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

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. In addition to the other information contained in this Form 10-K, the following risk factors related to our industry, business, operations, financial positionposition, and performance should be considered in evaluating our Company. If any of the following risks were to occur, it could negatively impact our Company and cause an investment in our securities to decline in value.

Prices for natural gas and NGLs are volatile and can fluctuate widely based upon a number of factors beyond our control, including supply and demand for our products. An extended decline in the prices CNX receives for our natural gas and NGLs will adversely affect our business, operating results, financial conditioncondition, and cash flows.

Our financial results are significantly affected by the prices we receive for our natural gas and NGLs (which includes oil and condensate). Natural gas and NGL pricing is very volatile and can fluctuate widely based upon supply from energy producers relative to demand for these products and other factors beyond our control. In particular, the U.S. natural gas industry faces oversupply due to the success of domestic Shale development, associated natural gas produced by oil producers, other North American Shale gas plays, and an outpacing of demand that impact domestic pricing. This oversupply of natural gas, beginning in 2012, has resulted in depressed domestic prices for most of that period. Development has continued in these plays, despite these lower gas prices, as producers continue to become more efficient. Evidence of volatility was present during 2022 and 2023 as natural gas prices spiked in the first half of 2022 due to lower domestic production, lower storage levels, and increased LNG export demand, but thereafter retreated to the depressed prices that we have witnessed over the past ten years. CNX expects continued volatility of natural gas prices in the future.

Our producing properties are geographically concentrated in the Appalachian Basin, which exacerbates the impact of regional supply and demand factors on our business, including the pricing of our natural gas. Not all of the natural gas produced in this region can be consumed by regional demand and must, therefore, be exported to other regions, which causes natural gas produced and sold locally to be priced at a discount to many other market hubs, such as the benchmark Henry Hub price. This discount, or negative basis, to the Henry Hub price is forecasted to continue in future years for all Appalachian Basin producers. While new interstate pipeline projects could reduce this discount, it could increase further if production in the basin continues to grow and projects to move natural gas out of the basin are cancelled, delayeddelayed, or denied for any reason, such as permitting and regulatory issues or environmental lawsuits.

Our development plans and operations also include some activity in areas of Shale formations that may also contain NGLs. The price for NGLs is also volatile for reasons similar to those described above for natural gas. Although the Company is able to hedge natural gas benchmarks and local basis differentials, it maintains only a small hedge position in its relatively minor quantities of NGLs. In addition, similar to natural gas, increased drilling activity by third parties in formations containing NGLs may lead to a decline in the price CNX receives for our NGLs. International demand and storage levels also affect NGL prices. Further, an oversupply of NGLs in the local markets where CNX operates requires excess NGLs to be transported out of our region and into the broader market, including international exports. NGLs are transported by a variety of methods, including pipeline, rail, truck, and truck.barge. Any disruption in those means of transportation could have a further detrimental impact on the price CNX receives for our NGLs. Our results of operations may be adversely affected by a depressed level of, or downward fluctuations in the price for NGLs.

•changes in the consumption pattern of industrial consumers, electricity generatorsgenerators, and residential users of electricity and natural gas;

•the costs, availabilityavailability, and capacity of transportation infrastructure;

If natural gas prices decrease or operational efforts are unsuccessful, CNX may be required to record write-downs of the quantity and value of our proved natural gas properties. Additionally, changes in assumptions impacting management’s estimates of future financial results as well as other assumptions related to the Company's stock price, weighted-average cost of capital, terminal growth ratesrates, and industry multiples, could cause goodwill and other intangible assets CNX holds to become impaired and result in material non-cash charges to earnings.

Lower natural gas prices or wells that produce less than expected quantities of natural gas,gas have in the past and may in the future reduce the amount of natural gas that CNX can produce economically. This results in our having to make substantial downward adjustments to our estimated proved reserves. When this occurs, or when our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. CNX is required to perform impairment tests on our assets at least annually or whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable, indicate a potential impairment in the carrying value of goodwill or intangible assets as defined by GAAP, or whenever development plans change with respect to those assets. In the past CNX has had to record an impairment charge related to certain assets and CNX may incur impairment charges in the future, which could have an adverse effect on our results of operations in the period taken. There were no indicators of impairment for the years ended December 31, 2024,2025, 20232024 and 2022.2023.

The natural gas, exploration, productionproduction, and midstream industries are intensely competitive with companies from various regions of the United States, and increasingly face competition in international markets. The industry has been experiencing increased competitive pressures as a result of both consolidation within the exploration and production space, along with the continued competition from stand-alone midstream companies. Midstream, transmissiontransmission, and processing consolidation in the industry could lead to a less competitive environment for CNX to find partners for projects needed to support development, which could increase costs. Many of the companies with which CNX competes are larger and have more resources to deploy, and if CNX were unable to compete, our company, our operating results, financial positionposition, or other parts of the business may be adversely affected. In addition, CNX competes with larger companies to acquire new natural gas properties for future exploration, limiting our ability to replace the natural gas CNX produces or to grow our production. There is also increased competition within the industry as a result of oil-focused drilling, where natural gas is produced as an ancillary byproductbyproduct, and this inelastic supply may bedepress soldmarket at prices below market.prices. Some of such “byproduct” gas could be transported to our key markets, thereby affecting regional supply. The industry also faces competition from alternative energy sources. The highly competitive environment in which CNX operates may negatively impact our ability to acquire additional properties at prices or upon terms CNX views as favorable. Any reduction in our ability to compete in current or future natural gas markets could materially adversely affect our business, financial condition, results of operationsoperations, and cash flows.

In addition, potential third-party customers who are significant producers of natural gas and condensate may develop their own midstream systems in lieu of using our systems. All of these competitive pressures could materially adversely affect our business, results of operations, financial conditioncondition, and cash flows.

Deterioration in the economic conditions in any of the industries in which our customers and their customers operate, a domestic or worldwide financial downturn, or negative credit market conditions can have a material adverse effect on our liquidity, results of operations, businessbusiness, and financial condition that CNX cannot predict.

Economic conditions in a number of industries in which our customers and their customers operate, such as electric power generation, have experienced substantial deterioration in the past, resulting in reduced demand for natural gas. Renewed or continued weakness in the economic conditions of any of the industries CNX serves or that are served by our customers, or the increased focus by markets on carbon-neutrality or alternative energy sources, could adversely affect our business, financial condition, results of operationoperation, and liquidity in a number of ways. For example:

•demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, marginsmargins, and profitability of our natural gas business;

To manage our exposure to fluctuations in the price of natural gas, CNX enters into hedging arrangements with respect to a portion of our expected production. As of January 15,8, 2025,2026, CNX expects these transactions will represent approximately 478.9 Bcf of our estimated 2025 production at an average price of $2.58 per Mcf, 432.3448.8 Bcf of our estimated 2026 production at an average price of $2.67$2.74 per Mcf, 304.4379.3 Bcf of our estimated 2027 production at an average price of $3.28 per Mcf, 51.6186.5 Bcf of our estimated 2028 production at an average price of $3.64$3.25 per Mcf,Mcf and a nominal amount of our estimated 2029 production. To the extent that CNX engages in hedging activities, CNX may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If CNX chooses not to engage in or otherwise reduce our future use of hedging arrangements or is unable to engage in hedging arrangements due to lack of acceptable counterparties, CNX may be more adversely affected by declines in natural gas prices than our competitors who engage in hedging arrangements to a greater extent than CNX does. Increases or decreases in forward market prices could result in material unrealized (non-cash) losses or gains on commodity derivative instruments resulting in volatility in reported earnings. Future legislation regarding derivatives could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price risks associated with our business.

Negative public perception regarding our industry resulting from, among other things, operational incidents or concerns raised by advocacy groups, related to environmental, health, or community impacts has resulted in increased regulatory scrutiny, which has resulted in additional laws, regulations, guidelinesguidelines, and enforcement interpretations, at the federal and state level. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdensburdens, and an increased risk of litigation that may negatively impact our future financial results or our stock price. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the administrative process or in the courts. This could cause the permits CNX needs to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

In addition, in recent years increasing attention has been given to corporate activities related to environmental issues in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities,community and other groups,groups to promote change at public companies, including through investment and voting practices. These activities include increasingfocusing attention on and demands fordemanding action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. As a result, some capital markets participants have reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the energy industry.equities. If divestment efforts continue,are successful, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted and have a material adverse effect on our business, financial condition, results of operationsoperations, and cash flows.

While CNX has not incurred significant disruptions to its operations during the past three fiscal years as a direct result of theany COVID-19global pandemicor domestic health crisis or geopolitical conflict, including the ongoing war in Ukraine and the ongoing conflicts in the Middle East, the resulting global instability and any similar disruptions may materially and adversely affect, our business, operating and financial resultsresults, and liquidity in the future. As the pandemic and global instability has significantly impacted economic activity and markets around the world, similar pandemicshealth crises and conflicts could negatively impact our business in numerous ways, including, but not limited to, the following:

•the operations of our midstream service providers, on whom CNX relies for the transmission, gatheringgathering, and processing of a significant portion of our produced natural gas, NGLs, oiloil, and condensate, and our other service providers and suppliers may be disrupted or suspended in response to containing the outbreak, geopolitical instabilityinstability, and/or the difficult economic environment may lead to the bankruptcy or closing of service providers, facilitiesfacilities, and infrastructure or delays or disruptions in our supply chain, which may result in substantial discounts in the prices CNX receives for our produced natural gas, NGLs, oiloil, and condensate or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.

To the extent events were to adversely affect our business and financial results, it may also have the effect of heightening many of the other risks set forth in this Risk Factors section of this Form 10-K, such as those relating to our financial performance and debt obligations. Any of these disruptions or outcomes could have a material adverse effect on our business, operations, financial resultsresults, and liquidity.

Increasing attention to environmental, social and governance (ESG) matters may adversely impact our business.

Organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESGenvironmental, social and governance matters. Such ratings, while not standardized or fully transparent, are used by some investors to evaluate their investment and voting decisions. Unfavorable ESGenvironmental, social and governance ratings may lead to increased negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries. Such diversion could have a negative impact on our stock price and our access to and costs of capital.

Additionally, increased governmental attention to ESGenvironmental, social and governance matters, including state actions such as California’s Climate Corporate Data Accountability Act and its Climate-Related Financial Risk Act, may require the production and public reporting of additional data for investors’ evaluation of investment and voting decisions. This could lead to negative investor sentiment toward us and to the diversion of their investment away from the fossil fuel industry to other industries. Such a diversion could have a negative impact on our stock price and our access to and costs of capital.

Although CNX owns midstream facilities, we also depend on third party facilities to gather, processprocess, and transport our natural gas to market. Reductions, limitationslimitations, or disruptions (including force majeure events) in pipeline, gathering, or processing facility capacity could force us to reduce our production, reduce our sales or transportation of natural gas and/or NGLsNGLs, or purchase higher cost replacement gas, negatively affecting our profitability, and causing our unit costs to increase. A significant portion of our natural gas is sold on or through twothree pipeline systems, Texas Eastern Transmission andTransmission, Columbia Gas Transmission, and Eastern Gas Transmission & Storage, which could experience capacity issues, operational disruptionsdisruptions, and unexpected downtime, including from cybersecurity incidents and cyberattacks, with either no or little alternative transportation options available for our natural gas. Further, if pipeline quality standards change or we cannot meet applicable standards, we might be required to install additional processing equipment which could increase our costs. Pipelines could also curtail our flows until the natural gas delivered to their pipeline is in compliance with predetermined gas quality specifications. Any reduction in our production of natural gas or increase in our costs could materially adversely affect our business, financial condition, results of operationsoperations, and cash flows.

CNX has various third-party firm transportation, processing, gatheringgathering, and other agreements in place, many of which have minimum volume delivery commitments that obligate us to pay fixed demand charges or fees on minimum volumes regardless of actual volume throughput. Reductions in our drilling program may result in insufficient production to fully utilize these arrangements or otherwise use our full firm transportation and processing capacity, reducing our cash flow from operations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect our business, financial condition, results of operationsoperations, and cash flows.

Our continuing investment in midstream infrastructure development and maintenance programs is intended, among other items, to connect our wells to other existing gathering and transmission pipelines and can involve significant risks, including those relating to timing, cost overrunsoverruns, and operational efficiency. Significant portions of our natural gas production are dependent on a small number of key compression and processing stations. An operational issue at any of those stations would materially impact our production, cash flowflow, and results of operation.

Uncertainties exist in the estimation of the economic recovery of natural gas reserves. Due to these uncertainties, estimates of revenues, operating and development costscosts, and future profitability may prove to be inaccurate.

Natural gas reserves are economically recoverable when the revenue expected to be generated from the products sold exceeds their expected cost of development and production. Estimating reserves requires the use of assumptions concerning natural gas and liquid hydrocarbon prices, production levels, recoverable reserve quantities, production and ad valorem taxes and operating and development costs. For example, a significant amount of our natural gas reserves are identified as proved undeveloped reserves and may be more susceptible to positive or negative changes in reserve estimates than our proved developed reserves. Also, we make certain assumptions regarding natural gas and liquid hydrocarbon prices, production levels, production and ad valorem taxestaxes, and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our natural gas reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of natural gas reserves based on risk of recoveryrecovery, and estimates of the future net cash flows. The PV-10 measure of pre-tax discounted future net cash flows and the standardized measure of after-tax discounted future net cash flows from our proved reserves included within this Form 10-K are not necessarily the same as the current market value of our estimated natural gas reserves. Actual future net cash flows from our proved and unproved oil and natural gas properties may be affected by factors such as:

•capital costs of drilling, completioncompletion, and gathering assets.

Developing, producingproducing, and operating natural gas wells is subject to operating risks and hazards that could increase expenses, decrease our production levelslevels, and expose us to losses or liabilities that may not be fully covered under our insurance policies.

The development of natural gas involves numerous risks, including the risk that an encountered well does not produce in sufficient quantities to make the well economically viable. The cost of drilling, completingcompleting, and operating wells is substantial and uncertain, and our operations may be curtailed, delayeddelayed, or canceled as a result of a variety of factors beyond our control. Our future development activities may not be successful, and if they are unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. CNX may be unable to develop identified or budgeted wells within our expected time frame, or at all for various reasons, and a final determination with respect to the development of any scheduled or budgeted wells will be dependent on a number of factors, including:

•the results of delineation efforts and the acquisition, reviewreview, and analysis of data, including seismic data;

Our business strategy focuses on horizontal drilling and production in unconventional Shale formations, primarily the Marcellus Shale and Utica Shale in the Appalachian Basin. Drilling and stimulating horizontal wells is technologically complex, expensiveexpensive, and involves a higher risk of failure when compared to vertical wells. Due to the higher costs, the risks of our development program are spread over a smaller number of wells, and in order to be profitable, each horizontal well will need to produce at higher levels. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad, or a single well could adversely affect production from all of the wells on the pad. Pad development can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we are better served by drilling horizontal wells using multi-well pads, the risk component involved in such development will be increased in some respects, with the result that CNX might find it more difficult to achieve economic success in our development program.

The exploration, production, and transporting of natural gas involves numerous operational risks. The cost of developing and operating a well is often uncertain, and a number of factors can delay, suspend, or prevent development operations, decrease productionproduction, and/or increase the cost of our natural gas operations at particular sites for varying lengths of time, including unexpected development and production conditions (such as pressure or irregularities in geologic formations or wells, material and equipment failures, fires, ruptures, loss of well control, landslides, mine subsidence, explosionsexplosions, or other accidents and environmental concerns and adverse weather conditions), which conditions and risks may be amplified as we increase the vertical and horizontal length of drilling endeavors; similar operational or design issues relating to pipelines, compressor stations, pump stations, related equipmentequipment, and surrounding properties; challenges relating to transportation, pipeline infrastructureinfrastructure, and capacity for treatment or disposal of waste water generated in operations and failure to obtain, or delays in the issuance of, permits at the state or local level and the resolution of regulatory concerns.

•regulatory enforcement, investigationsinvestigations, and penalties;

The occurrence of any operational event that prevents delivery of natural gas to a customer and is not excusable as a force majeure event under our supply agreement, could result in economic penalties, suspensionsuspension, or ultimately termination of the supply agreement.

Although CNX maintains insurance for a number of risks and hazards, we may not be adequately insured against the losses or liabilities that could arise from a significant accident or disruption in our operations. The occurrence of an event that is not fully covered by insurance, such as pollution or environmental issues, could materially adversely affect our business, financial condition, results of operationsoperations, and cash flows.

Our management team has specifically identified and scheduled certain locations as an estimation of our future multi-year development activities on our existing acreage which represent a significant part of our development strategy. Our ability to develop these locations may be dependent on a number of factors, including natural gas, NGLNGL, and oil prices, the availability and cost of capital, drilling, completions and production costs, obtaining required regulatory permits, the acquisition on acceptable terms of any leasehold interests we do not control but that are necessary to complete the drilling unit (including potentially through third-party swap transactions), availability of drilling services and equipment, drilling results, lease expirations for the failure to timely develop or otherwise, transportation constraints, regulatory and zoning approvalsapprovals, and other factors. Because of these uncertain factors, we do not know if the numerous development locations we have identified will ever be drilled. CNX may require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any development activities we are able to conduct on these locations may be unsuccessful, which may result in our inability to add additional proved reserves or may result in a downward revision of our estimated proved reserves, which could materially adversely affect our business and results of operations.

Our exploration and development projects and midstream development require substantial capital expenditures and are subject to regulatory, environmental, political, legallegal, and economic risks and if CNX fails to generate sufficient cash flow, obtain required capital or financing on satisfactory termsterms, or respond to regulatory and political developments, our natural gas reserves may decline, and our operations and financial results may suffer.

As part of our strategic determinations, CNX expects to continue to make substantial capital expenditures in the development and acquisition of natural gas reserves and the maintenance, purchasepurchase, or construction of midstream systems. If CNX is unable to make sufficient or effective capital expenditures, we will be unable to maintain and grow our business. The gas gathering agreements that we have with third parties may impose obligations on us to invest capital in our midstream systems that are not fully protected against volumetric risks associated with lower-than-forecast volumes flowing through our gathering systems. If our customers fail to develop their properties in the areas covered by these acreage dedications, or otherwise sell, exchange, farm-outfarm-out, or otherwise dispose of all of, or an undivided interest in, the development of the dedicated acreage, the resulting decrease in the development of reserves by our midstream customers could result in reduced volumes serviced by us and a commensurate decline in revenues and cash flows.

Additionally, the construction of additions or modifications to our existing midstream systems involves numerous regulatory, environmental, politicalpolitical, and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If these projects are undertaken, they may not be completed on schedule, at the budgeted costcost, or at all. The construction of additions to our existing assets may require us to obtain new land rights and regulatory permits prior to constructing new pipelines or facilities, which may not be obtained in a timely, cost-effective fashion or in a way that allows us to connect new natural gas supplies to existing gathering pipelines or capitalize on other attractive expansion opportunities Also, these midstream assets may not be able to attract enough throughput to achieve the expected investment return.

Revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. There is no assurance that CNX will have sufficient cash from operations, borrowing capacity under our credit facilities, or the ability to raise additional funds in the capital markets to meet our capital requirements. Without sufficient capital, CNX could be required to curtail the pace of the development of our natural gas properties and midstream activities, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial conditioncondition, and results of operations.

CNX may not be able to obtain the required personnel, services, equipment, partsparts, and raw materials in a timely manner, in sufficient quantitiesquantities, or at reasonable costs to support our operations.

CNX relies on third-party contractors to provide key services and equipment for our operations. CNX contracts with third parties for well services, related equipmentequipment, and qualified experienced field personnel to drill and complete wells, construct pipelinespipelines, and conduct field operations. We also utilize third-party contractors to provide land acquisition and related services to support our land operational needs. The demand for these services, equipmentequipment, and personnel can fluctuate significantly, often in correlation with natural gas and NGL prices, causing periodic shortages.

Historically, there have been shortages of drilling and work-over rigs, pipe, compressorscompressors, and other equipment as demand for rigs and equipment has grown, along with the number of wells being drilled and/or completed. The costs and delivery times of equipment and supplies are substantially greater in periods of peak demand, including increased demand for plays outside of our area of geographic focus. Weather may also play a role with respect to the relative availability of certain materials.

In addition, accelerated levels of inflation, including through the introduction of new tariffs, may lead to price increases beyond CNX’s control that could lead to CNX incurring increased costs for contractors and/or materials. For example, fuel pricing and labor shortages havecould ledlead to increased ground transportation costs. Accordingly, CNX cannot be assured that we will be able to obtain necessary services, drilling and completions equipmentequipment, and supplies in a timely manner or on satisfactory terms, and CNX may experience shortages of or quality assurance issues with, or increases in the costs of, drilling and completions equipment, crewscrews, and associated supplies, equipmentequipment, and field services used in the support of our operations.

Our future success depends to a large extent on the services of our and our service providers’ key employees. The loss of one or more of these individuals could materially adversely affect our business. Furthermore, competition for experienced technical and other professional personnel, as well as diverse candidates which bring with them valuable perspectives and experiences, remains strong. If CNX and our service providers cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. Continued service and equipment provider consolidation poses a potential risk to CNX of increasing the likelihood of key personnel turnover within our service providers. Service provider consolidation also poses the risk of individuals or equipment being relocated to another basinbasin, or a reduction in services provided, based on the service provider’s business plan.

Shortages may lead to escalating prices, poor service, inefficient operationsoperations, and increase the possibility of accidents due to the hiring of less experienced personnel and overuse of equipment by contractors. A decrease in the availability of these services, equipmentequipment, or personnel could lead to a decrease in our natural gas production levels, increase our costs of natural gas production, and decrease our anticipated profitability. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which events could materially adversely affect our business, financial condition, results of operations, or cash flows.

Global politicsand national politics, including geopolitical hostilities, or natural disasters can also create additional risk to CNX. This could lead to shortages in raw materials or finished goods, which ultimately impact CNX’s pricing and availability. In addition, global transportation can be impacted which can affect CNX’s ability to receive material in a timely manner, while also increasing cost.

As part of our drilling and production in Shale formations, CNX uses hydraulic fracturing processes that require access to adequate sources of water, which may not be available in proximity to our operations or at certain times of the year. To ensure adequate water for our operations, CNX may be required to invest substantial amounts of capital in water pipelines which are used for relatively short periods of time. Increased regulation of these water pipelines could cause us to invest additional capital, alter our disposal or transportation methodmethod, or negatively affect our operations. Alternatively, CNX may be required to transport water by truck, and CNX may not be able to contract for sufficient water hauling trucks or drivers to meet our needs.

Further, our operations generate significant volumes of wastewater that must be treated, reusedreused, or disposed. This produced water or wastewater can be generated from various aspects of our operations, including from drilling fluids, completions activitiesactivities, and normal production over the life of the well, and are associated with all types of natural gas wells. A significant portion of this water can be recycled for use in other hydraulic fracturing operations. To the extent we must dispose of water rather than recycle it, our costs may increase, which will detrimentally affect our cash flows. We attempt to minimize the expense associated with the transportation of wastewater by optimizing the transportation between the sources of wastewater and locations where the wastewater can be reused or disposed. Various interruptions in our planned transportation of this wastewater, including operational issues and regulatory matters, could increase our operating costs, which would detrimentally affect our cash flows. The risk of pollution also exists while handling, transferring, storing, recyclingrecycling, and disposing of wastewater and other wastes, as well as in development or production of a well.

Failure to successfully replace our current natural gas reserves through economic development of our existing or acquired undeveloped assets or through acquisition of additional producing assets, would lead to a decline in our natural gas, NGLNGL, and oil production levels and reserves.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline can change if production from our existing wells is different than what has been estimated, operating conditions change, or other circumstances arise that affect our ability to produce the wells. The ability to offset the declining production or natural gas reserves is dependent upon our success in efficiently developing and selling our current reserves and economically finding or acquiring additional economically recoverable reserves. CNX may not be able to develop, findfind, or acquire additional economically recoverable reserves to replace our current and future production at acceptable costs, which would negatively impact our future cash flows and income.

In addition, the level of natural gas, NGLNGL, and condensate volumes handled through our midstream systems depends on the level of production from natural gas wells feeding into such midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, CNX must supply natural gas, NGLsNGLs, and condensate from new wells on acreage in close proximity to our midstream systems. This can take the form of wells we develop on our own, wells developed by others on acreage that is dedicated to our midstream systemssystems, or through contracts with third-party customers to flow volumes on our midstream systems. CNX has no control over third party producers’ levels of development and completion activity in areas adjacent to our midstream systems, or the amount of reserves associated with or rate of production decline from those third-party wells – and only limited control over those factors on our own wells.

Additionally, most of the land on which our midstream systems have been constructed is not owned in fee by us; rather, the properties are held by surface use agreements, rights-of-wayrights-of-way, or other easement rights. CNX is, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. CNX may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew the right-of-way or for other reasons, could materially adversely affect our business, financial condition, results of operationsoperations, and cash flows.

Climate change risk, legislation, litigationlitigation, and regulation of greenhouse gas emissions at the federal or state level may increase our operating costs and reduce the value of our natural gas assets. Any such regulation that may be implemented, as well as uncertainty concerning such regulation and public policy pressures, could adversely impact the market for natural gas, as well as for our securities.

In 2013, the EPA began regulating GHGs under the Clean Air Act to limit emissions of CO2 from natural gas-fired power plants. Subsequently, the EPA reviewed and proposed repealing the Clean Power Plan in 2017, replacing it with the Affordable Clean Energy Rule (ACER) in 2019. ACER was vacated on the last day of the Trump administration in January 2021. Adopting an alternative approach, the Biden administration re-entered the United States in the Paris Climate Accord, and the EPA adopted a new Climate Adaptation Action Plan in October of 2021. In 2022, the Inflation Reduction Act (IRA) was signed, promoting renewable energy and imposing a fee on the emission of methane above specified limits from sources required to report their emissions to the EPA beginning in calendar year 2024. TheWhile the second Trump administration has taken steps in 2025 to reduce regulation of GHGs, including issuing a proposed rule to rescind the 2009 Endangerment Finding that is the basis for regulation of GHGs under the Clean Air Act, issuing a proposed rule to repeal GHG emissions standards for fossil fuel-fired electric generating units, and repealing, under the Congressional Review Act, the rule implementing the methane chargefee provisions of the IRA, the underlying methane fee provisions in the IRA have not been amended, and theother proposals to repeal GHG-related regulations are not final. As these rules and any replacements or updates thereto are adopted, changed, rescinded, or modified, any methane charges or incentives for renewable energy infrastructure development could increase operational costs and further accelerate the transition of the economy away from the use of natural gas towards lower carbon emissions alternatives. As these rulesalternatives and any replacements or updates thereto are adopted, changed, rescinded or modified, these rules could decrease demand for natural gas and consequently adversely affect our business and results of operations.

The EPA has adopted regulations under existing provisions of the federal Clean Air Act that establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permits for large stationary sources. Facilities requiring PSD permits may also be required to meet “best available control technology” (BACT) standards.standards, Rulemaking related to GHGwhich could alter or delay our ability (or our customers’ ability) to obtain new and/or modified air source permits.

The EPA has also adopted, changedchanged, and amended rules to control volatile organic compound emissions from certain oil and natural gas equipment and operations as part of itsa prior initiative to reduce methane emissions. In response to subsequent judicial involvement, the EPA issued a proposed rule in July 2017 that would stay the methane rule for two years (which rule was vacated by the United States Court of Appeals for the D.C. Circuit). Thereafter in September 2018, the EPA proposed revisions to the 2016 New Source Performance Standards for the oil and natural gas industry. Additional revisions were proposed in August 2019, August 20202020, and November 2021. On December 2, 2023, the EPA finalized New Source Performance Standards to reduce methane and smog-forming volatile organic compounds from new, modifiedmodified, and reconstructed sources. This final action also includes Emissions Guidelines, which set procedures for states to follow as they develop plans to limit methane from existing sources. These rules may result in increased costs for permitting, equipping, and monitoring methane emissions or otherwise restrict operations or increase the costs thereof.

CNX continually monitors factors that could cause actual results of operations to differ from historical results or current expectations. Examples include global events such as the conflictcurrent betweenuncertainties Russiain andglobal Ukrainefinancial markets, geopolitical tensions and announcements by the Organization of the Petroleum Exporting Countries that impact oil production, bothall of which have had an impact on global commodity prices. These and other factors could affect the Company’s operations, earnings and cash flows for any period and could cause such results to not be comparable to those of the same period in previous years. The results presented in this Form 10-K are not necessarily indicative of future operating results.

•Repurchased 7.216.9 million shares of CNX common stock for $179$528 million on the open market at an average price of $24.68.$31.00 (see Note 5 – Stock Repurchase in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information).

•On January 27, 2025, the CompanyCNX completed the acquisition of the natural gas upstream and associated midstream business of Apex Energy II, LLCLLC, (“the Apex Transaction"”) for total cash consideration of approximately $505$518 million,million subject to certain adjustments. See(see Note 224 – SubsequentAcquisitions Eventand Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.information).

•Our 20252026 annual sales volumes are expected to be approximately 605-620605 - 620 Bcfe.

•Our 20252026 capital expenditures are expected to be approximately $450-$500$556 - $586 million.

The following discussion and analysis of our Results of Operations and Liquidity and Capital Resources includes a comparison of the year ended December 31, 20242025 to the year ended December 31, 2023.2024. A similar discussion and analysis that compares year ended December 31, 20232024 to the fiscal year ended December 31, 20222023 is omitted from this Annual Report on Form 10-K and may be found in 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, 2023,2024, which is incorporated herein by reference.

Net Income (Loss) Income

Included in earnings for the year ended December 31, 2025 was an unrealized gain on commodity derivative instruments of $278 million and a net gain on asset sales and abandonments of $97 million. Included in the net loss for the year ended December 31, 2024 was an unrealized loss on commodity derivative instruments of $453 million and a net gain on asset sales and abandonments of $25 million. Included in earnings for the year ended December 31, 2023 was an unrealized gain on commodity derivative instruments of $1,765 million and a net gain on asset sales and abandonments of $132 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information related to the gain on asset sales and abandonments.

•Lease operating expense increased on a per unit basis primarily due to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completions and an increase in well tending expense. The increases were offset, in part, by the overall increase in total sales volumes.

•Depreciation, depletion and amortization expense increased on a per unit basis primarily due to a slightly higher annual depletion rate for 2024.rate. The increases were offset, in part, by the overall increase in ratetotal issales primarily attributable to downward reserve revisions due to adjustments to the five-year development plan that lowered proved undeveloped reserves, price changes, and the sale of various non-operated producing oil and gas assets.volumes.

The increase in Sales of Natural Gas, NGL and Oil, including Cash Settlements, a Non-GAAP Financial Measure, was primarily due to the 83.7 Bcf increase in natural gas sales volumes and the $1.01 per Mcf increase in natural gas sales price, when excluding the impact of hedging. These increases were offset, in-part, by the impact of the change in the (loss) gain on commodity derivative instruments - cash settlement related to the Company's hedging program, the 8.55.5 Bcfe increasedecrease in NGL sales volumes and the $0.36$0.30 per barrel increasedecrease in NGL prices. These increases were offset, in-part, by the $0.22 per Mcf decrease in natural gas sales price, when excluding the impact of hedging, and the 17.7 Bcf decrease in natural gas sales volume.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $1,764 million for the year ended December 31, 2025 compared to $1,080 million for the year ended December 31, 20242024. comparedThe to $1,170$684 million for the year ended December 31, 2023. The $90 million decreaseincrease was due primarily to a 9.0%52.6% decreaseincrease in the average sales price for natural gas and aan 3.4%18.6% decreaseincrease in Shale gas sales volumesvolumes. primarilyThese due to normal production declines and the timing of when new wellsincreases were turned-in-line. The decrease was offset, in part, by a 19.1%10.6% increasedecrease in NGLs sales volumes due to an increase in ethane recoveries and a 1.7%1.4% increasedecrease in the average sales price for NGLs.

The increase in total average Shale sales price was primarily due to a $0.25$1.01 per Mcf increase in average gas sales price. These increases were offset, in part, by a $0.88 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlementsettlements and a $0.06$0.05 per Mcfe increasedecrease in the average NGL sales price. These increases were offset in part by a $0.19 per Mcf decrease in average gas sales price. The notional amounts associated with these financial hedges represented approximately 389.7452.6 Bcf of the Company's produced Shale gas sales volumes for the year ended December 31, 20242025 at an average gainloss of $0.67$0.38 per Mcf hedged. For the year ended December 31, 2023,2024, these financial hedges represented approximately 399.2389.7 Bcf at an average gain of $0.37$0.67 per Mcf hedged.

Total operating costs and expenses for the Shale segment were $903 million for the year ended December 31, 2025 compared to $791 million for the year ended December 31, 2024 compared to $746 million for the year ended December 31, 2023.2024. The increasesincrease in total dollars and decrease in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $73 million for the year ended December 31, 2025 compared to $48 million for the year ended December 31, 2024 compared to $44 million for the year ended December 31, 2023.2024. The increase in total dollars and unit costs was primarily related to an increase in water disposal costs as more water was taken to disposal instead of being reused in well completionscompletions, higher well tending expense and anhigher repairs and maintenance expense. The increase in wellunit tendingcosts expense.was offset, in part, by the increase in total Shale sales volumes.

•Shale transportation, gathering and compression costs were $316$317 million for both the yearsyear ended December 31, 20242025 andcompared 2023.to $316 million for the year ended December 31, 2024. The increase in total dollars was primarily due to higher repairs and maintenance and electrical compression expense offset, in part, by lower processing costs due to the production mix of higher dry gas volumes and an increase in lower cost ethane volumes. The decrease in unit costs was due to the decreaseincrease in total Shale sales volumes.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $488 million for the year ended December 31, 2025 compared to $405 million for the year ended December 31, 2024 compared to $365 million for the year ended December 31, 2023.2024. These amounts included depletion on a unit of production basis of $0.68$0.72 per Mcfe and $0.59$0.68 per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily due to a higher annual depletion rate for 2024. The increase in rate is primarily attributable to downward reserve revisions due to adjustments to the five-year development plan that lowered proved undeveloped reserves, price changes, and the sale of various non-operated producing oil and gas assets The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

The CBM segment had a loss before income tax of $17 million for the year ended December 31, 2025 compared to a loss before income tax of $26 million for the year ended December 31, 2024 compared to earnings before income tax of $1 million for the year ended December 31, 2023.2024.

The CBM segment had natural gas revenue of $148 million for the year ended December 31, 2025 compared to $105 million for the year ended December 31, 20242024. comparedThe to $131$43 million for the year ended December 31, 2023. The $26 million decreaseincrease was primarily due to a 16.5%45.4% decreaseincrease in the average sales price for natural gas in the current period andoffset, in part, by a 3.7%3.3% decrease in CBM gas sales volumes due to normal production declines.

The total average CBM sales price decreasedincreased $0.30$0.40 per Mcf due to a $0.53$1.22 per Mcf decreaseincrease in average gas sales price, offset, in part, by a $0.25$0.83 per Mcf change in the (loss) gain on commodity derivative instruments - cash settlement resulting from the Company's hedging program.settlements. The notional amounts associated with these financial hedges represented approximately 30.629.5 Bcf of the Company's produced CBM gas sales volumes for the year ended December 31, 20242025 at an average gainloss of $0.67$0.39 per Mcf hedged. For the year ended December 31, 2023,2024, these financial hedges represented approximately 31.930.6 Bcf at an average gain of $0.36$0.67 per Mcf hedged.

•CBM transportation,lease gatheringoperating andexpense compressionwas costs were $64$24 million for the year ended December 31, 20242025 compared to $66$22 million for the year ended December 31, 2023.2024. The decreaseincrease in total dollars and unit costs was primarily due to a decrease in repairs and maintenance expense offset, in part, by an increase in electricalrepair compressionand maintenance and well tending expense. The increase in per unit costs was also due to the decrease in total CBM gas sales volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment were $60 million for both the yearyears ended December 31, 20242025 comparedand to $50 million for the year ended December 31, 2023.2024. These amounts also included depletion on a unit of production basis of $0.85 per Mcfe andfor $0.64both per Mcfe, respectively. The increase in the units of production depreciation, depletion and amortization rate in the current period is primarily the result of a higher 2024 annual depletion rate. The increase in rate is primarily attributable to downward reserve revisions due to higher operating costs and price changes.periods. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

The Other Segment includes nominal shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, Newsales Technologies,of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.

The Other Segment had earnings before income tax of $60 million for the year ended December 31, 2025 compared to a loss before income tax of $711 million for the year ended December 31, 2024 compared to earnings before income tax of $1,580 million for the year ended December 31, 2023.2024. The decreaseincrease in total dollars is discussed below.

Unrealized Gain (Loss) Gain on Commodity Derivative Instruments - Unrealized

For the year ended December 31, 2025, the Other Segment recognized an unrealized gain on commodity derivative instruments of $278 million. For the year ended December 31, 2024, the Other Segment recognized an unrealized loss on commodity derivative instruments of $453 million. For the year ended December 31, 2023, the Other Segment recognized anThe unrealized gain on commodity derivative instruments of $1,765 million. The unrealized (loss or gain) on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.

Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $45 million for the year ended December 31, 2025 compared to $59 million for the year ended December 31, 20242024. comparedPurchased togas $75costs were $43 million for the year ended December 31, 2023.2025 Purchasedcompared gas costs wereto $57 million for the year ended December 31, 2024 compared to $70 million for the year ended December 31, 2023.2024. The period-to-period decrease in purchased gas revenue was due to a decrease in averagepurchased gas sales price.volumes.

•Sales of environmental attributes includesinclude items such as (but are not limited to): carbon credits, air quality credits, renewable or alternative energy credits, methane capture credits, methane performance certificates, emission reductions, offsets and/or allowances. The quantities and types of environmental attributes we sell and the associated revenue can vary depending on a number of factors, including the market for these credits, changes to the various voluntary or compliance programs under which the credits are generated and sold, and our ability to strictly comply with the programs under which the attributes can be sold. The increasedecrease in the period-to-period comparison was due to ana increasedecrease in the amount of environmental attributes sold.sold and a decrease in the price received.

•Short-termLong-term incentiveequity-based compensation (non-cash) increased $12in millionthe period-to-period comparison due to higheran projectedincrease payoutsin forequity awards issued in the current period.year.

•Other increaseddecreased in the period-to-period comparison primarily due to higherlower professional services and consultingvarious fees,other asone-time wellitems, asnone increasedof softwarewhich costs.were individually material.

The financial conditions and operating results of the Company can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in "Item 1A. Risk Factors" in the 2025 Form 10-K. The risks described could materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. CNX may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, conditions that are currently deemed to be immaterial may also materially and adversely affect CNX's business, financial condition, cash flows, and results of operations. Except for the risk factor disclosed in Part II, Item 1A of the first quarter 2026 Form 10-Q, which is hereby incorporated by reference into this Part II, Item 1A of this Form 10-Q, thereThere have been no material changes to the Company’s risk factors as set forth in the 2025 Form 10-K.

Natural Gas, NGL,NGLs and Oil Pricing

Total hedged natural gas production for the secondthird quarter of 2026 is 115.1116.0 Bcf. CNX's annual gas hedge position is shown in the table below:

Results of Operations - Three Months Ended MarchJune 31,30, 2026 Compared with Three Months Ended MarchJune 31,30, 2025

Net Income (Loss)

Included in the earnings for the three months ended MarchJune 31,30, 2026 was an unrealized gain on commodity derivative instruments of $226$131 million and a net loss on asset sales and abandonments of $1 million. Included in the earnings for the three months ended June 30, 2025 was an unrealized gain on commodity derivative instruments of $456 million and a net gain on asset sales and abandonments of $6 million. Included in the loss for the three months ended March 31, 2025 was an unrealized loss on commodity derivative instruments of $418 million and a net gain on asset sales and abandonments of $10$18 million. See Note 4 – Acquisitions and Dispositions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q for additional information related to the loss (gain) on asset sales and abandonments, net.abandonments.

CNX's management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial performance, and believes that they are useful for investors in analyzing the Company. Although these are not measures of performance calculated in accordance with GAAP, management believes that these financial measures are useful to an investor in evaluating CNX because these metrics are widely used to evaluate a natural gas company’s operating performance. Sales of Natural Gas, NGLNGLs and Oil, including cash settlements is a non-GAAP measure that excludes the impacts of changes in the fair value of commodity derivative instruments prior to settlement, which are often volatile, and only includes the impact of settled commodity derivative instruments. Sales of Natural Gas, NGLNGLs and Oil, including cash settlements also excludes purchased gas revenue and other revenue and operating income, which are not directly related to CNX’s natural gas producing activities. Natural Gas, NGLNGLs and Oil Production Costs is a non-GAAP measure that excludes certain expenses that are not directly related to CNX’s natural gas producing activities and are managed outside our production operations. These expenses include, but are not limited to, interest expense, other operating expense and other corporate expenses such as selling, general and administrative costs. We believe that Sales of Natural Gas, NGLNGLs and Oil, including cash settlements, Natural Gas, NGLNGLs and Oil Production Costs and Natural Gas, NGLNGLs and Oil Production Margin (which is derived by subtracting Natural Gas, NGLNGLs and Oil Production Costs from Sales of Natural Gas, NGLNGLs and Oil, including cash settlements) provide useful information to investors for evaluating period-to-period comparisons of earnings trends. These metrics should not be viewed as a substitute for measures of performance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies.

Selected Natural Gas, NGLNGLs and Oil Production Financial Data

The following table presents a summary of our total sales volumes, sales of natural gas, NGLNGLs and oil including cash settlements, natural gas, NGLNGLs and oil production costs and natural gas, NGLNGLs and oil production margin related to our production operations on a total company basis (See Non-GAAP Financial Measures Reconciliation above for the reconciliation to the most directly comparable financial measures calculated and presented in accordance with GAAP):

*NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of NGL,NGLs, condensate, and natural gas prices.

•Lease operating expense decreased on a per unit basis primarily due to a decrease inlower water disposal costs as more water was reused in well completions,completion aactivities rather than taken to disposal. The decrease was offset, in wellpart, tendingby expense and the overall increase inlower total sales volumes.volumes during the period.

•Depreciation,Transportation, depletiongathering and amortizationcompression expense increased on a per unit basis primarily due to a slightly higher annual depletion rate offset, in part, by the overall increasedecrease in total sales volumes.volumes as well as higher repairs and maintenance and processing costs due to production mix.

The increasedecrease in Sales of Natural Gas, NGLNGLs and Oil, including Cash Settlements, a Non-GAAP Financial Measure was primarily due to the 4.616.1 Bcfe increasedecrease in total sales volumes and the $1.08$0.44 per Mcf increasedecrease in natural gas sales price, when excluding the impact of hedging. TheseThe increasesdecreases were offset, in part, by the impact of the change in the gain (loss) on commodity derivative instruments - cash settlement related to the Company's hedging program.program, the 3.7 Bcfe increase in NGL sales volumes and the $1.92 per Bbl increase in NGL prices.

SEGMENT ANALYSIS for the three months ended MarchJune 31,30, 2026 compared to the three months ended MarchJune 31,30, 2025:

The Shale segment had earnings before income tax of $249$197 million for the three months ended MarchJune 31,30, 2026 compared to earnings before income tax of $215$196 million for the three months ended MarchJune 31,30, 2025.

* NGLs and Oil/Condensate are converted to Mcfe at the rate of one barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGL,NGLs, condensate, and natural gas prices.

The Shale segment had natural gas, NGLs and oil/condensate revenue of $663$361 million for the three months ended MarchJune 31,30, 2026 compared to $508$452 million for the three months ended MarchJune 31,30, 2025. The $155$91 million increasedecrease was primarily due to a 29.1%15.4% increasedecrease in the average sales price for natural gas and a 3.5%10.4% increasedecrease in total Shale sales volumes. The decrease was offset, in part, by a 247.8% change in the gain (loss) on commodity derivative instruments and an 8.9% increase in the average sales price of NGLs.

The Shale segment had a lossgain on commodity derivative instruments - cash settlements of $209$42 million for the three months ended MarchJune 31,30, 2026 compared to a loss of $103$33 million for the three months ended MarchJune 31,30, 2025. The notional amounts associated with these financial hedges represented approximately 106.1108.3 Bcf of the Company's produced Shale gas sales volumes for the three months ended MarchJune 31,30, 2026 at an average lossgain of $1.97$0.40 per Mcf hedged. For the three months ended MarchJune 31,30, 2025, these financial hedges represented approximately 109.7113.6 Bcf at an average loss of $0.92$0.29 per Mcf hedged.

The increase in total average Shale sales price was primarily due to a $1.04 per Mcf increase in average gas sales price and a $0.17$0.32 per Mcfe increase in the average NGL sales price.price and a $0.57 per Mcf change in the gain (loss) on commodity derivative instruments - cash settlements. These increases were offset, in part, by a $0.80$0.43 per Mcf changedecrease in theaverage lossnatural ongas commoditysales derivative instruments - cash settlements.price.

Total operating costs and expenses for the Shale segment were $221 million for the three months ended MarchJune 31,30, 2026 compared to $207$240 million for the three months ended MarchJune 31,30, 2025. The increasedecrease in total dollars and increase in unit costs for the Shale segment were due to the following items:

•Shale lease operating expenses were $16$15 million for the three months ended MarchJune 31,30, 2026 compared to $17$20 million for the three months ended MarchJune 31,30, 2025. The decrease in total dollars and unit costs waswere primarily relateddue to a decrease inlower water disposal costs as more water was reused in well completions.completion activities rather than taken to disposal. The decrease was offset, in part, by lower total sales volumes during the period.

•Shale transportation,production, gatheringad valorem and compressionother costsfees were $86$5 million for the three months ended MarchJune 31,30, 2026 compared to $78$9 million for the three months ended MarchJune 31,30, 2025. The increasedecrease in total dollars and unit costs waswere primarily due to higherdecreased repairsrealized andprices maintenanceon expensenatural andgas. increasedThe utilization of firm transportation capacity as volumesdecrease in ourunit central Pennsylvania operating area have increased. The increasecosts was offset, in part, onby alower per-unittotal basissales byvolumes during the overall increase in total Shale sales volumes.period.

•Depreciation, depletion and amortization costs attributable to the Shale segment were $113$114 million for the three months ended MarchJune 31,30, 2026 compared to $106$131 million for the three months ended MarchJune 31,30, 2025. These amounts included depletion on a unitunits of production basis of $0.68$0.70 per Mcfe and $0.66$0.68 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

Total Shale other revenue and operating income relates to natural gas gathering services provided to third parties. The Shale segment had other revenue and operating income of $16$15 million for the three months ended MarchJune 31,30, 2026 compared to $17 million for the three months ended MarchJune 31,30, 2025. The decrease in the period-to-period comparison was primarily due to a decrease in third-party gathering volumes.

The CBM segment had earningsa loss before income tax of $7$6 million for the three months ended MarchJune 31,30, 2026 compared to a loss before income tax of $2$8 million for the three months ended MarchJune 31,30, 2025.

The CBM segment had natural gas revenue of $59$29 million for the three months ended MarchJune 31,30, 2026 compared to $43$33 million for the three months ended MarchJune 31,30, 2025. The $16$4 million increasedecrease was primarily due to a 39.5%17.2% increasedecrease in the average sales price for natural gas in the current period offset, in part, by a 2.2%3.2% decreaseincrease in CBM sales volumes due to normalthe productiontiming declines.of when new wells were turned-in-line.

The total average CBM sales price increaseddecreased $1.12$0.07 per Mcf primarily due to a $1.83$0.61 per Mcf increasedecrease in average natural gas sales price offset, in part, by a $0.71$0.54 per Mcf change in the gain (loss) on commodity derivative instruments - cash settlements. The notional amounts associated with these financial hedges represented approximately 6.97.5 Bcf of the Company's produced CBM sales volumes for the three months ended MarchJune 31,30, 2026 at an average lossgain of $1.92$0.41 per Mcf hedged. For the three months ended MarchJune 31,30, 2025, these financial hedges represented approximately 7.66.8 Bcf at an average loss of $0.92$0.32 per Mcf hedged.

Total operating costs and expenses for the CBM segment were $38 million for the three months ended June 30, 2026 compared to $39 million for the three months ended MarchJune 31, 2026 compared to $38 million for the three months ended March 31,30, 2025. The increasedecrease in total dollars and unit costs for the CBM segment were due to the following items:

•CBM lease operating expenses were $6 million for both the three months ended MarchJune 31,30, 2026 and 2025. The increase in per unit costs was due to an increase in repairs and maintenance expense, offset, in part, by the decreaseincrease in total CBM volumes.

•CBM production,transportation, ad valoremgathering and othercompression feescosts were $3$15 million for the three months ended MarchJune 31,30, 2026 compared to $2$17 million for the three months ended MarchJune 31,30, 2025. The increasedecrease in total dollars was primarily due to a decrease in repairs and maintenance expense. The decrease in unit costs was primarily due to the increase in the averagetotal CBM gas sales price.volumes.

•Depreciation, depletion and amortization costs attributable to the CBM segment waswere $14$15 million for both the three months ended MarchJune 31,30, 2026 and 2025. These amounts included depletion on a unitunits of production basis of $0.80 per Mcfe and $0.87$0.86 per Mcfe, respectively. The remaining depreciation, depletion and amortization costs were either recorded on a straight-line basis or related to asset retirement obligations.

The Other Segment includes nominal shallow oil and gas productionproduction, which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, sales of environmental attributes, exploration and production related other costs, as well as various other expenses that are managed outside the Shale and CBM segments such as selling, general and administrative expense (“SG&A”), interest expense and income taxes.

The Other Segment had earnings before income tax of $172$46 million for the three months ended MarchJune 31,30, 2026 compared to a lossearnings before income tax of $486$398 million for the three months ended MarchJune 31,30, 2025. The increasedecrease in total dollars is discussed below.

Unrealized Gain (Loss) on Commodity Derivative Instruments

For the three months ended MarchJune 31,30, 2026, the Other Segment recognized an unrealized gain on commodity derivative instruments of $226$131 million. For the three months ended MarchJune 31,30, 2025, the Other Segment recognized an unrealized lossgain on commodity derivative instruments of $418$456 million. The unrealized gain (loss) on commodity derivative instruments represents changes in the fair value of all the Company's existing commodity hedges on a mark-to-market basis.

Purchased gas volumes represent volumes of natural gas purchased at market prices from third parties and then resold in order to fulfill contracts with certain customers and to balance supply. Purchased gas revenue was $13$12 million for the three months ended MarchJune 31,30, 2026 compared to $11$10 million for the three months ended MarchJune 31,30, 2025. Purchased gas costs were $12 million for the three months ended MarchJune 31,30, 2026 compared to $11$9 million for the three months ended MarchJune 31,30, 2025. The period-to-period increase in purchased gas revenue was primarily due to an increase in thepurchased averagegas sales pricevolumes offset, in part, by thea decrease in purchasedaverage gassales volumes.price.

SG&A includes costs such as overhead, including employee labor and benefit costs, short-term incentive compensation, costs of maintaining our headquarters, audit and other professional fees, charitable contributions and legal compliance expenses. SG&A costs also includeincludes non-cash long-term equity-based compensation expense.