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

Volatility of natural gas, NGLs and oil prices significantly affects our cash flow and capital resources and could significantly hamper our ability to operate economically. Natural gas, NGLs and oil prices are volatile, and a decline in prices could adversely affectsaffect our profitability and financial condition. As a commodity business, the oil and gas industry is typically cyclical and we expect the volatility to continue. Natural gas prices are likely to affect us the most because approximately 64%65% of our proved reserves were natural gas as of December 31, 20242025 and, at times in the past, natural gas prices have been low compared to our costs to produce. Natural gas, NGLs and oil prices fluctuate in response to changes in supply and demand, market uncertainty and other factors that are beyond our control. These factors include:

military, economic and political conditions in natural gasgas, NGLs and oil producing regions;

the cost of exploring for, developing, producing, transporting and marketing natural gas, NGLs and oil; and domestic (federal, state and local) and foreign governmental regulations, sanctions, tariffs and taxation, including further legislation requiring, subsidizing or providing tax benefits for the use of alternative energy sources and fuels.

We could experience periods of higher costs. These cost increases could reduce our profitability, cash flow and ability to conduct development activities as planned. We rely on third-party contractors to provide key services and equipment for our operations. Historically, our capital and operating costs have risen during periods of increasing oil,natural gas, NGLs and gasoil prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling and completions activity increases; tariffs on foreign goods; and increased taxes. Increased levels of drilling activity in the natural gasgas, NGLs and oil industry could lead to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in our revenue, thereby negatively impacting our profitability, cash flow and ability to conduct development activities as planned and on budget.

Our debt obligations may limit our liquidity and financial flexibility. We are a borrower under fixed rate senior notes and maintain a floating rate bank credit facility which had no$118.0 debtmillion of borrowings as of December 31, 2024.2025. Our exploration and development program requires substantial capital resources depending on the level of drilling and the expected cost of services. Existing operations also require ongoing capital expenditures. Increases in our level of debt may:

require us to dedicate a substantialgreater portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations or return of capital to stockholders;

Any failure to meet our debt obligations could harm our business, financial condition and results of operations. Our earnings and cash flow will fluctuate from year to yearyear-to-year due to the variable nature of commodity prices. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek equity sales or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations and our financial flexibility. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives.

loss of title and other title-related land issues;

Our identified drilling locations are scheduled out over multiple years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Unless we successfully replace the reserves that we produce, our reserves will decline as reserves are depleted, eventually resulting in a decrease in production and lower revenues and cash flow from operations. Our management team has specifically identified and scheduled certain drilling locations for future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, obtaining lease agreements and managing lease expirations, transportation constraints, permits, regulatory and zoning approvals and other factors. Unless production is established within the spacing units covering acreage subject to an expiration, the leases for such acreage will expire. Because of these uncertain factors, our actual drilling activities may materially differ from those presently identified. In addition, we will require significant 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 drilling activities we are able to conduct on these locations may not be successful or result in our ability to add proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our business and results of operations and financial condition.

Additionally, we rely to a large extent on facilities owned and operated by third parties, in particular gas transportation and processing facilities, and damage to, or destruction of, those third-party facilities could affect our ability to process, transport and sell our production. To a limited extent, we maintain business interruption insurance related to threekey third-party processing plantsfacilities and connecting lines for our wells in Pennsylvania where we are insured for potential catastrophic losses from the interruption of production caused by a covered loss of or damage to the processing plants; however, such insurance is limited and may not adequately protect us from all potential consequences, damages and losses.

Additionally, local governments in Pennsylvania are authorized to adopt and implement ordinances and impose certain restrictions regarding siting of well sites, tank pads and other related facilities. Approval from one or more local governmental bodies, some following a public hearing, may be required before commencing construction of facilities which can result in delay, increased expense or, in some cases, prevention of development. Moreover, new initiatives or regulations could propose new setback distances or further restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of substances generated by our operations, including, but not limited to, produced water, drilling fluids and other wastes associated with our operations. For example, in January 2024, the DEP announced that it would implement a policy requiring natural gas well operators to disclose chemicals they use in drilling and hydraulic fracturing operations before the chemicals are used on-site. Further, in November 2024, Cecil Township, located in Washington County, Pennsylvania, adopted an ordinance that increased the setback distance for oil and gas operations from 500 feet to 2,500 feet from protected structures like residences and businesses and 5,000 feet from schools and hospitals,hospitals. See also above Land Use and separately,Setbacks. Separately, the DEP received a citizen petition for rulemaking to expand setback distances from natural gas operations across Pennsylvania. On December 9, 2025, the Pennsylvania Environmental Quality Board (PEQB) accepted the citizen petition for rulemaking moving the petition forward for the DEP’s review and study of the requested rulemaking. We do not expect action on the requested rulemaking for the foreseeable future and believe that the petition and requested rulemaking are unlawful. We will continue to monitor this petition, the requested rulemaking and any related developments to assess potential impacts to our operations. Currently there are a few states that have elected to ban or severely limit hydraulic fracturing. Should Pennsylvania or the federal government ban hydraulic fracturing, it would preclude economic development of our Marcellus Shale reserves potentially resulting in severe negative financial consequences to us.

Our business depends on natural gas and oil transportation and NGLs processing facilitiesfacilities, which are owned by others and depends on our ability to contract with those parties. Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of gathering and transportation pipeline systems, processing facilities, rail cars, trucks or vessels owned by third parties and our ability to contract with those third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Changes in intrastate pipeline rate design for Section 311 service could increase fixed transportation costs and reduce flexibility. If intrastate pipelines that provide interstate transportation under the Natural Gas Policy Act Section 311 adopt or maintain rate designs with higher fixed (reservation) charges, our transportation costs could increase and our flexibility to manage volumes through variable charges could decline. Because we depend on third‑party systems to gather and transport our production, higher fixed fees or related tariff changes could reduce our netbacks, contribute to curtailments in constrained periods, and adversely affect our results of operations and cash flows. See also aboveabove, Our producing properties are concentrated in Pennsylvania, making us vulnerable to risks associated with operating in one geographic and political region.

Although we have some contractual control over the transportation of our products, material changes in these business relationships, including the financial condition of the contractual counterparties, could materially affect our operations. In some cases, we do not purchase firm transportation on third-party facilities andand, as a result, our production transportation can be interrupted by those having firm arrangements. In other cases, we have entered into firm transportation arrangements where we are obligated to pay fees on minimum volumes regardless of actual volume throughput. If production decreases due to reduced or delayed developmental activities, the current commodity price environment, production related difficulties or otherwise, we may be unable to utilize all of our rights under existing firm transportation contracts, resulting in obligations to pay fees without receiving revenue from sales. Such fees may be significant and may have a material adverse effect on our operations. We have also entered into long-term agreements with third parties to provide natural gas gathering and processing services. In some cases, the capacity of gathering systems and transportation pipelines may be insufficient to accommodate production from existing and new wells. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelinespipelines, obstacles or impediments due to coal or other mineral extraction activities and general economic conditions could adversely affect our ability to produce, gather and transport natural gas, NGLs and oil. If any of these third-party pipelines or other facilities become partially or fully unavailable to transport or process our product, or if the natural gas quality specifications for a natural gas pipeline or facility change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected.

The natural gas industry is subject to extensive regulation. Natural gas, NGLs, oil and other hydrocarbons, as well as our operations to produce these products, are subject to extensive laws, regulations, and ordinances at the federal, state and local level. Further, new legislation, proposed rulemaking and ordinance amendments affecting the industry are under constant review foroften with more expansive requirements and rules on our products and operations. Compliance with new and expanding laws from numerous governmental departments and agencies often increases our cost of doing business, delays our operations and decreases our profitability.profitability and additional uncertainty can be introduced through varying court interpretations of such laws. Certain potential legislation, such as a ban on hydraulic fracturing, could even preclude our ability to economically develop our reserves.

Matters subject to laws and regulations affecting our business include, but are not limited to: the amount and types of substances and material that may be released into the environment, including GHGs; responding to unexpected releases of regulated substances or materials to the environment; the sourcing, transporttransportation and disposal of water used in the drilling and completions process; permits, performance rules and reporting obligations concerning drilling, completion and production operations; threatened or endangered species and waterway protection efforts; and climate related initiatives.

Environmental regulations and pollution liability could expose us to significant costs and penalties. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies or initiatives. Some of these environmental laws and regulations may impose strict, joint and several liability regardless of fault or knowledge, which could subject us to liability for conduct that was lawful at the time it occurred, or conditions caused by prior owners or operators or which relate to third partythird-party sites where we have taken materials for recycling or disposal. Pennsylvania law also imposes criminal liability for certain releases of substances, regardless of fault or intent. Failure to comply with these laws and regulations may result in the occurrence of delays, cancellations or restrictions in permitting or performance of our projects or other operations and subject us to administrative, civil and/or criminal penalties, corrective actions and orders enjoining some or all of our operations. Our operations may be impacted by new and amended laws and regulations andregulations, reinterpretations of existing laws and regulations or increased government enforcement relating to environmental laws. For example, properly handled drilling fluids and produced water are currently exempt from regulation as hazardous waste under RCRA, and instead are regulated under RCRA’s non-hazardous waste provisions. It is possible that the EPA may in the future propose rulemaking that designates such wastes as hazardous rather than non-hazardous, and a similar designation may be made at the state level. Should this occur at the federal and/or state level it could result in significant costs to attain and maintain compliance.

We may also be exposed to liability and costs for handling of hydrocarbons, air emissions and wastewater or other fluid discharges related to our operations and waste disposal practices. Spills or other unauthorized releases of hazardous or regulated substances by us, our contractors or resulting from our operations could expose us to material losses, expenditures and liabilities, including civil and criminal liabilities, in each case under environmental laws and regulationregulations and we are currently and have in the past been involved in such investigations, remediation and monitoring activities. The Pennsylvania Office of the Attorney General has publiclypreviously announced investigations and charges generally related to our industry in Pennsylvania. Additionally, neighboring landowners and other third parties may assert claims or file lawsuits against us for personal injury and/or property damage allegedly caused by the release of substances into the environment, with or without evidence of an impact from our operations, all of which could also result in significant litigation or settlement costs as well as reputational harm.

Laws and regulations pertaining to threatened and endangered species and protection of waterways could delay or restrict our operations and cause us to incur substantial costs. Various federal and state statutes prohibit actions or operations that adversely affect endangered or threatened species and their habitats. These statutes include the federal ESA, the Migratory Bird Treaty Act, the CWA, CERCLA and similar state programsprograms, including under the Pennsylvania Oil and Gas Act and the Clean Streams Law and related regulations. For example, the United States Fish and Wildlife Service as well as state agencies may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in material restrictions to land use and delay, restrict or even prevent our operations. For additional details, please refer to Governmental Regulation in Item 1, Environmental and Occupational Health and Safety Matters, specifically the Endangered Species Act section above. Similarly, operations may be impacted, delayed or even prevented by the existence of wetlands or other environmentally sensitive areas based upon the scope of the CWA and its protection of waters of the United States as well as state laws such as the Pennsylvania Clean Streams Law and related regulations and permitting requirements. We will continue to monitor changes to the federal definition of “waters of the United States,” proposed in November 2025 since jurisdictional shifts can affect permitting scope, timing, and mitigation requirements for certain of our activities.

Climate related regulations and initiatives could expose us to significant costs and restrictions on operations. There is an ongoing public debate as to the extent to which our climate is changing, the potential causes of climate change and its potential impacts. As part of that debate, there is general belief that increased levels of GHGs, including carbon dioxide and methane, have contributed to and continue to contribute to climate change which has led to numerous regulatory, political, litigation and financial risks associated with the production of fossil fuels and emissions of GHGs. OurOil operationsand resultnatural ingas GHGs.development generates GHG emissions.

Financial risks exist for fossil fuel energy companies, including natural gas producers, as in recent years, stockholders and bondholders are concerned about the potential effects of fossil fuels on climate change and may elect to shift some or all of their investments away from fossil fuel based energy. Institutional lenders who provide financing to fossil fuel energy companies are at times under pressure from activists and are the subject of lobbying to not provide funding for fossil fuel production, although this trend has recently decreased. Also,For example, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network of Greening the Financial System, of which the Federal Reserve is a member, to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. InHowever in January 2025, the Federal Reserve issued a statement announcing it has withdrawn from the Network of Central Banks and Supervisors for the Greening of the Financial System. SomeDespite ofthe thesedeclining trend, some institutional lenders may elect not to provide funding for us which could result in restriction, delay or cancellation of drilling programs, development or production activities or impair our ability to operate economically.

On March 6, 2024, the SEC adopted rules that would require public companies to disclose extensive climate change-related information in certain of their SEC filings. However, on March 15, 2024, a federal appellate court imposed a temporary stay pending judicial review of such new rules, and in response, on April 4, 2024, the SEC issued an order staying any amendments to such rules pending the completion of judicial review of the federal appellate court petitions. On February 11, 2025, the acting chairman of the SEC released a statement that he has directed the SEC staff to request that the court not schedule the case for argument to provide time for the SEC to deliberate the appropriate next steps in litigation related to The Enhancement and Standardization of Climate-Related Disclosures for Investors rule. On March 27, 2025, the SEC commissioners voted to end the defense of The Enhancement and Standardization of Climate-Related Disclosures for Investors rule. While the finalSEC formhas ceased defending the previously approved climate disclosure rules and substancenotified ofthe thesecourt rulesaccordingly (leaving them stayed and unlikely to take effect under the current administration), other state-level jurisdictions have already implemented or are notcurrently yetdeveloping knownclimate anddisclosure therequirements ultimatefor scopelarge andcompanies impactthat on our business is uncertain, compliance with the rules may resultoperate in increasedtheir legal, accounting, operational, technology and financial compliance costs.jurisdictions.

Certain organizations that provide corporate governance and other corporate risk information to investors and stockholders have developed scores and ratings to evaluate companies and investment funds based on sustainability or environmental, social and governance ("ESG") metrics. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and stockholders. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through investment and voting practices of investment advisors, public pension funds, universities and other members of the investing community. As a result, many investment funds focus on positive ESG business practices and sustainability scores when making investments. Companies which do not adapt to or comply with investor or stockholder ESG expectations and standards or which are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the financial condition, results of operations or cash flows of such a company could be materially and adversely affected.affected, or could also have limited access to certain capital markets.

Information concerning our reserves and future net cash flow are estimates and may not match our results. There are numerous uncertainties inherent in estimating quantities of proved natural gasgas, NGLs and oil reserves and their values, including many factors beyond our control. Estimates of proved reserves depend on many assumptions relating to current and future economic conditions and commodity prices as well as the projected productivity of our wells and infrastructure to gather, process, store and/or transport our products to market. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we utilize robust processes and procedures to evaluate and estimate our reserves, they are estimates and the actual production, revenues and costs to develop our estimated reserves will vary from estimates and these variances could be material and/or negative.

U.S. or state tax legislation may adversely affect our business, results of operations, financial condition and cash flow .flow. Legislation is periodically proposed that could make significant changes to United States federal income tax laws and could include the elimination of certain United States federal income tax benefits currently available to oil and gas exploration and production companies including, but not limited to, (i) the repeal of percentage depletion allowances for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs and; (iii) an extension of the amortization period for certain geological and geophysical expenditures. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for our products. The passage of any such legislation or any other similar change in United States federal income tax law could increase costs or eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development and any such changes could have an adverse effect on our financial condition, results of operations and cash flows.

Common stockholders may be diluted if additional shares are issued. In order to align interests and encourage ownership, we issue restricted stock, restricted stock units and performance share units to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional senior notes or other securities or debt convertible into common stock to extend maturities or fund capital expenditures, including acquisitions. The issuance of additional shares of common stock results in dilution of the interests of existing stockholders. One way to reverse the effects of dilution is by the acquisition of our stock. On December 31, 2024,2025, our share repurchase program had $1.0$785.5 billionmillion remaining.remaining authorization. However, this program may be suspended, modified or discontinued by theour board of directors at any time.

cybersecurity threats to gain unauthorized access to sensitive information or to render data or computer systems unusableunusable, which may become more sophisticated with the use of artificial intelligence;

We are an independent natural gas, NGLs and oil company engaged in the exploration, development and acquisition of natural gasgas, NGLs and oil properties located in the Appalachian region of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We measure financial performance as a single enterprise and not on an area-by-area basis.

Our overarching business objective is to build stockholder value through returns-focused development of natural gas, NGLs and oil properties. Our strategy to achieve our business objective is to generate consistent cash flows from reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions and divestitures of non-core or, at times, core assets.divestitures. Currently, our investment portfolio is focused on high quality natural gas and NGLs assets in the stateCommonwealth of Pennsylvania. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and oil and on our ability to economically find, develop, acquireacquire, produce and producesell natural gas, NGLs and oilthese reserves.

Commodity prices have been and are expected to remain volatile. We believe we are well-positioned to manage any challenges that could occur during a low commodity price environmentvariations and that we can endure the continued volatilityfluctuations in current and future commodity prices by:

managing price risk through thepartial hedging of our production; and managing our balance sheet.

the quantity of natural gas, NGLs and oil shown as proved reserves; and our ability to borrow and raise additional capital, if needed.

We believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large producing nations, the Russia-Ukraine conflict, hostilitiestensions in the Middle East, global inventories of natural gas, NGLs and oil, future U.S infrastructure investment, future monetary and fiscal policypolicy, tariffs and their impacts on global trade and energy demand and governmental policies aimed at transitioning towards lower carbon energy,energy. and weWe expect prices for commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global energy markets. InDuring fourth quarter 2024,2025, natural gas prices declinedincreased basedprimarily ondue theto relativelyincreased mildexports earlyfrom daysnew ofU.S. winterLNG inexport the United States.facilities. Longer term natural gas futures prices remain strongerconstructive based on market expectations that associated gas-related activity in oil basins and dry gas basin activity will show modest rates of growth due to infrastructure constraints, moderated reinvestment rates and core inventory exhaustion. In addition, the global energy crisisshortage experienced in recent years further highlighted the lowneed costfor affordable and lowreliable emissionsfuel shale gas resource base in North America,sources, supporting continued strong structural demand growth for United States liquefied natural gasLNG exports, as well as domestic industrial gas demand and powerelectricity generation. Other factors such as geopolitical disruptions, supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace and changes in global monetary policy may impact theglobal demand for natural gas, NGLs and oil. We continue to assess and monitor the impact and consequences of these factors on our business and operations.

PricesBenchmarks for various quantities of natural gas,gas increased in 2025 compared to 2024, while NGLs andslightly oildecreased. thatAs a result, we producehave significantlyexperienced impactincreases in our revenuesprice andrealizations cashin flows. Prices for commodities, such as hydrocarbons, are inherently volatile.2025. Recently, benchmark natural gas prices have increased whenfurther compared to the fourth quarter 2024,2025, with the average NYMEX monthly settlement price for natural gas increasing to $3.51$4.69 per mcf for January 2026 and $3.54 per mcf$7.46 for February 20252026 settlement following cold winter weather. Oil prices slightly increased from December 2024, to $75.10 per barrel in January 2025. The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the years ended December 31, 20242025 and 2023.2024.

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Our price realizations (not including the impact of our derivatives) may differ from the benchmarks for many reasons, including quality, location, or production being sold at different prices.

Our revenues vary from year to yearyear-to-year as a result of changes in realized commodity prices and production volumes. In 2024, natural gas, NGLs and oil sales decreased 5% from 2023 with a 7% decrease in realized prices (excluding cash settlements on our derivatives) partially offset by slightly higher production volumes. The following table illustrates the primary components of natural gas, NGLs and oil sales for the last two years (in thousands):

We believe we are positioned for sustainable long-term success. We continue to monitor the impact of the actions of OPEC and other large hydrocarbon producing nations; the Russia-Ukraine war,war; military action in the Middle East and flows of energy commodities through the Strait of Hormuz; global inventories of natural gas, NGLs and oil; future U.S. infrastructure investment; future monetary and fiscal policy,policy; tariffs and their impacts on global trade and energy demand; and governmental policies aimed at the energy sector, including those focused on transitioning towards lower carbon energy. We expect prices for the commodities we produce to remain volatile given the complex dynamics of supply and demand that exist in the global energy markets. In first threesix months 2026, average natural gas prices increased primarily due to increased demand from winter weather and liquefied natural gas ("LNG") export growth. Longer termLonger-term natural gas futures prices remain constructive based on market expectations of continued LNG export expansion and increasing global power demand, while associated gas-related activity in oil basins and dry gas basin activity are expected to show modest rates of growth due to infrastructure constraints, moderated reinvestment rates and inventory exhaustion.deterioration. In addition, the global energy shortage experienced in recent years and geopolitical disruptions of energy flows from key producing regions further highlighted the need for affordable and reliable fuel sources, supporting continued strong structural demand growth for U.S. LNG exports, as well as domestic electricity generation. Other factors such as supply chain disruptions, cost inflation, concerns over a potential economic recession and the pace of changes in global monetary policy may impact global demand for natural gas, NGLs and oil. We continue to assess and monitor the impact of these factors on our business and operations.

The following table lists related benchmarks for natural gas, oil and NGLs composite prices for the three and six months ended MarchJune 31,30, 2026 and 2025:

Overview of FirstSecond Quarter 2026 Results

In firstsecond quarter 2026, we experienced an increase in revenue from the sale of natural gas, NGLs and oil when compared to the same quarter of 2025, due to a 29%2% increase in net realized prices (average prices including all derivative settlements and third-party transportation costs paid by us) andcombined with a slight5% increase in total production.

During firstsecond quarter 2026, we recognized net income of $341.6$195.3 million, or $1.44$0.83 per diluted common share compared to net income of $97.1$237.6 million, or $0.40$0.99 per diluted common share during firstsecond quarter 2025. The higherlower net income in firstsecond quarter 2026 compared to firstsecond quarter 2025 is primarily due to increasedlower realizedderivative prices.fair value income.

Our firstsecond quarter 2026 financial and operating performance included the following results:

revenue from the sale of natural gas, NGLs and oil increased 28%5% from the same period of 2025 due to a 27%1% increase in average realized prices (before cash settlements on our derivatives) combined with a slight5% increase in production volumes;

direct operating expense per mcfe increased to $0.14$0.13 induring firstsecond quarter 2026 compared to $0.13$0.11 induring the same period of 20252025, primarily due to anhigher increasewater inhauling, winterlabor operationscosts and water hauling costsworkovers;

transportation, gathering, processing and compression per mcfe increasedremained toflat $1.63at $1.52 in firstsecond quarter 2026 compared to $1.55 in the same period of 2025, primarily due to an increase in electricity rates and fuel prices2025;

general and administrative expense per mcfe increased to $0.23 in firstsecond quarter 2026 compared to $0.21 in the same period of 20252025, primarily due to higher employee relatedemployee-related costs and legal expense; and interest expense per mcfe decreased 33%46% from the same period of 2025 due to lower debt balances and lower interest rates.

FirstSecond quarter 2026 also included the following returns of capital and balance sheet highlights:

repurchased $27.1$78.4 million (800,0002.0 million shares) of our common stock;

paid $23.8$23.6 million of dividends, an 11% higher dividend of $0.10 per share compared to $0.09 per share in the same period of 2025; and reducedmaintained oursubstantial higherliquidity interest rate debt by paying off the $600 million principal balance of our 8.25% senior notes due 2029 by utilizing borrowings under the credit facility, while retainingwith $1.5 billion in available liquidity under our credit facility.

We generated $619.1$235.0 million of cash from operating activities in firstsecond quarter 2026, ana increasedecrease of $289.1$101.2 million from firstsecond quarter 2025, whichprimarily reflectsdue theto impacttiming ofand higherworking realizedcapital prices.changes.

Our revenues vary primarily as a result of changes in realized commodity prices and production volumes. Our revenues are generally recognized when control of the product is transferred to the customer and collectability is reasonably assured. The following table illustrates the primary components of natural gas, NGLs and oil sales for the three and six months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Production growth is generated as new wells are placed in production, which is partially offset by the natural decline in production throughof existing wells. Our production for the three and six months ended MarchJune 31,30, 2026 and 2025 is set forth in the following table:

Our average realized price received (including all derivative settlements and third-party transportation costs) during second quarter 2026 was $2.01 per mcfe compared to $1.97 per mcfe in second quarter 2025. Our average realized price received (including all derivative settlements and third-party transportation costs) during first quartersix months 2026 was $3.21$2.60 per mcfe compared to $2.48$2.22 per mcfe in first quartersix months 2025. Our average realized prices (excluding derivative settlements) do not include derivative settlements or third-party transportation costs which are reported in transportation, gathering, processing and compression expense in the accompanying consolidated statements of income. Our average realized prices (including derivative settlements) do not include transportation costs where we receive net revenue proceeds from purchasers. Our average realized prices (including derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives. We believe computed final realized prices should include the total impact of transportation, gathering, processing and compression expense. Our average realized price calculations for three and six months ended MarchJune 31,30, 2026 and 2025 are shown below:

Transportation, gathering, processing and compression expense was $323.3$316.8 million in firstsecond quarter 2026 compared to $306.1$304.7 million in firstsecond quarter 2025. These third-party costs arewere higher in firstsecond quarter 2026 compared to firstsecond quarter 2025 primarily due to an increase in processing costs due to higher electricitycommodity ratesprices and fuel prices. We have included these costs in the calculation of average realized prices (including derivative settlements and third-party transportation expenses paid by Range). The following table summarizes transportation, gathering, processing and compression expense for the three months ended March 31, 2026 and 2025 on a per mcf and per barrel basis (in thousands, except for costs per unit):volumes.

Derivative fair value lossincome was $33.4$73.5 million in second quarter 2026 compared to income of $154.7 million in second quarter 2025. Derivative fair value income was $40.1 million in first quartersix months 2026 compared to a loss of $159.0$4.2 million in first quartersix months 2025. All of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment can result in more volatility of our revenues as the change in the fair value of our commodity derivative positions is included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate potentially lower wellhead revenues in the future while derivative losses indicate potentially higher future wellhead revenues. The following table summarizes the impact of our commodity derivatives for the three and six months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Brokered natural gas, NGLs and marketing revenue was $57.2$57.5 million in firstsecond quarter 2026 compared to $54.4$33.0 million in firstsecond quarter 2025, which is primarily the result of higher commoditybroker pricesnatural offset by lower brokergas sales volumes (volumes not related to our production). slightly offset by lower broker natural gas sales prices. Brokered natural gas, NGLs and marketing revenue was $114.7 million in first six months 2026 compared to $87.4 million in first six months 2025, which is the result of higher broker natural gas sales volumes (volumes not related to our production) slightly offset by lower broker natural gas sales prices. We continue to optimize our transportation portfolio using these volumes. See also Brokered natural gas, NGLs and marketing expense below for more information on our net brokered margin.

Other income was $118,000$448,000 in firstsecond quarter 2026 compared to $3.2$1.9 million in firstsecond quarter 2025. This includes $55,000$27,000 of interest income and a $6,000$23,000 gain on sale of assets in second quarter 2026 compared to $1.8 million of interest income and a $78,000 gain on sale of assets in second quarter 2025. Other income was $566,000 in first six months 2026 compared to $5.1 million in first six months 2025. This includes $82,000 of interest income and a $29,000 gain on sale of assets in first quartersix months 2026 compared to $3.1$4.8 million of interest income and a $62,000$136,000 gain on sale of assets in first quartersix months 2025. Interest income is lower in 2026 due to lower cash balances primarily resulting from the use of cash to repay senior notes in May 2025.

We believe some of our expense fluctuations are best analyzed on a unit-of-production or per mcfe basis. The following table presents information about certain of our expenses on a per mcfe basis for the three and six months ended MarchJune 31,30, 2026 and 2025:

Direct operating expense was $28.7$27.8 million in firstsecond quarter 2026 compared to $25.4$23.1 million in firstsecond quarter 2025. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workover costs and repair-related expenses. Our direct operating costs increased in firstsecond quarter 2026 primarily due to higher water hauling costs, labor costs and winter operations costs.workovers. We incurred $644,000$1.8 million of workover costs in firstsecond quarter 2026 compared to $789,000$803,000 in firstsecond quarter 2025. The following table summarizes direct operating expense per mcfe for the three months ended March 31, 2026 and 2025:

GeneralDirect and administrative (G&A)operating expense was $45.4$56.5 million in first quartersix months 2026 compared to $41.7$48.5 million in first quartersix months 2025. TheOur direct operating costs increased in first quartersix months 2026 increase of $3.7 million compared to the same period of 2025 is primarily due to higher employeewater relatedhauling, costs.labor costs and workovers. We incurred $2.4 million workover costs in first six months 2026 compared to $1.6 million in first six months 2025. The following table summarizes G&Adirect operating expense on a per mcfe basis for the three and six months ended MarchJune 31,30, 2026 and 2025:

InterestG&A expense was $19.4$93.1 million in first quartersix months 2026 compared to $29.2$83.8 million in first quartersix months 2025. The increase of $9.2 million is primarily due to higher employee-related costs, software costs and legal expense. The following table presentssummarizes information about interestG&A expense on a per mcfe basis for the three and six months ended MarchJune 31,30, 2026 and 2025:

The decrease in interest expense for three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods of 2025 was primarily due to lower average outstanding debt balances and lower average interest rates. In January 2026, we repaid the $600 million principal balance of our 8.25% senior notes due 2029 by utilizing borrowings on our credit facility. In May 2025, we repaid the remaining principal balance of $606.5 million of our 4.875% senior notes due 2025 by utilizing cash on hand and borrowing on our credit facility. We had $334.0$381.0 million outstanding on the bank credit facility as of MarchJune 31,30, 2026 compared to no$125.0 bank debtmillion outstanding for the same period of 2025.

Depletion, depreciation and amortization ("DD&A") expense was $88.5$93.1 million in firstsecond quarter 2026 compared to $90.6$91.5 million in second quarter 2025 and $181.6 million in first quartersix months 2026 compared to $182.1 million in first six months 2025. This decreaseincrease isin expense for the quarter ended June 30, 2026 compared to the prior year was due to ahigher production volumes slightly offset by lower depletion raterates. offsetThe bydecrease slightlyin higherexpense productionfor volumes.the six months ended June 30, 2026 compared to prior year was primarily due to the reduction in the depletion rate. Depletion expense, the largest component of DD&A expense, was $0.44 per mcfe in second quarter 2026 and first quartersix months 2026 compared to $0.45 per mcfe in the same periodperiods of 2025. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. The following table summarizes DD&A expense per mcfe for the three and six months ended MarchJune 31,30, 2026 and 2025:

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, brokered natural gasgas, NGLs and marketing expense, exploration expense, abandonment and impairment of unproved properties, exit costs, deferred compensation plan expense and lossgain on early extinguishment of debt. Stock-based compensation includes the amortization of restricted stock grants and performance units. See Note 9 to our consolidated financial statements for more information on allocation of stock-based compensation by functional expense categories.

Brokered natural gas, NGLs and marketing expense was $58.1$59.3 million in firstsecond quarter 2026 compared to $58.2$35.0 million in firstsecond quarter 2025 duewhich tois primarily the result of higher commodity prices slightly offset by lower broker purchasenatural gas sales volumes (volumes not related to our production). slightly offset by lower broker natural gas sales prices. Brokered natural gas, NGLs and marketing expense was $117.5 million in first six months 2026 compared to $93.2 million in first six months 2025 which is primarily the result of higher broker natural gas sales volumes (volumes not related to our production) slightly offset by lower broker natural gas sales prices. The following table details our brokered natural gasgas, NGLs and marketing net margin for the three and six months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Exploration expense was $6.0$6.5 million in firstsecond quarter 2026 compared to $6.4$7.9 million in firstsecond quarter 2025 mainlyprimarily due to lower delay rentalsrentals. somewhatExploration offsetexpense bywas higher$12.5 personnelmillion expense.in first six months 2026 compared to $14.3 million in first six months 2025 primarily due to lower delay rentals. The following table details our exploration expense for the three and six months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Abandonment and impairment of unproved properties expense was $3.9$4.6 million in firstsecond quarter 2026 compared to $4.6$6.8 million in firstsecond quarter 2025. Abandonment and impairment of unproved properties expense was $8.5 million in first six months 2026 compared to $11.4 million in first six months 2025. Abandonment and impairment of unproved properties for firstsecond quarter 2026 and first six months 2026 decreased when compared to the same periodperiods of 2025 due to lower than expected lease expirations in Pennsylvania. When we do not intend to drill on a property prior to expiration, we have allowed acreage to expire. We also expect to strategically allow expirations in the future, as we believe certain acreage needed for our future development plans can be efficiently leased again prior to development.

Exit costs were $7.0$9.6 million in firstsecond quarter 2026 compared to $8.9$8.5 million in second quarter 2025. Exit costs were $16.5 million in first quartersix months 2026 compared to $17.4 million in first six months 2025. These costs are associated with normal accretion expense primarily related to retained liabilities for certain gathering, transportation and processing obligations extending through 2030. There was an additional $2.9 million of exit costs incurred in second quarter 2026 associated with the change in expected throughput volumes associated with this obligation.

Deferred compensation plan had a lossgain of $2.5$1.8 million in firstsecond quarter 2026 compared to a lossgain of $2.9$88,000 in second quarter 2025. Deferred compensation plan expense was $787,000 in first six months 2026 compared to an expense of $2.8 million in first quartersix months 2025. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense based on the number of vested shares in the plan at the time. The change in both periods is related to the change in Range stock price at the end of each period combined with fewer shares being held within the deferred compensation plan. The deferred compensation plan held 248,000199,000 shares (237,000187,000 vested shares) of Range common stock as of MarchJune 31,30, 2026 compared to 621,000265,000 shares (609,000256,000 vested shares) as of MarchJune 31,30, 2025.

Income tax expense was $91.5$53.3 million in firstsecond quarter 2026 compared to an expense of $12.7$64.5 million in second quarter 2025. Income tax expense was $144.8 million in first quartersix months 2026 compared to an expense of $77.1 million in first six months 2025. The 2026 effective tax rates were not materially different than the federal statutory rate. The 2025 effective tax rates were lowerdifferent than the federal statutory ratetax rates due primarily to tax credits, state income taxes and equity compensation.

Commodity prices are the most significant factor impacting our revenues, net income, operating cash flows, and the amount of capital we have available to invest in our business, pay dividends and fund share or debt repurchases. Commodity prices have been and are expected to remain volatile. Our top priorities for using cash provided by operations are to fund our capital program, return capital to stockholders,stockholders and maintain a strong balance sheet while making prudent investments in our business. We currently believe we have sufficient liquidity and capital resources to execute our business plan for the foreseeable future and across a wide range of commodity price scenarios. We continue to manage the duration and level of our drilling and completion commitments in order to maintain flexibility with regard to our activity level and capital expenditures.

The following table presents sources and uses of cash and cash equivalents for the threesix months ended MarchJune 31,30, 2026 and 2025 (in thousands):

Cash flows provided from operating activities in first threesix months 2026 were $619.1$854.2 million compared to $330.1$666.3 million in first threesix months 2025. Cash provided from operating activities is largely dependent upon commodity prices and production volumes, net of the effects of settlement of our derivative contracts. As of MarchJune 31,30, 2026, we have hedged more than 35%25% of our projected natural gas production for the remainder of 2026. Changes in working capital (as reflected in our consolidated statements of cash flows) for first threesix months 2026 was a positivenegative $79.5$12.0 million compared to a negative $61.4$18.0 million for first threesix months 2025.

Borrowings on credit facility in first threesix months 2026 were $1.2$1.7 billion, of which approximately $608$608.3 million was utilized for the early redemption of principal of our 8.25% senior notes due 2029. Borrowings net of repayments on the credit facility for the first threesix months 2026 brought the credit facility balance to $334.0$381.0 million as of MarchJune 31,30, 2026.