes including inventory, payment of obligations, collection of cash, human capital management, financial tools and other processes and procedures. Our ability to manage our business effectively depends on the reliability, security and capacity of these systems. We seek to address these risks by safeguarding assets, data, and operations through the cybersecurity risk management processes described below:

Risk Assessment:

Regular assessments are conducted across our systems, networks, and data infrastructure to identify potential cybersecurity threats and vulnerabilities. These assessments include penetration testing, vulnerability scanning, and red teaming exercises conducted by third-party service providers, which help us to evaluate the likelihood and potential impact of cybersecurity incidents. Feedback from these assessments is incorporated into our systems and procedures through upgrades intended to further improve our security posture.

Incident Identification and Response:

A monitoring and detection system has been implemented to help identify cybersecurity incidents. The IT Security Department is tasked with monitoring certain network activities, logs, and system behavior, leveraging threat detection technologies. In the event of any breach or cybersecurity incident, we have an incident response plan that is designed to follow industry best practices and aligns with legal and regulatory requirements. This plan is designed to provide for immediate action to contain the incident, mitigate the impact, and restore normal operations efficiently.

Cybersecurity Training and Awareness:

Cybersecurity awareness among our employees is promoted with regular training and awareness programs. Employees receive training on recognizing and reporting potential cybersecurity threats, best practices for data protection, and adhering to cybersecurity policies and procedures. Additionally, periodic simulated phishing exercises are conducted to enhance employee readiness in identifying and mitigating phishing attacks.

Access Controls:

Access control policies have been implemented to limit unauthorized access to sensitive information and we seek to maintain and monitor critical systems. Multi-factor authentication is used for remote access, use of privileged accounts and access to critical systems.

Encryption and Data Protection:

Encryption methods are used to protect sensitive data in transit and at rest. This includes the encryption of customer data, financial information, and other confidential data.

The above cybersecurity risk management processes are integrated into the Partnership’s overall risk management program. Cybersecurity threats are understood to be dynamic and intersect with various other enterprise risks. As such, cybersecurity is considered an important component of our enterprise-wide risk management approach. We have assembled a Cybersecurity Steering Committee comprised of IT management, cybersecurity specialists, and representatives of business management, including the CTO and internal legal counsel. The Cybersecurity Steering Committee reviews information security policies and cybersecurity risks in conjunction with other operational, financial, and strategic risks to ensure alignment with our business objectives. The Cybersecurity Steering Committee convenes regularly to review and monitor the Partnership’s programs for the prevention, detection, mitigation, and remediation of cybersecurity incidents. The Cybersecurity Steering Committee receives reports on security incidents, threat intelligence, and vulnerability assessments from our IT Security Department.

The Cybersecurity Steering Committee regularly reports to the CFO through the CTO and reports annually on cybersecurity to the Audit Committee during a scheduled meeting. These reports include, as appropriate, updates on the current cybersecurity landscape, incident trends, and any significant developments that may impact the Partnership’s security posture.

To enhance the effectiveness of our cybersecurity program, we periodically engage external assessors, consultants, and auditors. These third-party service providers conduct independent evaluations of our cybersecurity measures, helping to identify areas for improvement and adherence to industry standards and best practices.

Our IT Security Department recognizes that third-party service providers may introduce cybersecurity risks to our organization. In an effort to mitigate these risks, we have implemented a process designed to assess and oversee the cybersecurity practices of our vendors. Before engaging with any third-party cybersecurity service provider, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we include cybersecurity requirements in our contracts with these providers, requiring them to adhere to certain cybersecurity standards and protocols.

Impact of Risks from Cybersecurity Threats

The energy industry increasingly depends on information and operational technology to sustain critical functions. However, the rise in cybersecurity incidents, whether caused by deliberate attacks or accidental events, poses substantial challenges. As these threats grow in complexity and scale, the industry’s efforts to prevent, detect, mitigate, and remediate such incidents become progressively more demanding and complex.

During 2025 and through the date of this Annual Report on Form 10-K, though the Partnership and our service providers may have experienced cybersecurity incidents, we are not aware of any cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or are reasonably likely to materially affect the Partnership, including our business strategy, result of operations, or financial condition. However, we acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Our IT Security Department aims to monitor and assess these risks to maintain the security and continuity of our operations. Despite the implementation of our cybersecurity programs, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our IT systems could have significant consequences to our business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. Please see “Item 1A. Risk Factors” for additional information about the risks to our business associated with a breach or compromise to our information technology systems.

Board of Directors’ Oversight of Risks from Cybersecurity Threats

The Board of Directors oversees risks from cybersecurity threats. Recognizing the importance of cybersecurity to the success and resilience of our business, the Board considers cybersecurity to be an important aspect of corporate governance. To facilitate effective oversight, the Audit Committee and the Board of Directors hold discussions with management, including the CTO on cybersecurity risks, incident trends, and the effectiveness of cybersecurity measures annually and as needed during both scheduled and special meetings. If new material cybersecurity risks arise, the Board of Directors and the Audit Committee are informed through regular discussions between the CFO and both the Chairman of the Board and the Audit Committee Chair. These discussions are then brought to the attention of the Board of Directors and Audit Committee at the next meeting.

Management’s Role and Expertise

The CTO and the Cybersecurity Steering Committee are responsible for overseeing and executing our cybersecurity strategy, including the assessment and management of cybersecurity risks. The CTO reports directly to the CFO and maintains communication with the Audit Committee, the Board of Directors and the Cybersecurity Steering Committee with respect to information security and cybersecurity matters.

The CTO holds a Master of Business Administration from the University of Kentucky/University of Louisville’s joint executive program and has an extensive background in information security, risk management, and incident response with over twenty years of varying information technology roles with increasing responsibility at both private and public companies. The CTO is supported by a dedicated team of cybersecurity professionals, each bringing diverse expertise in areas such as network security, data protection, and threat intelligence.

COAL MINERAL RESOURCES AND RESERVES

Overview of Coal Properties

Our coal properties are located in the Illinois Basin and the Appalachia Basin. Our Illinois Basin properties are located in western Kentucky, southern Illinois, and southern Indiana. Our Appalachian properties are located in eastern Kentucky, western Maryland, western Pennsylvania, and northern West Virginia. Mining operations on our coal properties consist of underground mines that produce bituminous coal that is sold to customers principally for electric power generation (thermal) and the production of steel (metallurgical). In addition to our coal mining operations, we also hold coal mineral interests that we lease/sublease to our operations or hold for lease/sublease to our operations or others. For a detailed overview of our coal mining operations and our coal royalty activities, please see “Item 1. Business—Coal Mining Operations” and “Item 1. Business—Mineral Interest Activities”, respectively.

Evaluation and Review of Coal Mineral Resources and Reserves

Numerous uncertainties are inherent in estimating coal mineral resources and reserves, and the estimates are subject to change as additional information becomes available or circumstances change. Significant factors and assumptions related to the uncertainty in estimating coal mineral reserves and resources include:

• geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;
• the percentage of coal in the ground ultimately recoverable;
• historical production from the area compared with production from other producing areas;
• the assumed effects of regulation and taxes by governmental agencies;
• future improvements in mining technology; and
• assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.

Each of the factors which impacts reserve and resource estimation may vary considerably from the assumptions used in making the estimation and, as a result, the estimates in this report may not accurately reflect the actual coal reserves and resources. Actual production, revenues, and expenditures with respect to the coal reserves will likely vary from the assumptions used in these estimates, and these variances may be material. Government regulations and other pressures may result in the closure of coal-fired electric generating plants earlier than assumed. Such changes would reduce the economic viability of our mining operations and could have a material adverse impact on our operations and financial results.

Under SEC rules, a mineral resource is a concentration or occurrence of a material of economic interest in or on the Earth’s crust in such form, grade or quality, and quantity that there are reasonable prospects for economic extraction. A mineral resource is a reasonable estimate of mineralization, considering relevant factors such as cut-off grade, likely mining dimensions, location or continuity that, with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part, become economically extractable. A mineral reserve is an estimate of tonnage and grade or quality of indicated and measured mineral resources that, in the opinion of the qualified person, can be the basis of an economically viable project. More specifically, it is the economically mineable part of a measured or indicated mineral resource, which includes diluting materials and allowances for losses that may occur when the material is mined or extracted.

The coal mineral resource and reserve estimates included in this Annual Report on Form 10-K were prepared by an independent, qualified engineering firm, RESPEC. We provided RESPEC with property control, mine plans, production, revenue, costs, capital, and other information considered by RESPEC in making their estimates. As part of our internal controls, our geologists and engineers review the integrity, accuracy, and timeliness of the data provided to RESPEC that they considered in calculating their coal mineral resource and reserve estimates. We also review the geologic data, mining assumptions, and methodology used by RESPEC to estimate our coal mineral resources and reserves. Our geologists and engineers also meet with RESPEC periodically during the year to discuss the assumptions and methods used in the coal mineral resource and reserve estimation process.

RESPEC, an independent third-party engineering firm, does not have an interest in any of our properties and is not employed on a contingent basis. RESPEC prepared the initial TRS for each of our material mining properties. The TRSs will be updated when there are material changes to the coal mineral reserve or resource estimates. The most recent TRSs for our material mining operations are included as exhibits to our Annual Report on Form 10-K.

Summary of Coal Mineral Resources and Reserves

Coal Mineral Resources

Most of our coal properties designated as mineral resources are of thickness, quality, and mineability similar to our mineral reserves, and all are proximal to existing infrastructure such as power, water, transportation, facilities, etc. However, we have not completed pre-feasibility or feasibility studies with respect to our coal properties designated as mineral resources, as is required to convert the mineral resources into mineral reserves. There is no certainty that all or any part of the mineral resources will be converted into mineral reserves.

The following table sets forth our coal mineral resources, exclusive of coal mineral reserves, at December 31, 2025:

(1) Combined resources are defined as measured plus indicated resources.

(2) As with our Henderson County mine, River View (KY) has geographic overlap with Henderson/Union (KY) and there is potential for further development of our resources from the existing facilities. See Individual Property Disclosures for more detail.

On December 31, 2025, we had approximately 1.066 billion tons of coal mineral resources. Tonnages are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2025 in a range from approximately $46 to $59 per short ton in the Illinois Basin and from approximately $64 to $117 per short ton in the Appalachian Basin, which are the prices used by RESPEC to verify the amount of coal mineral resources. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All resources are classified as underground mineable in the exploration stage.

Coal Mineral Reserves

Reserves at our active operations are currently in production and meet the other requirements to be considered reserves as defined by the SEC. There is no certainty that all our mineral reserves remain economically viable as fluctuations in pricing and costs occur within the coal industry.

The following table sets forth coal mineral reserve information, exclusive of the coal mineral resources, at December 31, 2025:

On December 31, 2025, we had approximately 586.5 million tons of coal mineral reserves. Tonnages are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2025 in a range from approximately $46 to $59 per short ton in the Illinois Basin and from approximately $64 to $117 per short ton in the Appalachian Basin, which are the prices used by RESPEC to verify the amount of coal mineral reserves. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All reserves are classified as underground mineable in the development or production stage.

Mining Operations

The following table sets forth production and other data about our mining operations:

(in millions)

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Individual Property Disclosures

We consider the following properties to be material based on multiple factors including, but not limited to, the property’s contribution to our overall business and financial condition. Please see Coal Mineral Resources and Coal Mineral Reserves above for information about the coal mineral resources and reserves held by these material properties. In addition to the following information, TRSs for these material properties with additional information are included as exhibits to this Annual Report on Form 10-K.

Henderson/Union Resources

The Henderson/Union Resources are located in Henderson and Union counties, Kentucky at 37°44'30"N, -87°46'07"W and we currently have control in over 1,600 tracts encompassing over 127,000 acres. The property is controlled through both fee ownership and leases of the coal. The coal mineral resources are controlled by Alliance Resource Properties. The base leases are with private owners and WKY CoalPlay or its subsidiaries, which are related parties. See “Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions” for more information about our WKY CoalPlay transactions. These base leases generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:

Major Roads: Interstate 69 and US-60,

Railroads: None,

Airport: Evansville Regional Airport (EVV),

Town: Morganfield,

Docks: River View, Hamilton 1, UC Processing, on the Ohio River,

Water: Local municipalities and mine sources,

Electricity: Kentucky Utilities (KU),

Personnel: Regional.

Description

The potential underground mine(s) would utilize room-and-pillar methods operating a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill possible permitting and development requirements. Multiple access points are available for development. Access is available from the active River View complex, which began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Access at the Hamilton and UC Coal, LLC sites are considered “brownfield” developments. Though some facilities and permitting are in place, significant upgrades to existing infrastructure and new construction would be needed to bring them into good working order that meets industry standards. The property associated with Henderson/Union has no book value as of December 31, 2025 but does have outstanding advanced royalties with WKY CoalPlay or its subsidiaries. See “Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions” for more information about advanced royalties that Henderson/Union has with WKY CoalPlay.

Though there is geographic overlap between the Henderson/Union and River View properties, the resources and reserves of each are associated with different coal seams or, if in the same seam, are separated by existing mine works or geologic features into distinct areas. There is no overlap in the resource / reserve estimation.

History

The Henderson/Union property contains resources in the WKY11, WKY7, and WKY6 seams. Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and controlled a portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 mine. Peabody and later Patriot operated the Camp complex and Highland #11 mine to the southeast and east. The WKY11 seam was mined at these locations. No mining has occurred on the property in the WKY7 or WKY6 seams.

In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market.

Encumbrances

Our credit facility is secured by, among other things, liens against certain Henderson/Union surface properties and coal leases. Documentation of such liens is of record in the Offices of the Henderson and Union County Clerks. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our credit facility.

The KYDNR, DMP is responsible for the review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining.

Geology and Reserves

Henderson/Union contains coal resources in three seams ranging in depths from about 100 to 750 feet. The table below summarizes mineral resources as of December 31, 2025, using a cut off thickness of 4.00 feet:

River View Complex

The River View complex is located in Union County, Kentucky at 37°45'37"N, -87°56'42"W and currently has approximately 93,200 underground acres permitted. The complex is composed of the River View and Henderson County mines along with shared preparation, loadout, and other ancillary facilities. The mineral is controlled through both fee ownership and leases of the coal. The coal mineral reserves are leased or held for lease to the River View complex almost exclusively by Alliance Resource Properties. The River View complex either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts, and slopes. The base leases are with private owners and generally provide for a term that can be extended until exhaustion of the leased coal. Local infrastructure is as follows:

Major Roads: Interstate 69 and US-60,

Railroads: None,

Airport: Evansville Regional Airport (EVV),

Town: Morganfield,

Docks: River View on the Ohio River,

Water: Union and Henderson County water districts and mine sources,

Electricity: Kentucky Utilities (KU),

Personnel: Regional.

Description

The underground mines are currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The complex began production in 2009. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for the River View complex as of December 31, 2025 was $387.4 million.

Though there is geographic overlap between the River View complex and the Henderson/Union properties, the reserves and resources of each are associated with different coal seams or, if in the same seam, are separated by existing mine works or geologic features into distinct areas. There is no overlap in the resource / reserve estimation.

History

Island Creek operated mines in the area and controlled a portion of the property. Under a joint venture, Texas Gas Service also controlled a large interest in the mineral rights. Lastly, Peabody and Patriot operated mines in the area and controlled a smaller portion of the reserves. We consolidated control of the property through multiple transactions from 2005 through 2015. Island Creek operated the Ohio #11 and Uniontown #9 mines to the west of River View. Island Creek also operated the Hamilton #1 and #2 mines to the southwest. Peabody and later Patriot operated the Camp mines and Highland mines adjacent to the complex. Both the WKY9 and WKY11 seams were mined at these locations. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market.

Encumbrances

Our credit facility is secured by, among other things, liens against certain River View complex surface properties and coal leases. Documentation of such liens is of record in the Office of the Union County Clerk. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our credit facility.

Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Union County Clerk. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our accounts receivable securitization facility.

The KYDNR, DMP is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities, and other incidental activities have been obtained and remain in good standing.

Geology and Reserves

The River View complex extracts coal underground from the WKY11 and WKY9 seams with depths ranging from 200 to 500 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2025 using a cut off thickness of 4.00 feet:

Resources associated with the River View complex are included in the Coal Mineral Resources table above.

The River View complex had 303.5 million tons of coal mineral reserves at the end of 2024. The year over year reconciliation is as follows:

(in millions)

Normal course adjustments are associated with numerous small changes in the geologic/mining model.

Hamilton Mine

Hamilton, a longwall mine located in Hamilton County, Illinois at 38°10'12"N, -88°36'47"W, currently has approximately 23,270 underground acres permitted. The mineral is controlled through both fee ownership and leases of the coal. The coal mineral reserves and resources are leased or held for lease to Hamilton by Alliance WOR Properties, a subsidiary of Alliance Resource Properties. Hamilton either owns or controls the surface properties upon which its facilities are located including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. The underlying base coal leases are with private owners and are comprised of a large number of leases originally taken by AMAX Coal Company and Old Ben in the mid to late 1970’s and early 1980’s, leases acquired by Consolidation Coal Company in the late 1980’s, and subsequent leases taken directly by White Oak Resources, LLC or affiliated companies and/or Alliance WOR Properties. Local infrastructure is as follows:

Major Roads: Interstate 64,

Railroads: CSX and EVW,

Airport: Evansville Regional Airport (EVV),

Towns: McLeansboro and Mt. Vernon,

Docks: Mount Vernon on the Ohio River,

Water: Hamilton County Water District and mine sources,

Electricity: Wayne-White Electric Co-op (WWEC),

Personnel: Regional.

Description

The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Hamilton as of December 31, 2025 was $377.3 million.

History

There were no previous operations on the Hamilton reserves property prior to our predecessor, White Oak Resources LLC, who began construction of the mine in 2011. In general, all drilling has shown highly consistent coal seams of mineable thickness and quality for the high-sulfur thermal utility market for the Herrin and Springfield seams.

Encumbrances

Our credit facility is secured by, among other things, liens against certain Hamilton surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Hamilton County Clerk. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our credit facility.

The Illinois Department of Natural Resources, Land Reclamation Division is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation and related facilities and other incidental activities have been obtained and remain in good standing.

Geology and Reserves

Hamilton extracts coal underground from the Herrin (Illinois No.6) seam with depths ranging from 900 to 1100 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2025 using a cut off thickness of 4.00 feet:

Resources associated with Hamilton County are included in the Coal Mineral Resources table above.

The Hamilton mine had 113.8 million tons of coal mineral reserves at the end of 2024. The year over year reconciliation is as follows:

(in millions)

Normal course adjustments are associated with numerous small changes in the geologic/mining model.

Gibson South Mine

Gibson South is located in Gibson County, Indiana at 38°18'22"N, 87°42'30"W and currently has approximately 41,640 underground acres permitted. The mineral is controlled through both fee ownership and leases of the coal. Leases generally have an initial term with automatic extensions for as long as mining operations are conducted within a described area. Local infrastructure is as follows:

Major Roads: Interstates 69 and 64,

Railroads: CSX and NS,

Airport: Evansville Regional Airport (EVV),

Town: Princeton,

Docks: Mount Vernon on the Ohio River,

Water: Gibson Water, Inc. and well water,

Electricity: Western Indiana Energy REMC,

Personnel: Regional.

Description

The underground mine is currently in production using room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2014. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Gibson South as of December 31, 2025 was $108.9 million.

History

In November 1997, pursuant to (a) Assignment of Underground Coal Leases, (b) Partial Assignment of Underground Coal Leases and (c) Special Corporate Warranty Deed, Old Ben conveyed to MAPCO Land & Development Corporation various coal leases and fee coal interests within a large property boundary located in Gibson County, Indiana. MAPCO Land & Development Corporation changed its name to MAPCO Coal Land & Development Corporation, and MAPCO Coal Land & Development Corporation merged into Alliance Properties effective August 4, 1999.

After the original Old Ben acquisition, Alliance Properties and Gibson continued to acquire additional coal leases and fee coal interests in the area. In addition, beginning in or around 2006, the leases originally acquired from Old Ben began to expire by their terms, and Alliance Properties/Gibson began a program of either amending the expiring leases or entering into new, direct leases with the coal owners. Alliance Properties merged into Gibson on February 19, 2018.

The King’s Mine operated to the east and the Wabash Mine operated to the west of the reserve area. In general, all drilling has shown a highly consistent coal seam of mineable thickness and quality for the high-sulfur domestic thermal utility market and low/medium sulfur export market.

Encumbrances

Our credit facility is secured by, among other things, liens against certain Gibson surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the Recorder of Gibson County, Indiana. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our credit facility.

Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the Recorder of Gibson County, Indiana. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our accounts receivable securitization facility.

The Indiana Department of Natural Resources, Division of Reclamation is responsible for oversight of active coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations. In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation, and related facilities and other incidental activities have been obtained and remain in good standing.

Geology and Reserves

Gibson South extracts coal underground from the Springfield (Indiana No.5) seam with depths ranging from 450 to 650 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2025 using a cut off thickness of 4.00 feet:

Resources associated with Gibson South are included in the Coal Mineral Resources table above.

The Gibson South mine had 40.0 million tons of coal mineral reserves at the end of 2024. The year over year reconciliation is as follows:

(in millions)

Normal course adjustments are associated with numerous small changes in the geologic/mining model.

Tunnel Ridge Mine

Tunnel Ridge, located at 40°09'17" N, -80°39'26"W, is an underground longwall mine in the Pittsburgh No. 8 seam and currently has approximately 23,870 underground acres permitted. The mineral is controlled through both fee ownership and leases of the coal. The coal mined and to be mined by Tunnel Ridge is leased from Alliance Resource Properties and third parties. Prior to January 29, 2026, certain of the coal mined and to be mined by Tunnel Ridge had been leased from the Craft Foundations. On January 29, 2026, Alliance Resource Properties purchased all of the ownership interests in these coal reserves together with surface rights from the Craft Foundations. Please read “Item 8. Financial Statements and Supplemental Data— Note 12 – Long-term Debt and —Note 21 – Related-Party Transactions” for additional information on related-party leases and transactions. Tunnel Ridge either owns or controls the surface properties upon which its facilities are located, including the preparation plant, refuse areas, mine offices, conveyor systems, shafts and slopes. Local infrastructure is as follows:

Major Roads: Interstate 70,

Railroads: None,

Airport: Pittsburgh International Airport (PIT),

Town: Wheeling,

Docks: Tunnel Ridge on the Ohio River,

Water: Municipal water districts and mine sources,

Electricity: American Electric Power (AEP), West Penn Power (WPP),

Personnel: Regional.

Description

The underground mine is currently in production using longwall and room-and-pillar methods utilizing a heavy media, float/sink style preparation plant. Exploration continues as needed to fulfill mining and permitting requirements. The mine began production in 2010. All equipment, facilities, infrastructure, and underground development are in good working order and maintained to industry standards. Total book value of the property and any associated plant and equipment for Tunnel Ridge as of December 31, 2025 was $330.9 million.

History

Valley Camp operated mines on the property prior to Tunnel Ridge’s operations. In general, all drilling has shown a highly consistent coal seam of mineable thickness and quality for the high-sulfur thermal utility market.

Encumbrances

Our credit facility is secured by, among other things, liens against certain Tunnel Ridge surface properties, coal leases and owned coal. Documentation of such liens is of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our credit facility.

Accounts receivable generated from the sale of coal mined from this property are collateral for our accounts receivable securitization facility, evidenced by financing statements of record in the Office of the County Commission of Ohio County, West Virginia and the Office of the Recorder of Deeds of Washington County, Pennsylvania. Please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-term Debt” for more information on our accounts receivable securitization facility.

Tunnel Ridge is located on the West Virginia / Pennsylvania State boundary, operating in each state. As such, regulatory requirements must be met pertaining to mining facilities located in each state.

For operations in West Virginia, the WVDEP is the regulatory authority over mining activities. Within the WVDEP, the Division of Mining and Reclamation is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.

For operations in Pennsylvania, the PADEP is the regulatory authority over mining activities. Within the PADEP, the Bureau of District Mining Operations is responsible for review and issuance of all permits relative to coal mining and reclamation activities, and financial assurance of comprehensive environmental protection performance standards related to surface and underground coal mining operations.

In addition to state mining and reclamation laws, operators must comply with various federal laws relevant to mining. All applicable permits for underground mining, coal preparation, and related facilities and other incidental activities have been obtained and remain in good standing.

Geology and Reserves

Tunnel Ridge extracts coal underground from the Pittsburgh No.8 seam with depths ranging from 300 to 975 feet across the reserve. The table below summarizes mineral reserves as of December 31, 2025 using a cut off thickness of 4.00 feet:

Resources associated with Tunnel Ridge are included in the Coal Mineral Resources table above.

The Tunnel Ridge mine had 111.0 million tons of coal mineral reserves at the end of 2024. The year over year reconciliation is as follows:

(in millions)

Normal course adjustments are associated with numerous small changes in the geologic/mining model.

OIL & GAS RESERVES

Summary of Oil & Gas Reserves

Our mineral interests are primarily located in three basins, which also represent our areas of focus for future development. These include the Permian (Delaware and Midland), Anadarko (SCOOP/STACK) and Williston (Bakken) Basins. At December 31, 2025, we had 51,233 developed and undeveloped net acres held at a weighted average royalty of 17.0%. Our net acres standardized to 1/8th royalty equate to 69,880 net royalty acres, including 3,962 net royalty acres owned through our equity interest in AllDale III.

The following table presents our estimated net proved oil & gas reserves, including our share of reserves attributable to our equity interest in AllDale III, as of December 31, 2025 based on the reserve report prepared by our internal engineering team and reserve information provided by AllDale III. The reserve report and reserve information have been prepared in accordance with the rules and regulations of the SEC. All of our proved reserves are located in the continental United States.

(1) Proved reserves of approximately 2,037 MBOE were attributable to noncontrolling interests as of December 31, 2025.

(2) Natural gas reserve volumes are converted to BOE based on a 6:1 ratio: 6 Mcf of natural gas converts to one BOE.

Estimates of reserves as of December 31, 2025 were prepared using product prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2025. The average realized product prices weighted by production over the remaining lives of the properties are $64.89/Bbl for oil, $1.40/Mcf of natural gas and $18.29 per barrel of NGL. These prices are adjusted for energy content, associated average differential and transportation deducts by producing area to arrive at the net realized prices by product. For 2025, NGL prices averaged approximately 33% of the posted oil prices during the course of the year with an additional $3.38/Bbl deducted for transportation costs.

The following table summarizes our changes in proved undeveloped reserves (in MBOE):

During the year ended December 31, 2025, PUD reserves were increased as a result of the acquisition of oil & gas mineral interests during the year primarily from the Elk Range Acquisition discussed in more detail in “Item 8. Financial Statements and Supplementary Data—Note 4 – Acquisitions.”

During the year ended December 31, 2025, PUD reserves were reduced as a result of conversion to proved developed reserves primarily in the Permian and Anadarko basins as the result of well completions during the year.

Extensions and discoveries contributed to an increase in PUD reserves during the year ended December 31, 2025 primarily as the result of permitting activities in the Permian Basin.

Revisions of previous estimates resulted in a decline due primarily to revisions to quantity estimates.

As a mineral interest owner we have no transparency into or control over the operators’ investments and operational progress to convert PUDs to proved developed producing reserves nor do we have insight into the operators’ drilling plans. Since we do not have insight into the operators’ drilling plans, we use active drilling permits as evidence of economic viability and intention to expend capital to develop reserves within five years as there is generally a statutory two-year timeframe associated with permits. We do not incur capital expenditures or lease operating expenses in connection with the development of our PUDs, which costs are borne entirely by the operators. As a result, during the year ended December 31, 2025, we did not have any expenditures to convert PUDs to proved developed producing reserves. PUDs that have not been developed within two years of permitting are reviewed and removed from proved reserves as necessary. Because we remove PUDs from proved reserves that have not been developed within two years of initial classification as proved reserves, we have no material PUDs that are not expected to be developed within five years of initial classification as proved reserves. Our average permit to first sales timeframe is 381 days. For our 2025 reserve reporting, we had scheduled all PUD locations to be drilled within a two year timeframe using the average historical development pacing on our acreage in the individual basins in which we own mineral interests. As of December 31, 2025, approximately 10.26% of our total proved reserves were classified as PUDs.

Evaluation and Review of Reserves

Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

Under SEC rules, proved reserves are those quantities of oil & gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible–from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations–prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2025 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil & gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil & gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods:

(1) performance-based methods,

(2) volumetric-based methods and

(3) analogy.

These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Performance methods include, but may not be limited to, decline curve analysis, which utilize extrapolations of available historical production data. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

To estimate economically recoverable proved reserves and related future net cash flows, our engineering team considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, and radioactivity logs.

Non-producing reserve estimates, for both developed and undeveloped properties, are based on regional type curve methodologies by reservoir or productive bench. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and undeveloped reserves for our properties, due to the mature nature of properties targeted for development and an abundance of historical production data on which we base statistical average type forecasts.

New drills on our acreage include planned drills, wells currently drilling, and/or permitted wells. For each new drill, a reserve category of proved developed non-producing or PUD is assigned based on whether the location has been spud or permitted. Generally, we recognize a location as a PUD when it has been permitted by the operator and a PUD becomes a proved developed non-producing reserve when the operator has spud that well to begin drilling operations.

Drill scheduling is determined by historical development pacing on our acreage in each basin and it is assumed that future pacing will mirror that of the historical pace. This projection is then adjusted to take into account anticipated commodity prices and other industry economic factors which tend to either reduce or increase future development pacing. First, known completed locations are developed in chronological order based on state filings or publicly sourced completion data. The development schedule for these locations estimates the turn-in-line rate of these locations due to production data lag. Second, spud locations with unknown completion status are scheduled based on the historical spud to completion time within each basin. Third, permitted locations, without development timing, are scheduled in chronological order by filing date.

Excluding our share of proved reserves held by AllDale III, our 2025 year-end estimate of proved reserves were prepared by our internal engineering team. Our engineering team works to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our proved reserve estimates, with the exception of AllDale III, which comprise 3.3% of our total proved reserves, were audited by CGA. Our engineering team met with CGA periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. Our engineering team provided historical information to CGA for our properties, such as oil & gas production, well test data, and realized commodity prices. Our engineering team also provided ownership interest information with respect to our properties. Our internal petroleum engineer, primarily responsible for overseeing the petroleum reserves preparation, has over 20 years of engineering and operations experience in the oil & gas sector and a Bachelor of Science in Petroleum Engineering.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

• review and verification of historical data, which is based on actual production as reported by the operators;
• verification of property ownership by our land department;
• review of all our reported proved reserves semi-annually including the review of all significant reserve changes and proved undeveloped reserves additions by our internal petroleum engineer;
• internally prepared reserve estimates compared to reserves audit by CGA;
• review of changes in reserves semi-annually by our internal petroleum engineer and by senior management; and
• no employee’s compensation is tied to the amount of reserves booked.

CGA, an independent third-party petroleum engineering firm, does not own an interest in any of our properties and is not employed on a contingent basis. When compared on a well-by-well basis, some of our estimates are greater and some are less than the CGA estimates. CGA is satisfied with our methods and procedures used to prepare the December 31, 2025 reserve estimates and future revenue, and noted nothing of an unusual nature that would cause CGA to take exception with the estimates, in the aggregate, prepared by us. CGA’s audit report with the respect to our proved reserve estimates as of December 31, 2025 is included as an exhibit to this Annual Report on Form 10-K.

CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for auditing the estimates meets or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry-standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Acreage Concentration

Below is a chart reflecting our gross, net mineral and net royalty acreage associated with our mineral interests in each of our primary basins as of December 31, 2025.

The 51,233 developed and undeveloped net mineral acres in the table above represent the number of acres that are owned for the mineral rights under a given tract of land, whereas the 69,880 developed and undeveloped net royalty acres are our net mineral acres normalized to 1/8th royalty leasing terms. As an example, if 100 net mineral acres were leased for a 25% royalty, this would be equivalent to 200 net royalty acres, normalized to 1/8th royalty (100 x .25/.125 = 200).

Our royalty interests are predominately perpetual mineral interests. As a mineral interest owner, we generally hold our acreage in perpetuity and not through a lease. As a result, our undeveloped acreage is not generally subject to expiration. Our royalty interests do include a small portion that come in the form of overriding royalites (ORRI) that are subject to lease terminations once the wells on that lease cease to produce oil & gas in commercial quantities. As a result, we do have limited long-dated lease expiration exposure; however, nearly all of these ORRIs are part of leases with proved developed producing reserves and ongoing development that we believe will be sufficient to maintain these leases for decades.

Oil & Gas Production Prices and Production Costs

For the year ended December 31, 2025, 44.5% of our production and 75.2% of our oil & gas revenues were related to oil production and sales, respectively. The following table sets forth information regarding production of oil & gas including our equity investment in AllDale III and certain price and cost information for each of the periods indicated:

Productive Wells

As of December 31, 2025, our productive wells were as follows:

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. We do not own any material working interests in any wells and therefore use our net revenue interest to determine our net wells.

Drilling Results

As a holder of mineral interests, we generally do not receive information as to whether wells drilled on the acreage associated with our mineral interests are classified as exploratory or as developmental wells. We are not aware of any dry holes drilled on the acreage associated with our mineral interests during the year ended December 31, 2025. Based on our net revenue interests, 4, 9 and 10 net wells were drilled on our interests during the years ended December 31, 2025, 2024 and 2023, respectively.

From time to time, we are party to litigation matters incidental to the conduct of our business. It is the opinion of management that the ultimate resolution of our pending litigation matters will not have a material adverse effect on our financial condition, results of operation or liquidity. However, we cannot assure you that disputes or litigation will not arise or that we will be able to resolve any such future disputes or litigation in a satisfactory manner. From time to time, we are also a party to certain environmental legal proceedings involving governmental authorities. Our threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1.0 million. The information under “General Litigation” and “Other” in “Item 8. Financial Statements and Supplementary Data—Note 16 – Commitments and Contingencies” is incorporated herein by this reference.

Litigation was initiated in November 2019 in the U.S. District Court for the Western District of Kentucky (Branson v. Webster County Coal, LLC, et al.) against certain of our subsidiaries in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time “donning” and “doffing” equipment and to account for certain bonuses in the calculation of overtime rates and pay. A similar lawsuit was initiated in March 2020 in the U.S. District Court for the Eastern District of Kentucky (Brewer v. Alliance Coal, LLC, et al.). Subsequently, four additional lawsuits making similar allegations were initiated against certain of our subsidiaries: filed March 4, 2021 in the Circuit Court for Hopkins County, Kentucky (Johnson v. Hopkins County Coal, LLC, et al.); filed April 6, 2021 in the U.S. District Court for the Northern District of West Virginia (Rettig v. Mettiki Coal WV, LLC, et al.); filed April 9, 2021 in the U.S. District Court for the Southern District of Illinois (Cates v. Hamilton County Coal, LLC, et al.); and filed April 13, 2021 in the U.S. District Court for the Southern District of Indiana (Prater v. Gibson County Coal, LLC, et al.). The plaintiffs in these cases sought class and collective action certification, which we opposed. The plaintiffs sought to recover alleged compensatory, liquidated and/or exemplary damages for the alleged underpayment, and costs and fees that potentially may be recoverable under applicable law. In April 2024, we entered into a settlement agreement with the plaintiffs pursuant to which we agreed to settle all six cases for $15.3 million. In November 2025, the court approved the parties’ settlement and settlement checks were distributed in December 2025. Following an acceptance period, the parties will file a joint notice of the acceptance period’s conclusion and a notice of voluntary dismissal with prejudice.

The following discussion of our financial condition and results of operations should be read in conjunction with the historical financial statements and notes thereto included in “Item 8. Financial Statements and Supplementary Data” where you can find more detailed information in “Note 1 – Organization and Presentation” and “Note 2 – Summary of Significant Accounting Policies” regarding the basis of presentation supporting the following financial information.

Executive Overview

Organization

We are a diversified natural resource company that generates operating and royalty income from the production and marketing of coal to major domestic utilities, industrial users and international customers, as well as royalty income from oil & gas mineral interests located in 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.

Please see “Item 1. Business and Item 2. Properties” for a more detailed discussion of our various businesses.

As of December 31, 2025, we had four reportable segments: Illinois Basin Coal Operations, Appalachia Coal Operations, Oil & Gas Royalties and Coal Royalties. We also have an “all other” category referred to as Other, Corporate and Elimination. Our two coal operations reportable segments correspond to major coal producing regions in the eastern United States with similar economic characteristics including coal quality, geology, coal marketing opportunities, mining and transportation methods and regulatory issues. Our Oil & Gas Royalties reportable segment includes our oil & gas mineral interests. Our Coal Royalties reportable segment includes coal mineral reserves and resources owned or leased by Alliance Resource Properties.

• The Illinois Basin Coal Operations reportable segment includes (a) the Gibson mining complex, (b) the Warrior mining complex, (c) the River View mining complex and (d) the Hamilton mining complex. The segment also includes activity associated with support services and our non-operating mining complexes.
• The Appalachia Coal Operations reportable segment includes (a) the Mettiki mining complex, (b) the Tunnel Ridge mining complex and (c) the MC Mining mining complex.
• The Oil & Gas Royalties reportable segment includes oil & gas mineral interests held by Alliance Minerals as well as our equity interests in AllDale III.
• The Coal Royalties reportable segment includes substantially all of our coal mineral resources and the majority of our coal mineral reserves owned or leased by Alliance Resource Properties. Approximately 73% of the coal sold by our coal operations’ mines was leased from our Coal Royalties entities for the year ended December 31, 2025.
• Other, Corporate and Elimination includes marketing and administrative activities, the Matrix Group, Bitiki (which holds our crypto-mining activities), our non-oil & gas investments, Wildcat Insurance (which assists the ARLP Partnership with its insurance requirements), and AROP Funding and Alliance Resource Finance Corporation (both discussed in “Item 8. Financial Statements and Supplementary Data – Note 12 – Long-Term Debt”), and other miscellaneous activities. The eliminations included in Other, Corporate and Elimination primarily represent the intercompany coal royalty transactions described above between our Coal Royalties reportable segment and our coal operations’ mines.

Risks and Uncertainties

We face a variety of risks and uncertainties that management considers in the operation and planning of our businesses, which could affect our financial position and results of operations. For additional information regarding our risks and uncertainties that affect our business and the industries in which we operate, see “Item 1A. Risk Factors”.

Business Strategy

Our primary business strategy is to create sustainable, capital-efficient growth in available cash to maximize unitholder returns by:

• expanding our coal operations by adding and developing mines and coal mineral reserves and resources in existing, adjacent or neighboring properties;
• extending the lives of our mining operations through the acquisition and development of coal mineral reserves and resources using our existing infrastructure;
• continuing to make productivity improvements to remain a low-cost coal producer in each region in which we operate;
• strengthening our position with existing and future customers by offering a broad range of coal qualities, transportation alternatives and customized services;
• developing strategic relationships to take advantage of opportunities within the coal and oil & gas industries and in other industries;
• continuing to make investments in oil & gas mineral interests in various geographic locations within producing basins in the continental United States;
• strengthen and expand our technology company, Matrix Group, as we continue to develop and market industrial, mining and technology products and services worldwide; and
• continuing to identify and make strategic investments in the growth and development of energy and related infrastructure opportunities to leverage our core competencies and build platforms for future lines of business with long-term growth and cash flow generation.

How We Evaluate Our Performance

Our management uses a variety of financial and operational measurements to analyze our performance. Primary measurements include the following: (1) coal volumes; (2) coal sales; (3) oil & gas volumes; (4) oil & gas royalties; (5) intercompany coal royalties; (6) Segment Adjusted EBITDA Expense; and (7) Segment Adjusted EBITDA.

Coal Volumes

We monitor and analyze our coal sales and production volumes of our mining complexes. We also regularly compare budgeted to actual volumes reported and investigate variances. Coal sales volumes are used as a measure of performance as well as an indicator of inventory levels at our complexes when viewed in connection with coal production volumes. Coal production volumes give us an insight into the capacity usage of our complexes and are a source of expenses on a per ton basis as fixed costs are spread across the production.

Coal Sales

We monitor and analyze coal sales as a measure of performance of our coal mining operations. We review coal sales and coal sales per ton at a consolidated level as well as at the mining complex level. We calculate coal sales per ton by dividing coal sales by coal sales volumes. We regularly compare budgeted coal sales and coal sales per ton to actual coal sales and coal sales per ton and investigate unexpected variances.

Oil & Gas Volumes

We monitor and analyze our oil & gas royalty volumes from the various basins that comprise our portfolio of mineral interests. We also regularly compare budgeted to actual volumes reported and investigate variances. Oil & gas royalty volumes on a BOE basis are used as a measure of performance and give us insight into the production activity of our operators.

Oil & Gas Royalties

We monitor and analyze our oil and gas royalties in total and on a price per BOE from the various basins that comprise our portfolio of mineral interests. We also regularly compare budgeted to actual volumes and investigate unexpected variances. We define price per BOE as total oil & gas royalties divided by BOE produced. We review oil & gas royalties and price per BOE to evaluate performance against budget and for trend analysis.

Intercompany Coal Royalties

We monitor and analyze our coal royalties, coal royalty volumes and coal royalties per ton at our various mining subsidiaries for coal leased by Alliance Resource Properties for trend analysis. We define coal royalties per ton as total coal royalties divided by royalty tons sold.

Segment Adjusted EBITDA Expense

We define Segment Adjusted EBITDA Expense (a non-GAAP financial measure) as the sum of operating expenses, coal purchases and other expenses as adjusted to remove certain items from operating expenses that we characterize as unrepresentative of our ongoing operations. Transportation expenses are excluded as these expenses are passed through to our customers and, consequently, we do not realize any gain or loss on transportation revenues. Segment Adjusted EBITDA Expense is used as a supplemental financial measure by our management to assess the operating performance of our segments. Segment Adjusted EBITDA Expense is a key component of Segment Adjusted EBITDA in addition to coal sales, royalty revenues and other revenues. The exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA Expense allows management to focus solely on the evaluation of segment operating performance as it primarily relates to our operating expenses. We also review Segment Adjusted EBITDA Expense on a per ton basis for cost trends at our coal operations by dividing Segment Adjusted EBITDA expense by coal sales volumes.

Segment Adjusted EBITDA

We define Segment Adjusted EBITDA (a non-GAAP financial measure) as net income attributable to ARLP before net interest expense, income taxes, depreciation, depletion and amortization and general and administrative expenses adjusted for certain items that we characterize as unrepresentative of our ongoing operations. Segment Adjusted EBITDA is a key component of consolidated Adjusted EBITDA, which is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We believe that the presentation of consolidated Adjusted EBITDA provides useful information to investors regarding our performance and results of operations because Adjusted EBITDA, when used in conjunction with related GAAP financial measures, (i) provides additional information about our core operating performance and ability to generate and distribute cash flow, (ii) provides investors with the financial analytical framework upon which we base financial, operational, compensation and planning decisions and (iii) presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations.

Segment Adjusted EBITDA is also used as a supplemental measure by our management for reasons similar to those stated in the previous explanation of Adjusted EBITDA. In addition, the exclusion of corporate general and administrative expenses from Segment Adjusted EBITDA allows management to focus solely on the evaluation of segment operating profitability as it relates to our revenues and operating expenses, which are primarily controlled by our segments.

Analysis of Historical Results of Operations – 2025 Compared with 2024

Consolidated Information

(in thousands)

(1) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

(2) For definitions of Segment Adjusted EBITDA and Segment Adjusted EBITDA Expense and related reconciliations to their respective comparable GAAP financial measures, please see below under “— Reconciliation of Non-GAAP Financial Measures.”

Total Revenues

Total revenues decreased 10.4% to $2.19 billion in 2025 compared to $2.45 billion 2024 primarily due to lower coal sales pricing and transportation revenues.

• Coal sales decreased to $1.93 billion in 2025 compared to $2.11 billion in 2024. The decrease was attributable to lower average coal sales prices, which reduced coal sales by $157.0 million and lower tons sold, which reduced coal sales by $22.3 million. Coal sales prices decreased by 7.5% as a result of lower domestic price realizations at several mines due to the continued roll-off of higher-priced contracts entered into during the energy crisis and reduced export price realizations from our MC Mining and Mettiki mines.
• Transportation revenues and expenses were $36.6 million and $112.6 million in 2025 and 2024, respectively. The decrease of $76.0 million was primarily attributable to lower third-party transportation rates in 2025 and decreased coal shipments to the international markets for which we arrange third-party transportation. Transportation revenues are recognized when title to the coal passes to the customer and recognized in an amount equal to the corresponding transportation expenses.

Segment Adjusted EBITDA Expense

Segment Adjusted EBITDA Expense decreased 9.1% to $1.39 billion in 2025 primarily related to our coal operations which decreased 9.3% to $1.36 billion, as a result of lower per ton costs and sales volumes. Segment Adjusted EBITDA Expense per ton sold for our coal operations decreased 8.4% to $41.29 per ton sold in 2025 compared to $45.07 per ton in 2024, primarily due to an increased sales mix of tons from lower cost operations, higher recoveries from several mines and fewer longwall move days at our Hamilton operation as well as the following per ton cost decreases:

• Labor and benefit expenses, excluding workers’ compensation, per ton produced decreased 6.8% to $13.06 per ton in 2025 from $14.01 per ton in 2024. The decrease of $0.95 per ton was primarily due to lower direct labor costs at several mines.
• Material and supplies expenses per ton produced decreased 12.2% to $13.95 per ton in 2025 from $15.88 per ton in 2024. The decrease of $1.93 per ton produced primarily reflects decreases of $0.67 per ton for roof support, $0.33 per ton in longwall subsidence expense, and $0.28 per ton for contract labor used in the mining process.
• Maintenance expenses per ton produced decreased 13.1% to $4.70 per ton in 2025 from $5.41 per ton in 2024. The decrease of $0.71 per ton produced was primarily a result of lower maintenance costs at several mines.
• Outside coal purchases decreased to $21.8 million in 2025 compared to $35.8 million in 2024. The decrease in outside coal purchases benefited costs per ton in 2025 since the cost of outside coal purchases is generally higher on a per ton basis than our produced coal.

Depreciation, depletion and amortization

Depreciation, depletion and amortization expense increased to $299.4 million in 2025 compared to $285.4 million in 2024 primarily as a result of recent capital investments at our River View and Tunnel Ridge mines.

Asset impairments

During 2024, we recorded $31.1 million of non-cash asset impairment charges as a result of our decision to reduce production at our MC Mining operation due to market uncertainty, challenging geology and higher costs. Please read “Item 8. Financial Statements and Supplementary Data—Note 9 – Long-Lived Asset Impairments” for more information.

Equity method investment income (loss)

We had equity method investment income of $21.0 million in 2025 compared to an equity method investment loss of $5.0 million in 2024. The change was primarily due to income attributable to our investments in Gavin Generation and NGP ET IV.

Change in fair value of digital assets

We recorded a $4.4 million decrease in the fair value of our digital assets in 2025 compared to an increase of $22.4 million during 2024 reflecting the movement in the price of bitcoin during each period.

Impairment loss on investments

During 2025, we recorded impairments totaling $28.0 million on our equity and debt investments in Ascend. Please read “Item 8. Financial Statements and Supplementary Data—Note 10 – Investments” for more information.

Net income attributable to ARLP

Net income attributable to ARLP for 2025 was $311.2 million, or $2.40 per basic and diluted limited partner unit, compared to $360.9 million, or $2.77 per basic and diluted limited partner unit, for 2024 as a result of lower revenues and a decrease in the fair value of our digital assets in 2025, partially offset by reduced operating expenses and increased investment income.

Segment Adjusted EBITDA

Our 2025 Segment Adjusted EBITDA decreased $14.6 million, or 1.8%, to $781.9 million from 2024 Segment Adjusted EBITDA of $796.5 million.

Segment Information

(in thousands)

(1) BOE for natural gas is calculated on a 6:1 basis (6,000 cubic feet of natural gas to one barrel).

(2) Represents tons sold by our coal operations segments associated with coal reserves leased from our Coal Royalties Segment.

Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased 3.6% to $456.7 million in 2025 from $473.9 million in 2024. The decrease of $17.2 million was primarily attributable to lower coal sales prices, partially offset by higher sales volumes and lower operating expenses. Coal sales price per ton decreased by 7.7% compared to 2024 as a result of lower domestic price realizations across the region. Sales volumes increased by 4.0% compared to 2024 due primarily to increased tons sold from our Hamilton and River View mines. Segment Adjusted EBITDA Expense decreased 4.5% compared to 2024 due to lower operating expenses per ton. Segment Adjusted EBITDA Expense per ton in 2025 decreased by 8.2% compared to 2024 due primarily to increased production and improved recoveries at our River View and Hamilton mines, higher volumes at our Warrior operation, and reduced longwall move days at Hamilton.

Appalachia Coal Operations – Segment Adjusted EBITDA decreased 18.5% to $133.7 million in 2025 from $164.1 million in 2024. The decrease of $30.4 million was primarily attributable to lower coal sales, which decreased 17.2% to $590.2 million in 2025 from $712.7 million in 2024, partially offset by lower operating expenses. The decrease in coal sales reflects lower coal sales volumes and price realizations. Tons sold decreased by 15.6% in 2025 compared to 2024 primarily as a result of lower production levels at Tunnel Ridge due to challenging mining conditions and the recent transition to a new longwall district. Average coal sales price per ton decreased by 1.8% compared to 2024 primarily due to reduced domestic pricing from our Tunnel Ridge and MC Mining operations and lower export price realizations from MC Mining and Mettiki, partially offset by a greater mix of higher priced sales tons from the MC Mining and Mettiki operations during 2025. Segment Adjusted EBITDA Expense decreased 16.7% to $459.4 million in 2025 from $551.7 million in 2024 due to reduced volumes and lower per ton operating expenses. Segment Adjusted EBITDA Expense per ton for 2025 decreased by 1.3% compared to 2024 due to higher recoveries at the Mettiki and MC Mining operations.

Oil & Gas Royalties – Segment Adjusted EBITDA increased slightly to $117.5 million for 2025 from $117.0 million in 2024. The increase was primarily due to increased volumes in 2025, which increased by 7.2%, higher other revenues and lower expenses, partially offset by lower average sales price per BOE, which decreased 7.0% to $37.79 per BOE. Higher BOE volumes during 2025 resulted from increased drilling and completion activities on our properties and additional volumes from oil & gas mineral interest acquisitions.

Coal Royalties – Segment Adjusted EBITDA increased 20.2% to $52.9 million for 2025 from $44.0 million in 2024. The $8.9 million increase was a result of increased royalty tons sold and higher average royalty rates per ton.

Analysis of Historical Results of Operations – 2024 Compared with 2023

For discussion and analysis of 2024 compared to 2023, please refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on February 27, 2025, and is incorporated by reference herein.

Reconciliation of Non-GAAP Financial Measures

The following is a reconciliation of net income, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA:

(in thousands)

The following is a reconciliation of operating expenses, the most comparable GAAP financial measure, to consolidated Segment Adjusted EBITDA Expense:

(in thousands)

Liquidity and Capital Resources

Liquidity

We have historically satisfied our working capital requirements and funded our capital expenditures, investments, contractual obligations and debt service obligations with cash generated from operations, cash provided by the issuance of debt or equity, borrowings under credit and securitization facilities and other financing transactions. We believe that existing cash balances, consisting of cash and cash equivalents of $71.2 million at December 31, 2025, future cash flows from operations and investments, borrowings under credit facilities and cash provided from the issuance of debt or equity will be sufficient to meet our working capital requirements, capital expenditures and additional investments, debt payments, contractual obligations, commitments and distribution payments. Nevertheless, our ability to satisfy our working capital requirements and additional investments, to satisfy our contractual obligations, to fund planned capital expenditures, to service our debt obligations or to pay distributions will depend upon our future operating performance and access to and cost of financing sources, which will be affected by prevailing economic conditions generally, and in both the coal and oil & gas industries specifically, as well as other financial and business factors, some of which are beyond our control. Based on our recent operating cash flow results, current cash position, anticipated future cash flows and sources of financing that we expect to have available, we anticipate being in compliance with the covenants of the Credit Agreement and expect to have sufficient liquidity to fund our operations and growth strategies. However, to the extent operating cash flow or access to and cost of financing sources are materially different than expected, future covenant compliance or liquidity may be adversely affected. Please see “Item 1A. Risk Factors.”

Unit Repurchase Program

We have $80.6 million remaining authorized under our unit repurchase program as of December 31, 2025. No units were repurchased during the year ended December 31, 2025. The program has no time limit and we may repurchase units from time to time in the open market or in other privately negotiated transactions. The unit repurchase program authorization does not obligate us to repurchase any dollar amount or number of units, and repurchases may be commenced or suspended from time to time without prior notice. The timing of any future unit repurchases and the ultimate number of units to be purchased will depend on several factors, including business and market conditions, our future financial performance, and other capital priorities. Please read “Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” for more information on the unit repurchase program.

Securitization Facility

In January 2026, we extended the term of our $75.0 million Securitization Facility to January 2027. For additional information on the Securitization Facility please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-Term Debt”.

Cash Flows

Cash provided by operating activities was $651.1 million for 2025 compared to $803.1 million for 2024. The decrease in cash provided by operating activities was primarily due to the decrease in net income adjusted for non-cash items and unfavorable working capital changes primarily related to trade receivables and other miscellaneous changes. These decreases were partially offset by favorable working capital changes primarily related to accounts payable, other receivables, and accrued payroll and related benefits.

Net cash used in investing activities was $331.3 million for 2025 compared to $440.7 million for 2024. The decrease in cash used in investing activities was primarily due to the decrease in capital expenditures and a decrease in oil & gas reserve acquisitions in 2025 as compared to 2024. This decrease was partially offset by increased contributions to equity method investments, changes in accounts payable and accrued liabilities and the purchase of equity securities during 2025.

Net cash used in financing activities was $385.7 million for 2025 compared to $285.3 million for 2024. The increase in cash used in financing activities was primarily attributable to proceeds from the issuance of our 2029 Senior Notes and from an equipment financing in 2024. These increases were partially offset by reduced payments on long-term debt, reduced distributions paid to partners in 2025 and the payment for cash settlement of grants under deferred compensation plans in 2024.

Capital Expenditures

For 2026, we are targeting total capital expenditures between $280 million and $300 million. We project average estimated annual maintenance capital expenditures over the next five years of approximately $7.23 per ton produced.

Other Cash Requirements

We expect to incur significant future cash outflows for scheduled payments on long-term debt, lease obligations, asset retirement obligation costs and workers’ compensation and pneumoconiosis as follows:

(in thousands)

For additional information on our future cash requirements other than capital expenditures, please see “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-Term Debt,” “—Note 11 – Leases,” “—Note 14 – Employee Benefit Plans,” “—Note 15 – Asset Retirement Obligations,” and “—Note 13 – Accrued Workers’ Compensation and Pneumoconiosis Benefits”

In addition to the cash outflows discussed above, we have liabilities totaling $164.9 million expected to be paid in 2026 and $55.6 million in years thereafter. Our liabilities include accounts payable, accrued expenses, contingent consideration and other miscellaneous liabilities which include amounts payable for subsidence and deferred income taxes. We also have contractual commitments of $94.3 million as of December 31, 2025, that we expect to pay during 2026. Please see “Item 8. Financial Statements and Supplementary Data—Note 16 – Commitments and Contingencies.”

Off-Balance-Sheet Arrangements

We use a combination of surety bonds and letters of credit to secure our financial obligations for reclamation, workers’ compensation and other obligations as follows as of December 31, 2025:

(in millions)

Insurance

Effective October 1, 2025, we renewed our property and casualty insurance program through September 30, 2026. Our property insurance was procured from our wholly owned captive insurance company, Wildcat Insurance. Wildcat Insurance charged certain of our subsidiaries for the premiums on this program and in return purchased reinsurance for the program in the standard market. The maximum limit in the commercial property program is $100.0 million per occurrence, excluding a $1.5 million deductible for property damage, a 75- or 90-day waiting period for underground business interruption depending on the mining complex and an additional $25.0 million overall aggregate deductible. We retained a 2.50% participating interest in our current commercial property insurance program. We can make no assurances that we will not experience significant insurance claims in the future that could have a material adverse effect on our business, financial condition, results of operations and ability to purchase property insurance in the future. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, the insurance industry has been subject to efforts by environmental activists to restrict coverages available for fossil-fuel companies.

Debt Obligations

See “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-Term Debt” for a discussion of our debt obligations.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts and disclosures in the consolidated financial statements. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. We discuss these estimates and judgments with the Audit Committee periodically. Actual results may differ from these estimates. We have provided a description of all significant accounting policies in the notes to our consolidated financial statements. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of our consolidated financial statements:

Business Combinations

We account for business acquisitions using the purchase method of accounting. See “Item 8. Financial Statements and Supplementary Data—Note 4 – Acquisitions” for more information on the Skyland and Elk Range Acquisitions. Assets acquired and liabilities assumed are recorded at their estimated fair values at the acquisition date. The excess purchase price over the fair value of net assets acquired, if any, is recorded as goodwill. Given the time it takes to obtain pertinent information to finalize the acquired business’ balance sheet, it may be several quarters before we are able to finalize those initial fair value estimates. Accordingly, it is not uncommon for the initial estimates to be subsequently revised. The results of operations of acquired businesses are included in the consolidated financial statements from the acquisition date.

For the Skyland and Elk Range Acquisitions, we determined a fair value for the acquired mineral interests using an income approach consisting of discounted cash flow models. The assumptions used in the discounted cash flow models included estimated production, projected cash flows, forward oil & gas prices and risk adjusted discount rates.

Oil & Gas Reserve Values

Estimated oil & gas reserves and estimated market prices for oil & gas are a significant part of our depletion calculations, impairment analyses, and other estimates. Following are examples of how these estimates affect financial results:

• an increase (decrease) in estimated proved oil & gas reserves can reduce (increase) our units of production depreciation, depletion and amortization rates; and
• changes in oil & gas reserves and estimated market prices both impact projected future cash flows from our mineral interests. This in turn can impact our periodic impairment analysis.

The process of estimating oil & gas reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, our proved reserves estimates are compared to proved reserves that are audited by independent experts in connection with our required year-end reporting. The data may change substantially over time as a result of numerous factors, including the historical 12 month average price, additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil & gas mineral interests and have an impact on our depreciation, depletion and amortization expense prospectively.

Estimates of future commodity prices utilized in our impairment analyses consider market information including published forward oil & gas prices. The forecasted price information used in our impairment analyses is consistent with that generally used in evaluating third-party operator drilling decisions and our expected acquisition plans, if any. Prices for future periods will impact the production economics underlying oil & gas reserve estimates. In addition, changes in the price of oil & gas also impact certain costs associated with our expected underlying production and future capital costs. The prices of oil & gas are volatile and change from period to period, thus are expected to impact our estimates. Significant unfavorable changes in the estimated future commodity prices could result in an impairment of our oil & gas mineral interests.

Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. We generally provide for these claims through self-insurance programs. Workers’ compensation laws also compensate survivors of workers who suffer employment related deaths. Our liability for traumatic injury claims is the estimated present value of current workers’ compensation benefits, based on our actuary estimates. Our actuarial calculations are based on a blend of actuarial projection methods and numerous assumptions including claim development patterns, mortality, medical costs and interest rates. See “Item 8. Financial Statements and Supplementary Data—Note 13 – Accrued Workers’ Compensation and Pneumoconiosis Benefits” for additional discussion. We had accrued liabilities for workers’ compensation of $49.4 million and $47.9 million for these costs at December 31, 2025 and 2024, respectively. A one-percentage-point reduction in the discount rate would have increased operating expense by approximately $2.1 million for the year ended December 31, 2025. We limit our exposure to traumatic injury claims by purchasing a high deductible insurance policy that starts paying benefits after deductibles for a particular claim year have been met. Our receivables for traumatic injury claims under this policy as of December 31, 2025 and 2024 were $4.1 million and $3.7 million, respectively.

Coal mining companies are subject to FMSHA and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker’s pneumoconiosis, or black lung. We provide for these claims through self-insurance programs. Our pneumoconiosis benefits liability is calculated using the service cost method based on the actuarial present value of the estimated pneumoconiosis benefits obligation. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and discount rates. We had accrued liabilities of $105.0 million and $124.3 million for the pneumoconiosis benefits at December 31, 2025 and 2024, respectively. A one-percentage-point reduction in the discount rate would have increased the expense recognized for the year ended December 31, 2025 by approximately $0.8 million. Under the service cost method used to estimate our pneumoconiosis benefits liability, actuarial gains or losses attributable to changes in actuarial assumptions, such as the discount rate, are amortized over the remaining service period of active miners.

The discount rate for workers’ compensation and pneumoconiosis is derived by applying the Financial Times Stock Exchange Pension Discount Curve to the projected liability payout. Other assumptions, such as claim development patterns, mortality, disability incidence and medical costs, are based on standard actuarial tables adjusted for our actual historical experiences whenever possible. We review all actuarial assumptions periodically for reasonableness and consistency and update such factors when underlying assumptions, such as discount rates, change or when sustained changes in our historical experiences indicate a shift in our trend assumptions are warranted.

Impairment of Long-Lived Assets

In addition to oil & gas reserves discussed above in the Oil & Gas Reserve Values section, we review the carrying value of long-lived assets and certain identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount may not be recoverable based on estimated undiscounted future cash flows. Long-lived assets and certain intangibles are not reviewed for impairment unless an impairment indicator is noted. Several examples of impairment indicators include:

• A significant decrease in the market price of a long-lived asset;
• A significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition;
• A significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset, including an adverse action of assessment by a regulator;
• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
• A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; or
• A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The term more likely that not refers to a level of likelihood that is more than 50 percent.

The above factors are not all inclusive, and management must continually evaluate whether other factors are present that would indicate a long-lived asset may be impaired. If there is an indication that the carrying amount of an asset group may not be recovered, we compare our estimate of undiscounted future cash flows attributable to the asset to the carrying value of the asset group. Individual assets are grouped for impairment review purposes based on the lowest level for which there is identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a by-mine basis. Assumptions about sales, operating margins, capital expenditures and sales prices are based on our budgets, business plans, economic projections, and anticipated future cash flows. If the carrying value of an asset group exceeds the future undiscounted cash flows expected from the asset group, the amount of impairment is measured by the difference between the carrying value and the fair value of the asset group. The fair value of impaired assets is typically determined based on various factors, including cost replacement, the present values of expected future cash flows using a risk adjusted discount rate, the marketability of the assets and the estimated fair value of assets that could be sold or used at other operations. We recorded an asset impairment of $31.1 million in 2024. See “Item 8. Financial Statements and Supplementary Data—Note 9 – Long-Lived Asset Impairments”.

Asset Retirement Obligations

SMCRA and similar state statutes require that mined property be restored in accordance with specified standards and an approved reclamation plan. A liability is recorded for the estimated cost of future mine asset retirement and closing procedures on a present value basis when incurred or acquired and a corresponding amount is capitalized by increasing the carrying amount of the related long-lived asset. Those costs relate to permanently sealing portals at underground mines and to reclaiming the final pits and support surface acreage for both our underground mines and past surface mines. Examples of these types of costs, common to both types of mining, include, but are not limited to, removing or covering refuse piles and settling ponds, water treatment obligations, and dismantling preparation plants, other facilities and roadway infrastructure. Accrued liabilities of $157.6 million and $158.8 million for these costs are recorded at December 31, 2025 and 2024, respectively. See “Item 8. Financial Statements and Supplementary Data—Note 15 – Asset Retirement Obligations” for additional information. The liability for asset retirement and closing procedures is sensitive to changes in cost estimates, estimated mine lives and timing of post-mine reclamation activities. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted, risk-free interest rate.

Accounting for asset retirement obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. Depreciation is generally determined on a units-of-production basis and accretion is generally recognized over the life of the producing assets.

On at least an annual basis, we review our entire asset retirement obligation liability and make necessary adjustments for permit changes approved by state authorities, changes in the timing of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Adjustments to the liability associated with these assumptions resulted in a decrease of $4.2 million for the year ended December 31, 2025. Adjustments to the liability associated with these assumptions resulted in an increase of $5.6 million for the year ended December 31, 2024.

While the precise amount of these future costs cannot be determined with certainty, we have estimated the costs and timing of future asset retirement obligations escalated for inflation, then discounted and recorded at the present value of those estimates. Discounting resulted in reducing the accrual for asset retirement obligations by $112.3 million and $120.1 million at December 31, 2025 and 2024, respectively. We estimate that the aggregate undiscounted cost of final mine closure is approximately $269.9 million and $278.9 million at December 31, 2025 and 2024, respectively. If our assumptions differ from actual experiences, or if changes in the regulatory environment occur, our actual cash expenditures and costs that we incur could be materially different than currently estimated.

Related–Party Transactions

See “Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions” and “Item 13. Certain Relationship and Related Transactions, and Director Independence” for a discussion of our related-party transactions.

New Accounting Standards

See “Item 8. Financial Statements and Supplementary Data—Note 2 – Summary of Significant Accounting Policies” for a discussion of new accounting standards.

Commodity Price Risk

We have significant long-term sales contracts as evidenced by approximately 84.6% of our sales tonnage being sold under long-term sales contracts in 2025. Many of the long-term sales contracts are subject to price adjustment provisions, which periodically permit an increase or decrease in the contract price, typically to reflect changes in specified indices or changes in production costs resulting from regulatory changes, or both. For additional discussion of coal supply agreements, please see “Item 1. Business—Coal Marketing and Sales” and “Item 8. Financial Statements and Supplementary Data—Note 20 – Concentration of Credit Risk and Major Customers.”

Our results of operations are highly dependent upon the prices we receive for our coal, oil and natural gas. Regarding coal, the short-term sales contracts favored by some of our coal customers leave us more exposed to risks of declining coal price periods. Also, a significant decline in oil & gas prices would have a significant impact on our oil & gas royalty revenues.

We have exposure to coal and oil & gas sales prices and price risk for supplies that are used directly or indirectly in the normal course of coal and oil & gas production such as electricity, steel and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. Historically, we have not utilized any commodity price-hedges or other derivatives related to either our sales price or supply cost risks but may do so in the future.

Credit Risk

In 2025, approximately 89.2% of our tons sold were purchased by U.S. electric utilities and 8.6% were sold into the international markets through brokered transactions. Therefore, our credit risk is primarily with domestic electric power generators and reputable global brokerage firms. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable. When deemed appropriate by our credit management department, we will take steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps may include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay. Such credit risks from customers may impact the borrowing capacity of our Securitization Facility. See “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-Term Debt” for more information on our Securitization Facility.

Exchange Rate Risk

The majority of our transactions are denominated in United States dollars, and as a result, we do not have material exposure to currency exchange-rate risks. However, because we periodically sell our coal internationally in United States dollars, general economic conditions in foreign markets and changes in foreign currency exchange rates may provide our foreign competitors with a competitive advantage. If our competitors’ currencies decline against the United States dollar or against foreign purchasers’ local currencies, those competitors may be able to offer lower prices for coal to these purchasers. Furthermore, if the currencies of overseas purchasers were to significantly decline in value in comparison to the United States dollar, those purchasers may seek decreased prices for the coal we sell to them. Consequently, currency fluctuations could adversely affect the competitiveness of our coal in international markets.

Interest Rate Risk

Borrowings under the Revolving Credit Facility, Term Loan and Securitization Facility are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates and we have not utilized interest rate derivative instruments related to our outstanding debt. We had $31.6 million in borrowings under Term Loan at December 31, 2025. We did not have any outstanding borrowings on either the Revolving Credit Facility or the Securitization Facility at December 31, 2025. A one percentage point increase in the interest rates related to the Term Loan would result in an annualized increase in interest expense of $0.3 million, based on borrowing levels at December 31, 2025. With respect to our fixed-rate borrowings, we had $400.0 million in borrowings under our 2029 Senior Notes and $31.8 million in borrowings under our equipment financings at December 31, 2025. A one percentage point increase in interest rates would result in a decrease of approximately $13.3 million in the estimated fair value of these borrowings.

The table below provides information about our market sensitive financial instruments and constitutes a “forward-looking statement.” The fair values of long-term debt are estimated using discounted cash flow analyses, based on our incremental borrowing rates for similar types of borrowing arrangements as of December 31, 2025 and 2024.

The carrying amounts and fair values of financial instruments are as follows:

(dollars in thousands)

(1) Interest rate of variable rate debt equal to the rate effective at December 31, 2025 and 2024, held constant for the remaining term of the outstanding borrowing.

Disclosure Controls and Procedures. We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow for timely decisions regarding required disclosures. As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the CEO and CFO, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act) as of December 31, 2025. Based on this evaluation, the CEO and CFO concluded that these controls and procedures are effective as of December 31, 2025.

Our management, including the CEO and CFO, does not expect that our disclosure controls or our internal controls over financial reporting will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the ARLP Partnership have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that simple errors or mistakes can occur. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based, in part, upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our disclosure controls and internal controls and make modifications as necessary; our intent in this regard is that the disclosure controls and the internal controls will be maintained as systems change and conditions warrant.

Management’s Annual Report on Internal Control over Financial Reporting. Management of the ARLP Partnership is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Exchange Act. The ARLP Partnership’s internal control over financial reporting is designed to provide reasonable assurance to our management and Board of Directors of our general partner regarding the preparation and fair presentation of published financial statements. Our controls are designed to provide reasonable assurance that the ARLP Partnership’s assets are protected from unauthorized use and that transactions are executed in accordance with established authorizations and properly recorded. The internal controls are supported by written policies and are complemented by a staff of competent business process owners and an internal auditor supported by competent and qualified external resources used to assist in testing the operating effectiveness of the ARLP Partnership’s internal control over financial reporting. Management concluded that the design and operations of our internal controls over financial reporting at December 31, 2025 are effective and provide reasonable assurance the books and records accurately reflect the transactions of the ARLP Partnership.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria set forth by COSO in Internal Control—Integrated Framework (2013). Based on its assessment, management concluded that, as of December 31, 2025, the ARLP Partnership’s internal control over financial reporting was effective based on those criteria, and management believes that we have no material internal control weaknesses in our financial reporting process.

Grant Thornton LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2025, as stated in their report that is included herein.

Changes in Internal Controls Over Financial Reporting. There have not been any changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) or Rule 15d-15(f) of the Exchange Act) in the three months ended December 31, 2025 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Alliance Resource Management GP, LLC

and Unitholders of Alliance Resource Partners, L.P.

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Alliance Resource Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2025, based on criteria established in the 2013 Internal Control— Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2025, and our report dated February 26, 2026 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 26, 2026