ARLP 10-K & 10-Q changes, risk factors and insider trading

In 2024,2025, we derived more than 10% of our total revenues from each of American Electric Power Company Inc., Louisville Gas and Electric Company,Company and TennesseeAmerican ValleyElectric Authority.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.

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. ForWe example,have in 2021,the wepast discoveredbeen, thatand certainmay ofin ourthe computerfuture systems werebe, subject to a cyber incident,incidents, althoughalong it did not materially impactwith our business,third-party financialvendors, position or results of operations. Following the incident, we took what we believed to be appropriate steps in response, including providing individual notifications, implementing multi-factor authenticationcontractors and other security enhancements. Cybersecurity attacks are increasingly dynamic and continuously evolving, encompassing threats such as malicious software, credential stuffing, surveillance, phishing, social engineering, the use of deepfakes (highly realistic synthetic media generated by artificial intelligence), unauthorized data access attempts, and other forms of electronic security breaches.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.

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,disease or any other public health crisis, such as SARS, H1N1/09 flu, avian flu, Ebola, E. Coli., measles and COVID-19,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.

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 is sold 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.

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, theseveral European Union, Canada, Mexico, and Chinacountries 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.

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. Globally, various governments have banned imports from Russia including commodities such as oil & gasshipping and coal.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.

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. CompetitionOur primary competition is from natural gas-fired plants that are relatively more efficient, less expensive to construct,efficient and less difficult to permit than coal-fired plants has the most potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.plants.

Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal, although the short-term future is uncertain as policy changes develop and are implemented by the Trump Administration.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 CSAPR and MATS, have in the past led to the premature 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.

Increased attention to climate change risk has also resulted in a recent trend of 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.

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.

Unexpected increasesIncreases 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 TrumpU.S. Administrationgovernment recentlyimposed announceda plans25% tariff on steel imports, which was increased to implement50% oron increaseJune tariffs,4, 2025, and on FebruaryApril 10,2, confirmed2025, the extensionU.S. ofgovernment 25announced percenta import10% tariff on product imports from almost all foreign countries and individualized higher tariffs on steelcertain globally,other whichcountries. couldThe 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 anretaliatory increase of $100 to $150 per short ton according to an analysis from Citi Bank, with such tariffs going into effectmeasures on MarchU.S. 12.goods. While the ultimate impact of thisthese tarifftariffs 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.

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 CSAPR and MATS, have led to the premature 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.”

The industries we participate in—coal mining and the third-party operations related to our oil & gas productionmineral interests—are subject to numerous federal, state, and local laws and regulations. Although we cannot predict what actions the Trump Administration may take with respect to regulation of those industries, theThe 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,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.

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. Although we cannot predict what actions the Trump Administration may take with respect to regulation of the coal mining industry, theThe 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.”

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 thefuture Trumpfederal Administrationor state regulators may take with respect to environmental regulation in the short term, we believe the trend ofregulation, more expansive and stricter environmental legislation and regulations willcould continue.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.

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 Federal Safe Drinking Water ActSDWA 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.

ThereIn hasthe beenpast, increasingthere was increased public controversyconcern regarding hydraulic fracturing aboutaround 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 have beenwere 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.

In addition, a number of lawsuits have been filed in other states, including in Oklahoma,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 seekingconsidering to imposeadopting 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. InFor September 2021,example, the TRRCOklahoma issuedCorporation aCommission notice(“OCC”) has released guidance to operators in the MidlandSCOOP areaand STACK areas for management of certain seismic activity that may be related to reducehydraulic saltwaterfracturing disposalactivities, and has at times ordered well activitiesclosures andin provide certain dataresponse to theseismic TRRC.activities. Subsequently,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.

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. MostMany 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. Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.

Governmental, scientific, and public concern over climate change has also resulted in increased political risks, including certain climate-related pledges made by certain candidates now in political office. In January 2021, President Biden issued an executive order that committed to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Although the Trump Administration has already announced its disagreement with various of these initiatives, we cannot predict what action the Trump Administration may take regarding these commitments or the timing of such action. Further, 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.”

Apart from governmental regulation, thereThere 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 alsohave havein 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.

Separately,In theaddition, SECsome states (such as California) have adopted a rule in March 2024 that establishes a framework for the reporting of climate risks, targets and metrics. The rule is being challenged in the U.S. Court of Appeals for the Eighth Circuit and the implementation of the rule has been voluntarily stayed by the SEC pending the outcome of the legal challenge. Moreover, on February 11, 2025, SEC Acting Chairman Mark T. Uyeda requested that the U.S. Court of Appeals for the Eighth Circuit not schedule argument in the case while the SEC reconsiders the final rule. While the Trump Administration may seek to repeal or otherwiseare modifyconsidering the rule, we cannot predict whether or how such action would occur or its timing. Relatedly, California has enacted newadopting laws requiring additionalthe disclosure with respect toof certain climate-related risks and GHG emission reduction claims,claims. someLawsuits have been filed challenging the implementation of whichthese arelaws, alreadybut subjectwe tocannot legal challenge. Whilepredict the outcome of suchthese challenges is uncertainsuits at this time, the judge in the case has declined to grant a temporary injunction of the laws while the litigation moves forward.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.

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.

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, 2024,2025, our total of such bonds was $251.6$237.8 million. The amount of surety bonding we are required to maintain may be increased by the governmental agencies holding the bond. For example, federal and state regulators are continuing to make financial assurance requirements more stringent and costly with respect to self-insured coal workers’ pneumoconiosis, mine closure and reclamation security amounts.

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 realizerealize, 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.

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. Further, while unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualified business income,” this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025, unless extended by Congress.

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 strategickey producing regions across the United States. Our strategycore is to provide our customers with reliable, baseload fuel for electricity generation to meet load expectations. The primary focus of our businessobjective is to maximize the value of our existing mineral assets,asset base—both inthrough thecoal production of coal from our mining assetsoperations and through the leasing and development of our coal and oil & gas mineral ownership.interests. InOur addition,strategy we continueis to positionprovide ourselvesreliable, asbaseload a reliable energy providerfuel for theelectricity futuregenerating ascustomers wewhile pursue opportunities that supportpositioning the Partnership for long-term growth andthrough developmentinvestments ofin energy and related infrastructure. We intend to pursue strategic investments that leverageLeveraging our core competencies and relationships with electric utilities, industrial customers, and federalgovernment andpartners, statewe governments.intend to pursue strategic opportunities that complement our operational strengths. We believe that our diverse and rich resource baseportfolio and strategictargeted investments will allow us to continue to create long-term value for our unitholders.

We are the second largest coal producer in the eastern United States withand as of December 31, 2025, we operated seven operating underground mining complexes near many of the major eastern utility generating plants and on major coal hauling railroads inacross Illinois, Indiana, Kentucky, Maryland, Pennsylvania, and West Virginia,Virginia as well asand a coal-loading terminal in Indiana. Two of our mines also have loading facilities located on the Ohio River.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.

InWe additionalso tohold ourcoal miningmineral operations,reserves Allianceand Resourceresources Propertiesin ownsIllinois, orIndiana, leasesKentucky, substantiallyPennsylvania and West Virginia. Substantially all of our coal mineral resources and thea majority of our coal mineral reserves inare theowned Illinoisor andleased Appalachiaby BasinsAlliance thatResource Properties, which are (a) leased or subleased to our internal mining complexes or (b) near ourother 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.

Total revenues decreased 4.6%10.4% to $2.19 billion in 2025 compared to $2.45 billion in 2024 compared to $2.57 billion in 2023 primarily due to lower coal sales pricing and transportation revenues, partially offset by higher other revenues.

Segment Adjusted EBITDA Expense increaseddecreased 8.9%9.1% to $1.53$1.39 billion in 2025 primarily related to our coal operations which increaseddecreased 8.0%9.3% to $1.50$1.36 billion, as a result of higherlower per ton costs,costs partially offset by lower coaland sales volumes. Segment Adjusted EBITDA Expense per ton sold for our coal operations increaseddecreased 11.6%8.4% to $41.29 per ton sold in 2025 compared to $45.07 per ton sold in 2024 compared to $40.38 per ton in 2023,2024, primarily due to certainan increased sales mix of tons from lower cost increases,operations, whichhigher arerecoveries discussedfrom belowseveral bymines categoryand fewer longwall move days at our Hamilton operation as well as the following per ton cost decreases:

Depreciation, depletion and amortization expense increased to $285.4$299.4 million forin 20242025 compared to $268.0$285.4 million forin 20232024 primarily due to increased sales of higher depreciation cost tons at our Tunnel Ridge mine as a result of lowerrecent productioncapital volumesinvestments at theour mineRiver inView 2024.and Tunnel Ridge mines.

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.Impairments” for more information.

Net income attributable to ARLP for 20242025 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, compared to $630.1 million, or $4.81 per basic and diluted limited partner unit, for 20232024 as a result of lower revenues, increased operating expensesrevenues and a $31.1 million non-cash impairment charge, partially offset by a $22.4 million increasedecrease in the fair value of our digital assets.assets in 2025, partially offset by reduced operating expenses and increased investment income.

Our 2025 Segment Adjusted EBITDA decreased $14.6 million, or 1.8%, to $781.9 million from 2024 Segment Adjusted EBITDA decreased $215.7 million, or 21.3%, toof $796.5 million from 2023 Segment Adjusted EBITDA of $1.01 billion.million.

Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased 7.8%3.6% to $456.7 million in 2025 from $473.9 million in 2024 from $514.1 million in 2023.2024. The decrease of $40.2$17.2 million was primarily attributable to increasedlower operatingcoal expenses,sales prices, partially offset by higher coal sales, which increased 2.5% to $1.40 billion in 2024 from $1.36 billion in 2023. The increase in coal sales primarilyvolumes reflectsand higherlower coaloperating expenses. Coal sales price realizations of $56.44 per ton solddecreased inby 20247.7% compared to $55.212024 peras tona result of lower domestic price realizations across the region. Sales volumes increased by 4.0% compared to 2024 due primarily to increased tons sold infrom 2023our dueHamilton toand improvedRiver domesticView pricing.mines. Segment Adjusted EBITDA Expense increaseddecreased 8.8%4.5% compared to $937.1 million in 2024 fromdue $861.3to million in 2023 as a result of higherlower operating expenses per ton. Segment Adjusted EBITDA Expense per ton increasedin 2025 decreased by 8.5%8.2% compared to 20232024 resultingdue fromprimarily reducedto increased production and higherimproved labor costsrecoveries at severalour minesRiver inView theand region.Hamilton mines, higher volumes at our Warrior operation, and reduced longwall move days at Hamilton.

Appalachia Coal Operations – Segment Adjusted EBITDA decreased 50.4%18.5% to $133.7 million in 2025 from $164.1 million for 2024 from $330.7 million in 2023.2024. The decrease of $166.6$30.4 million was primarily attributable to lower coal sales, which decreased 15.7%17.2% to $590.2 million in 2025 from $712.7 million in 20242024, frompartially $845.3offset millionby in 2023, and higherlower operating expenses. The decrease in coal sales reflects lower coal sales volumes and prices.price Coalrealizations. salesTons volumessold decreased by 12.2%15.6% in 2025 compared to 20232024 primarily due to reduced production at our Tunnel Ridge operation as a result of lower demandproduction andlevels at Tunnel Ridge due to challenging mining conditions.conditions and the recent transition to a new longwall district. Average coal sales pricesprice per ton decreased by 4.0%1.8% compared to 20232024 asprimarily adue resultto ofreduced domestic pricing from our Tunnel Ridge and MC Mining operations and lower export price realizations from ourMC MettikiMining and Mettiki, partially offset by a greater mix of higher priced sales tons from the MC Mining operations.and Mettiki operations during 2025. Segment Adjusted EBITDA Expense increaseddecreased 6.8%16.7% to $459.4 million in 2025 from $551.7 million in 2024 from $516.5 million in 2023 due to higherreduced volumes and lower per ton operating expenses per ton, partially offset by lower sales volumes.expenses. Segment Adjusted EBITDA Expense per ton for 20242025 increaseddecreased by 21.7%1.3% compared to 20232024 due to reduced production as a result of challenging mining conditions that loweredhigher recoveries andat increasedthe costs related to labor, roof control, outside expenses,Mettiki and maintenanceMC duringMining 2024.operations.

Oil & Gas Royalties – Segment Adjusted EBITDA decreasedincreased slightly to $117.5 million for 2025 from $117.0 million for 2024 from $121.5 million in 2023.2024. The decrease of $4.5 millionincrease 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 8.4%7.0% to $40.65$37.79 per BOE, partially offset by increased volumes in 2024, which increased by 9.6%, and increased expenses.BOE. Higher BOE volumes during 20242025 resulted from increased drilling and completion activities on our properties and additional volumes from oil & gas mineral interest acquisitions.

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.”

In January 2025,2026, we extended the term of theour $75.0 million Securitization Facility to January 2026 and decreased the borrowing availability under the facility to $75.0 million.2027. For additional information on the Securitization Facility please read “Item 8. Financial Statements and Supplementary Data—Note 12 – Long-Term Debt”.

Cash provided by operating activities was $651.1 million for 2025 compared to $803.1 million for 2024 compared to $824.2 million for 2023.2024. 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 accountstrade payable.receivables and other miscellaneous changes. These decreases were partially offset by favorable working capital changes primarily related to tradeaccounts payable, other receivables, inventories,and accrued payroll and miscellaneousrelated other changes.benefits.

Net cash used in financing activities was $385.7 million for 2025 compared to $285.3 million for 2024 compared to $507.1 million for 2023.2024. The decreaseincrease in cash used in financing activities was primarily attributable to proceeds from the issuance of our 8.625%2029 Senior Notes due 2029, borrowings under our February 2024 Equipment Financing and thefrom purchasean ofequipment units under our repurchase programfinancing in 2023.2024. These decreasesincreases were partially offset by thereduced redemptionpayments ofon ourlong-term remainingdebt, 7.5%reduced Seniordistributions Notespaid dueto partners in 2025 and the payment for cash settlement of grants under our deferred compensation plans.plans in 2024.

Other Cash Requirements

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 Belvedere, JaseSkyland and SkylandElk 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 Belvedere, JaseSkyland and SkylandElk 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.

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.

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. Adjustments to the liability associated with these assumptions resulted in a decrease of $1.5 million for the year ended December 31, 2023.

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 $120.1$112.3 million and $116.2$120.1 million at December 31, 20242025 and 2023.2024, respectively. We estimate that the aggregate undiscounted cost of final mine closure is approximately $278.9$269.9 million and $266.6$278.9 million at December 31, 20242025 and 2023,2024, 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.

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.

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 related technologies 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 MarchJune 31,30, 2026, 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 70,500 net royalty acres including approximately 4,000 net royalty acres attributable to our equity interest in AllDale Minerals III, LP (“AllDale III”), inacross premier oilbasins &and gasresource producing regionsplays in the United States,States primarilyincluding the Permian, Anadarko, Bakken, and Willistonafter Basins.the AllDale III & IV Acquisition on July 1, 2026, Haynesville. 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. Please read “Item 1. Financial Statements (Unaudited) – Note 3 – Variable Interest Entities, Note 4 – Acquisitions and Note 17. – Related Party Transactions” for more information on the AllDale III & IV Acquisition.

InDuring Januarythe andsix Marchmonths ended June 30, 2026, we acquired an aggregate 574881 oil and& gas net royalty acres through a series of transactions in the Permian Basin for $14.5an aggregate cash purchase price of $22.0 million inwhich cash.was funded with cash on hand. The interests include royalty interests in both developed properties and undeveloped properties. Please see “Item 1. Financial Statements (Unaudited) – Note 4 – Acquisitions” for additional information.

In January 2026, we announced our decision to cease longwall production at our Mettiki mining complex due to a series of planned and unplanned outages at a key customer’s plant. WeWhile limited coal production is ongoing with continuous mining units, we continue to evaluate options concerning the mine’s future. Please see “Item 1. Financial Statements (Unaudited) – Note 8 – Long-Lived Asset Impairment” for additional information.

Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025

Total revenues for the three months ended MarchJune 31,30, 2026 (“2026 Quarter”) decreasedincreased 4.5%0.7% to $516.0$551.6 million compared to $540.5$547.5 million for the three months ended MarchJune 31,30, 2025 (“2025 Quarter”) primarilyas duea toresult lower coal sales pricing, partially offset byof record oil & gas royaltiesroyalty revenues, increased coal sales volumes and higher other revenues, partially offset by lower coal sales volumes.prices per ton.

Segment Adjusted EBITDA Expense decreased 3.8% to $340.0 million for the 2026 Quarter compared to $353.5 million for the 2025 Quarter primarily due to decreased expenses at our coal operations. Segment Adjusted EBITDA Expense for our coal operations decreased 2.0%4.3% to $325.5$331.0 million due to lower per ton costs, partially offset by higher coal sales volumes. Segment Adjusted EBITDA Expense per ton sold for our coal operations decreased 3.1%6.3% to $41.42$38.68 per ton sold in the 2026 Quarter compared to $42.75$41.27 per ton in the 2025 Quarter, primarily due to increased production at several mines as well as the following per ton cost decreases:

Equity method investment income was $4.3$9.5 million in the 2026 Quarter compared to a loss of $2.0$1.5 million in the 2025 Quarter. The increasechange was primarily due to an increase in the value of our share of the net assets of theGavin companiesGeneration inand whichNGP weET hold interests.IV.

The fair value adjustment on our digital assets decreased by $6.1$19.2 million for the 2026 Quarter compared to the 2025 Quarter reflecting the movement in the price of bitcoin.

Net income attributable to ARLP for the 2026 Quarter decreasedincreased 87.7%33.9% to $9.1$79.6 million, or $0.07$0.61 per basic and diluted limited partner unit, compared to $74.0$59.4 million, or $0.57$0.46 per basic and diluted limited partner unit for the 2025 Quarter, primarily as a result of lower coal sales, higher depreciation,total arevenues decreaseand equity method investment income as well as the impact of the impairment loss on investments in the fair value of our digital assets and non-cash asset impairment charges in the 20262025 Quarter.

Our 2026 Quarter Segment Adjusted EBITDA decreasedincreased 0.8%16.0% to $179.0$211.5 million from the 2025 Quarter Segment Adjusted EBITDA of $180.5$182.3 million.

Illinois Basin Coal Operations – Segment Adjusted EBITDA decreased 21.4%8.8% to $99.2$104.2 million in the 2026 Quarter from $126.2$114.2 million in the 2025 Quarter. The decrease of $27.0$10.0 million was primarily attributable to lower average coal sales pricesvolumes. and higher operating expenses. Coal sales price per tonTons sold decreased by 7.4%4.5% compared to the 2025 Quarter due primarily to decreased sales volumes from our Hamilton mine as a result of a planned extended longwall move during the expiration2026 ofQuarter, higherpartially pricedoffset legacyby contracts.a strong sales performance and productivity at our River View complex. Segment Adjusted EBITDA Expense increaseddecreased to $213.6$229.2 million in the 2026 Quarter from $210.0$231.2 million in the 2025 Quarter, primarily as a result of reduced volumes, partially offset by increased operating expenses per ton. Segment Adjusted EBITDA Expense per ton increased by 1.3%3.7% compared to the 2025 Quarter due primarily to the planned extended longwall move at our Hamilton mine during the 2026 Quarter.

Appalachia Coal Operations – Segment Adjusted EBITDA increased 67.9%67.2% to $26.2$49.2 million for the 2026 Quarter from $15.6$29.4 million in the 2025 Quarter. The increase of $10.6$19.8 million was primarily attributable to reduced operating expenses and higher other revenues, partially offset by lower coal sales. The decrease in coal sales primarily reflects lower coal sales prices, which decreased by 4.8%22.9% compared to the 2025 Quarter primarily due to an increased sales mix of lower priced Tunnel Ridge sales volumes in the 2026 Quarter and reduced domestic sales price per ton.ton at Mettiki. Partially offsetting lower coal sales prices, coal sales volumes increased 3.6%27.6% compared to the 2025 Quarter primarily as a result of fewerincreased production days in the 2025 Quarter at our Tunnel Ridge mine due to aimproved longwallrecoveries move.and higher productivity. Other revenues increased by $3.2$10.6 million in the 2026 Quarter reflecting higher miscellaneous revenue activities. Segment Adjusted EBITDA Expense decreased 7.6%10.2% to $111.5$101.3 million in the 2026 Quarter from $120.6$112.8 million in the 2025 Quarter due primarily to lower per ton expenses, partially offset by increased sales volumes. Segment Adjusted EBITDA Expense per ton for the 2026 Quarter decreased by 10.8%29.7% compared to the 2025 Quarter as a result of increased production at our Tunnel Ridge operation primarily reflecting fewer production days due to a longwall move in the 2025 Quarter.operation.

Oil & Gas Royalties – Segment Adjusted EBITDA increased to $34.6a record $38.0 million in the 2026 Quarter compared to $29.9 million in the 2025 Quarter primarily due to recordhigher oilaverage sales prices, which increased 22.7%, partially offset by higher expenses. Oil & gas royalty volumes, whichvolumes increased 16.1%6.4% compared to the 2025 Quarter as a result of increased drilling and completion activities on our interestsacreage andcombined acquisitions ofwith additional volumes from oil & gas mineral interests.interests acquired.

Coal Royalties – Segment Adjusted EBITDA increased to $12.3$13.0 million in the 2026 Quarter compared to $9.4$11.8 million in the 2025 Quarter due to higher royalty tons sold, primarily from Tunnel Ridge,Ridge and River View, partially offset by lowerhigher average royalty rates per ton received from the Partnership's mining subsidiaries.expenses.

We have $80.6 million remaining authorized under our unit repurchase program as of MarchJune 31,30, 2026. No units were repurchased during the threesix months ended MarchJune 31,30, 2026. 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. 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 “Part II - Item 2. Unregistered Sales of Equity Securities and Use of Proceeds” of this Quarterly Report on Form 10-Q for more information on the unit repurchase program.

Cash provided by operating activities was $105.5$258.5 million for the 2026 QuarterPeriod compared to $145.7$297.4 million for the 2025 Quarter.Period. 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, inventories and accountsother payable.receivables. These decreases were partially offset by favorable working capital changes primarily related to accrued payrollinventories and relatedother benefitsmiscellaneous changes compared to the 2025 Quarter.Period.

Net cash used in investing activities was $107.8$181.2 million for the 2026 QuarterPeriod compared to $93.1$168.3 million for the 2025 Quarter.Period. The increase in cash used in investing activities was primarily due to increased oil & gas reserve acquisitions and capital expenditures in the 2026 QuarterPeriod as compared to the 2025 Quarter.Period. This increase was partially offset by changesdecrease in accounts payable and accrued liabilities and reduced capital expenditure during the 2026 Quarter.Period.

Net cash used in financing activities was $40.0$37.4 million for the 2026 QuarterPeriod compared to $108.3$211.2 million for the 2025 Quarter.Period. The decrease in cash used in financing activities was primarily attributable to increased borrowings under both the revolving credit facility and Securitization Facility and other long-term debt arrangements and reduced distributions paid to partners in the 2026 QuarterPeriod as compared to the 2025 Quarter.Period. These decreases were partially offset by increased payments on the revolving credit facility and Securitization Facility in the 2026 Quarter.Period compared to the 2025 Period.

Management anticipates having sufficient cash flow to meet 2026 cash requirements, including capital expenditures, acquisitions of oil & gas mineral interests, scheduled payments on long-term debt, lease obligations, asset retirement obligation costs and workers’ compensation and pneumoconiosis costs, with our MarchJune 31,30, 2026 cash and cash equivalents of $28.9$111.2 million, cash flows from operations, or borrowings under our revolving credit facility and Securitization Facility, if necessary. We project average estimated annual maintenance capital expenditures over the next five years of approximately $7.23 per ton produced. Our anticipated total capital expenditures, including maintenance capital expenditures, for 2026 are estimated in the range of $280.0 million to $300.0 million. We will continue to have significant cash requirements over the long term, which may require us to incur debt or seek additional equity capital. The availability and cost of additional capital will depend upon prevailing market conditions, the market price of our common units and several other factors over which we have limited control, as well as our financial condition and results of operations.

See “Item 1. Financial Statements (Unaudited)— – Note 10 – Long-Term Debt” of this Quarterly Report on Form 10-Q for a discussion of our long-term debt obligations.

We also have an agreement with a bank to provide additional letters of credit in the amount of $5.0 million to maintain surety bonds to secure certain asset retirement obligations and our obligations for workers’ compensation benefits. On MarchJune 31,30, 2026, we had $5.0 million in letters of credit outstanding under this agreement.

We have related-party transactions and activities with Mr. Craft, MGP and their respective affiliates as well as other related parties. These related-party transactions and activities relate principally to (1) an installment purchase obligation with The Joseph W. Craft III Foundation resulting from our January 2026 acquisition of ownership interests in certain coal reserves and associated surface rights that we had previously been leasing from The Joseph W. Craft III Foundation and The Kathleen S. Craft Foundation, (2) the use of aircraft andaircraft, (3) a master supply and services agreementagreements for the purchase and servicing of electronic components and other parts used in mining equipment.equipment, and (4) contribution and exchange agreements entered with related parties of Mr. Craft in connection with the AllDale III & IV Acquisition on July 1, 2026. We also have related-party transactions with (a) WKY CoalPlay LLC, a company owned by entities related to Mr. Craft, regarding three mineral leases, and (b) entities in which we hold equity investments. For more information, please read “Item 1. Financial Statements (Unaudited)— – Note 9 – Investments, Note 10 – Long-Term Debt and Note 17 – Related-Party Transactions” of this Quarterly Report on Form 10-Q. Please read our Annual Report on Form 10-K for the year ended December 31, 2025, “Item 8. Financial Statements and Supplementary Data—Note 21 – Related-Party Transactions” for additional information concerning related-party transactions.