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Company Presentation October 2025
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Forward-Looking Statements 2 All statements, except for statements of historical fact, made within regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future, such as those regarding future well costs, expected asset sales, well productivity, future liquidity and financial resilience, anticipated exports and related financial impact, NGL market supply and demand, future commodity fundamentals and pricing, future capital efficiencies, future shareholder value, emerging plays, capital spending, anticipated drilling and completion activity, acreage prospectivity, expected pipeline utilization and future guidance information, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and Range's future performance are subject to a wide range of business risks and uncertainties and there is no assurance that these goals and projections can or will be met. Any number of factors could cause actual results to differ materially from those in the forward- looking statements. Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission (SEC), including its most recent Annual Report on Form 10-K. Unless required by law, Range undertakes no obligation to publicly update or revise any forward-looking statements to reflect circumstances or events after the date they are made. The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose its probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. “EUR”, or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.
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Range – Who We Are 3 Top 10 U.S. Producer of Natural Gas & NGLs Pure Play Appalachian Producer with 30+ Years of Core Marcellus Inventory Durable Free Cash Flow Paired with Efficient Growth Access to Growing Demand in Domestic and International Markets Strong Balance Sheet to Deliver Durable Long-Term Capital Returns Upstream Leader in Environmental Practices
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Range – Positioned to Deliver Value Through the Cycles 4 Unmatched Position in Southwest Appalachia • 30+ Years of High-Quality Marcellus Inventory to Meet Long-Term Demand Growth Durable Free Cash Flow with Efficient Growth • History of Generating Free Cash Flow through Commodity Cycles • Expect to Grow Production ~20% through 2027 at <50% Reinvestment Rate Peer-Leading Capital Efficiency • Large Contiguous Acreage Position Supports Efficient Operations and Peer-Leading Well Costs Diversified Market Outlets • Diverse Access to Multiple Domestic and International Markets for Natural Gas and NGLs Strong Balance Sheet • Leverage Below 1x Debt/EBITDAX Growing Demand for Reliable, Affordable, Clean Energy • Supportive Outlook as Natural Gas and NGLs Play a Key Role in Meeting Global Energy Demand Growth • Achieved Net Zero for 2024 Scope 1 and 2 GHG Emissions
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<$2.00 <$2.50 <$3.00 <$4.00 Unmatched Core Marcellus Inventory 30+ Years of High-Quality Marcellus Inventory 5 Notes: Highlighted areas represent townships where Range holds ~2,000 or more acres. a) PV10 breakeven price per well includes all-in well costs, gathering, processing, transport, pricing differentials, LOE and production taxes. WTI/NGL realization (% of WTI) used for the cases are $2: $50/45%, $2.50: $60/42.5%, $3: $70/40%. b) Based on 2025 activity levels. ~440,000 Net Acres in Southwest Pennsylvania ~70,000 Net Acres in Northeast Pennsylvania 28 Million Lateral Feet of Undrilled Marcellus at YE 2024 $/MMbtu Breakeven(a) >30 Years(b) of Undrilled Marcellus Inventory Breaks Even Under $2.50 Utica/Point Pleasant and Upper Devonian Further Extend Range’s Inventory Life
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Oil-Linked Gas-Linked Mont Belvieu . Global Sales Portfolio Concentrated Marcellus Assets Access Multiple End-Markets for Natural Gas and NGL Price Diversification MidwestGulf Coast LNG Local & Northeast Exports Local & Northeast . Natural Gas End-Markets Ethane Price Diversification Propane & Butane Exports 6 Natural Gas & NGL NGL Export LNG Export / Premium Gulf ~30% of Natural Gas to Midwest ~25% of Natural Gas to Gulf Coast ~25% of Natural Gas to LNG and Premium Gulf Markets ~20% of Natural Gas to Local & Northeast
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$656 $1,580 $513 $453 $486 $- $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2021 2022 2023 2024 YTD 2025 (9 Mos.) RRC Free Cash Flow ($ MM)(a) YTD 2025 (9 Mos.) Sustainable Free Cash Flow and Capital Returns Supported by Low Capital Intensity, NGL Uplift, and Hedging (a) Cash flow from operations before working capital less capital expenditures History of Durable Free Cash Flow 7
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Three-Year Outlook Efficient Growth into Increasing Demand 8 Three-Year Outlook ▪ Cumulative 2025-2027 FCF of >$2 billion (a) ▪ $650 - $700 million annual capex 2025-2027 ▪ <50% reinvestment rate at $3.75 NYMEX natural gas while growing production ▪ Adds ~400 Mmcfe to daily production Growth Wedge into Increasing Demand ▪ 300 Mmcf/d incremental processing secured ▪ 250 Mmcf/d incremental natural gas takeaway accesses growing demand in Midwest and Gulf Coast markets ▪ 20 MBD NGL takeaway and export capacity utilizing new East Coast terminal Beyond 2027 ▪ Free cash flow breakeven of ~$2.00 NG / $75 WTI / $25 NGLs ▪ Ability to maintain 2.6 Bcfe per day production with only $570 million D&C per year, or ~$0.60 per Mcfe ▪ 30+ years of Marcellus inventory can support additional growth to meet in-basin demand (a) Free cash flow represents cash from operations before working capital less capital expenditures. Assumes effective cash tax r ate of 2% in 2025, 5% in 2026, and 8% in 2027. (b) 2025 EBITDAX and free cash flow estimates are based on FactSet consensus as of 10/27/25. (c) 2026 and 2027 EBITDAX and free cash flow are RRC estimates assuming $3.75 NYMEX NG, $70 WTI, and $25 NGL realizations. 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 2024A 2025E 2026E 2027E Daily Production (Mmcfe) EBITDAX and Free Cash Flow ($ MM)(a) Analyst FCF Pre-Tax FCF EBITDAX Production (b) (c) (c)
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Increasing Capital Returns Low Required Reinvestment Rate While Growing Provides Significant Shareholder Return Potential 9 <50% Reinvestment Rate(a) at $3.75 NYMEX Natural Gas Supports Potential Shareholder Return Increases While Growing Production (a) Reinvestment rate represents estimated total capital expenditures / cash flow from operations before working capital. (b) 2025 estimates are based on FactSet consensus as of 10/27/25. (c) 2026 and 2027 are RRC estimates assuming $3.75 NYMEX NG, $70 WTI, and $25 NGL realizations. 35% 40% 45% 50% 55% 60% 65% $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2024A 2025E 2026E 2027E Reinvestment Rate Cash Flow From Operations Before Working Capital ($ MM) Capex Dividends Repurchases/Dividend Increases/Net Debt Reduction Reinvestment Rate (b) (c) (c)
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$520 $80 - $100 $20 - $30 ~$30 $650 - $680 2025 Maintenance Capital Future Growth 2025 Pneumatic Devices/Other 2025 Incremental Land 2025 Capital $ Million 2025 Capital Investments Enhance Three-Year Growth Capacity 10 (a) 2025 Maintenance Capital for 2.18 Bcfe/d. Includes $25 - $35 million to maintain existing leases. Maintenance land spending will decrease over time as more of Range’s acreage is held-by-production. (b) Pneumatic Upgrade capital is expected to be completed by year-end 2026. Additional In-Process Well Inventory Adds up to 500k lateral feet of inventory (a) (b) Pneumatic Devices and Production Facility Upgrades ~$30 Million Land Operational Plan Supports Efficient Wedge of Production Growth through 2027 Maintenance D&C Capital Improved to ~$490 Million
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0% 20% 40% 60% 80% 100% 120% Peer 1 Peer 2 Peer 3 RRC Peer 4 Peer 5 Peer 6 2025 2026 $14 $28 $48 $68 Standardized Measure $3.00 $4.00 $5.00 NYMEX Natural Gas (a) Bloomberg sector estimates as of 10/24/25. RRC FCF assumes $3.00 NG/$70 WTI, $3.75 NG/$75 WTI, $4.50 NG/$80 WTI, and NGL realizations at 33% of WTI. RRC EV/EBITDA is Bloomberg consensus. Valuation of proved reserves only includes 2.9 million lateral feet (~10%) of Range’s ~28 million lateral feet of undeveloped core Marcellus inventory Compelling Free Cash Flow and Valuation Range Offers Durable Free Cash Flow and Attractive Relative Trading Multiple and Yield versus Other Sectors 2025 FCF Yield(a) 2026 EV/EBITDA(a) 11 RRC at $4.50 NG RRC at $3.75 NG RRC at $3.00 NG ATAX PV-10(b) of Proved Reserves per Share, Net of Debt b) ATAX PV-10 for $3/$4/$5 cases use $70/$80/$90 WTI, respectively. Assumes 21% tax rate in all cases, without accounting for expected NOL benefit. Year-end 2024 standardized measure value of $4.7 billion uses SEC-defined pricing of $2.13 natural gas/$74.88 WTI. ( c) Enverus estimates assuming strip price as of 9/11/25. Reinvestment rate represents estimated capital expenditures / (capital expenditures + free cash flow). Peers include AR, CNX, CRK, EQT, EXE, GPOR. ( Low reinvestment rate while growing production Reinvestment Rate (% of Cash Flow)(c) 6.2x 10.5x 12.5x 13.2x 14.7x 14.9x 15.5x 17.3x 18.0x 20.1x 0.0x 5.0x 10.0x 15.0x 20.0x 25.0x RRC Telecom Materials Healthcare Con. Staples Russell 3000 Con. Discretionary Industrials Real Estate Tech 2.2% 2.3% 3.0% 3.1% 3.1% 3.1% 3.4% 3.5% 4.7% ~13% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% Con. Discretionary Tech Russell 3000 Telecom Industrials Materials Con. Staples Real Estate Healthcare RRC
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Why Invest in Range? 12 • Large Contiguous Acreage Position Provides 30+ Years of Low-Breakeven, High-Return Marcellus Inventory • Resilient Free Cash Flow Given Peer-Leading Well Costs and Decline Rate, Low Capital Intensity, and Liquids Pricing Uplift • Low Required Reinvestment Supports Significant Free Cash Flow Generation while Growing Production into Increasing Demand • Diversified Access to Multiple Domestic and International Markets for Natural Gas and NGLs • All of the Above Position Range to Generate Free Cash Flow through Cycles and Increase Returns to Shareholders as Energy Demand Continues to Grow
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Natural Gas & NGL Macro 13
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▪ Between 2005 and 2024, U.S. energy emissions declined while total global energy emissions increased ~26% ▪ Despite several IEA calls over the last decade that coal demand would peak, global coal demand hit record highs in 2023 and 2024, highlighting the need for more natural gas and renewable energy ▪ China and India energy emission growth more than offset the decrease in U.S. emissions as their coal demand continues to surge Natural Gas Plays Key Role in Reducing Emissions 14 U.S. CO2 Emissions Reductions Driven by Coal Displacement (MMT)(a) ~14 Bcf/d ▪ Between 2005 and 2024, total U.S. energy emissions declined ~21%, driven by ~41% decline in emissions from power generation ▪ EIA attributes ~60% of U.S. power generation emissions reductions to natural gas displacing coal ▪ Gas can play a similar vital role in global emissions reductions by replacing coal for baseload generation 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,000 4,500 5,000 5,500 6,000 6,500 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Power Gen. & All Other Sector Total Energy Total Energy Emissions Power Gen. Emissions All Other Sector Emissions Coal Consumption & CO2 Emissions from Energy (2005-2024 Change)(b) (a) Source: EIA (b) Source: Energy Institute Statistical Review of World Energy 2025 -21% -29% 85% 145% 27% 34% 26% -65% -54% 66% 160% 52% 0% 27% -20 -10 0 10 20 30 40 50 60 70 -2,000 -1,000 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 U.S. EU China India Other Asia Other TOTAL Coal Consumption (EJ) CO2 Emissions from Energy (MMT) CO2 Emissions from Energy Coal Consumption
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Growing Market Share in U.S. Power Generation ▪ Gas power demand grew by 16 Bcf/d from 2010-2024, while coal declined 22 Bcf/d(c) and renewables grew 11 Bcf/d(c) ▪ Natural gas has grown to 43% of the U.S. generation mix Market Share Growth Should Continue ▪ Approximately 12 Bcf/d of coal generation remains to be displaced, or ~15% of U.S. Power Generation Mix ▪ 104 GW of coal plant capacity retired from 2013-2023, and another 36 GW of coal plant retirements have been announced for 2024-2030 ▪ Increased electrification, industrial reshoring, EV growth, and data centers to boost power demand. Modest new nuclear and challenged renewable returns in some regions require natural gas to fill the supply gap. ▪ New gas-fired reciprocating engines being added to balance grid instability issues created by renewables Global Power Generation Opportunity ▪ Coal generation remains ~34% of global power generation, or ~204 Bcf/d(c) ▪ Electrification of global economies and global AI data centers will increase power demand, a significant portion of which will be supplied by natural gas ▪ China and India are increasing natural gas use in efforts to reduce emissions intensity ▪ Coal generation remains ~58% of China’s power generation mix (~112 Bcf/d(c)) and ~75% of India’s power generation mix (~29 Bcf/d(c)) Natural Gas Benefiting from Coal Displacement and Electrification 15 U.S. Power Generation by Source(a) (a) Source: EIA (b) Source: Energy Institute Statistical Review of World Energy 2025 (c) Assumes 7x heat rate for gas equivalence Significant Global Coal Displacement Potential Remains (b) 48% 44% 45% 42% 37% 39% 39% 33% 30% 30% 28% 23% 19% 22% 20% 16% 15% 21% 23% 24% 25% 30% 28% 28% 33% 34% 32% 35% 38% 41% 38% 40% 43% 43% 3% 4% 4% 5% 5% 6% 7% 7% 8% 10% 10% 11% 12% 14% 15% 16% 17% 0 5 10 15 20 25 30 35 40 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Bcf per Day Equivalent Coal Gas Nuclear Hydro Solar+Wind Other 49% 15% 58% 75% 34% 19% 43% 3% 3% 22% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% U.S. (2005) U.S. (2024) China (2024) India (2024) World Average (2024) Power Generation Mix Coal Natural Gas Nuclear Hydro Renewables Other
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12.0 12.9 5.7 2.1 2.8 2.2 2.9 7.0 7.6 6.0 0 5 10 15 20 25 30 35 40 45 2020 2021 2022 2023 2024 Other LNG Norway Local Production + Other Pipe Russia via Pipeline U.S. LNG U.S. LNG Plays a Vital Role in Global Energy Security 16 Global LNG Exports (Bcf/d)(a) ▪ The U.S. became the world’s largest LNG exporter in 2023 ▪ Total U.S. LNG exports have grown from ~0 Bcf/d in 2015 to ~16 Bcf/d in 2025 ▪ LNG export projects create strong economic benefits for local communities via jobs, taxes and royalties ▪ U.S. has abundant gas resources to support future growth at higher prices ▪ U.S. has stepped up to replace Russian pipeline gas into Europe, while other sources were flat to down since 2021 ▪ U.S. LNG has played a vital role in energy security for our allies ▪ U.S. LNG can accelerate decarbonization through coal-to-gas switching in the power sector and provide backup to intermittent renewable power European Gas Supply by Source (Bcf/d)(b) (a) Source: Bloomberg (b) Source: Bloomberg, GIE, IEA; EU27 + UK gas supply 20 24 28 32 36 40 44 48 52 56 60 64 0 2 4 6 8 10 12 14 16 Total (RHS) Australia Qatar United States of America
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98 102 106 110 114 118 122 126 130 134 2024 Demand ResCom Industrial & Other Electric Power Mexico Exports LNG Exports 2030 Demand Associated Gas Other Basins Call on Gas Basins U.S. Demand (Bcf/d) Future Natural Gas Fundamentals Are Strong 17 Natural Gas Plays Key Role in Energy Transition, with a Supportive Demand Outlook ~22 Bcf/d ▪ Demand grows ~29 Bcf/d by 2030, driven by increased exports, electric power and industrial demand ▪ Upside to electric power demand from electrification and AI data center load growth ▪ Outlook includes ~4 Bcf/d of electric power demand growth related to AI data center load growth, recent third-party research estimates indicate Range outlook could be conservative ▪ Industry focus on capital discipline reduces outlook for associated gas growth versus historical expectations ▪ Even if oil basin activity increases with rising oil prices, significant growth is still needed from gassy basins to meet future demand ▪ Additional infrastructure is needed for supply to meet demand Note: Associated gas supply assumes 4% CAGR. Other basin supply represents legacy shale, conventional, offshore and imports. Source: Range Resources
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-2 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 2019-24 2025-30 R+C Industrial+Other Electric Power Mexico Exports LNG Exports Significant Natural Gas Demand Growth Through 2030 18 2025-2030 Demand Outlook ▪ Total demand growth of +29 Bcf/d through 2030 from LNG and pipeline exports to Mexico, industrial and electric power demand growth ▪ Current LNG feedgas capacity ~17 Bcf/d as of 3Q25 ▪ LNG projects under construction add ~16 Bcf/d by 2030 ▪ Continued coal (currently ~15% of power stack) retirements and site repurposing present upside to this demand outlook ▪ Reshoring of industrial demand and investments in domestic supply chains, and accelerating AI data center power demand growth present upside to industrial gas and electric power demand forecasts U.S. LNG Export Terminal Capacity Under Construction or In-Service (Bcf/d)U.S. Gas Demand Growth Outlook (Bcf/d) U.S. LNG Export Demand Outlook ▪ Range forecasts U.S. LNG feedgas capacity to reach >30 Bcf/d by 2030, and continue to grow in the 2030s ▪ Next-wave U.S. LNG projects of ~16 Bcf/d currently under construction expected to come online through 2030 ▪ Additional 1-2 Bcf/d could FID in 4Q25-2026 Source: EIA, LNG operator announcements, Range Resources Sabine Pass T1-T5 Cove Point Elba Island Corpus Christi T1-T2 Cameron T1-T3 Freeport T1-T3 Corpus Christi T3Sabine Pass T6 Calcasieu Pass 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 12/18 12/19 12/20 12/21 12/22 12/23 12/24 12/25 12/26 12/27 12/28 12/29 12/30 ECA Phase 1 Plaquemines Corpus Christi Stg3 Port Arthur Phase 1 Rio Grande Phase 1 CCL Midscale 8&9 Louisiana LNG CP2 Phase 1 Rio Grande T4 Port Arthur Phase 2 Golden Pass T1-T3
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- 2 4 6 8 10 12 2025 2026 2027 2028 2029 2030 Incremental Natural Gas Demand (Bcf/d) Third-Party Base Case Range Third-Party Base Case Average Northeast Gas Demand Growth Prospects Increasing ▪ PJM raised its summer load demand forecast to ~50 GW of growth by 2030 in its 2025 Load Forecast Report, up from ~21 GW in its 2024 report ▪ Assuming natural gas retains its ~45% share of PJM generation results in ~4 Bcf/d of natural gas demand growth ▪ Data centers, battery & chip plants, EVs, and reshoring are boosting PJM’s load forecast ▪ 30 GW of coal plants at risk of retiring in PJM by 2030 (~2 Bcf/d(a)) ▪ Neighboring regions (Southeast/Midwest) accessible by pipelines from Appalachia to exhibit similar gas demand trends Significant Natural Gas Demand Forecast from Data Centers ▪ Various third-party research estimates indicate an average ~5 Bcf/d of incremental natural gas demand from AI data centers by 2030 ▪ Appalachia well-positioned to meet incremental data center demand ▪ Announced Homer City Redevelopment and Shippingport Industrial Park expected to add ~1.5 Bcf/d of natural gas demand in Southwest Pennsylvania, with initial startup of power generation projected by 2027 ▪ Range announced strategic collaboration with Liberty Energy and Imperial Land to supply natural gas to a proposed state-of-the-art power generation facility in Washington County, PA Growing Power Demand Highlights Critical Role of Natural Gas 19 Natural Gas Demand from Data Centers(c) PJM Projections of Future Load Growth (MW) Revised Higher(b) Source: BCG, PJM Load Forecast Report January 2025, PJM 2024 State of the Market Report (Monitoring Analytics) (a) Assumes 7x heat rate for gas equivalence (b) PJM Load Forecast Report January 2025 (c) Aggregation of various third-party estimates Third-party estimates project significant gas demand from electricity generation for data centers Check for updates
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35 36 37 38 39 40 41 42 43 44 45 46 2024 Demand + Takeaway Takeaway Expansions Gas Power Demand (Data Centers, Chip Plants, Reshoring, EVs) Coal Plant Retirements 2030 Demand + Takeaway Appalachia Demand and Takeaway (Bcf/d) Appalachia Demand Fundamentals Improving 20 ~5-8 Bcf/d of Local Demand Growth and Additional Takeaway Capacity Through 2030 ~37 Bcf/d Source: Range Resources, EIA, Industrial Info Resources (a) Industrial Info Resources estimate, assumes 50% natural gas share Base Case High Case ~42-45 Bcf/d Data Centers ▪ Northeast data center projects underway (pre/post-FID) ~3 Bcf/d by 2030 (a) ▪ Homer City and Shippingport ~1.5 Bcf/d Industrial Demand Growth ▪ ~$90 billion of deals announced at Pennsylvania Energy and Innovation Summit to support AI and energy infrastructure in the state ▪ Large semiconductor projects potentially add ~0.1 Bcf/d of demand each; Intel (OH), Micron (NY) ▪ EV battery and solar manufacturing plants (OH) Coal Retirements ▪ ~0.9-1.8 Bcf/d by 2030 ▪ 4.1 GW of coal plant retirements in the Northeast already announced for 2024-2030 Takeaway ▪ Expansions including Transco SE Supply Enhancement and MVP Southgate potentially add ~2.2 Bcf/d by 2030 ▪ Multiple other pipeline projects under consideration provide further takeaway growth potential Base Case Base Case High Case High Case
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Lower 48 Dry Gas Production 21 Future U.S. Supply Growth Expected to be Limited by Infrastructure Constraints and Productivity Declines Source: Bloomberg, Range Resources 70 74 78 82 86 90 94 98 102 106 110 114 118 122 126 130 134 1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec U.S. L48 Pipeline Flows (Bcf/d) 2021 2022 2023 2024 2025 Projected 2030 Demand
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Lower 48 Storage - Days of Supply 22 U.S. Natural Gas Days of Supply Are Below Average Source: Bloomberg 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec U.S. L48 Gas Storage Days of Supply 2016-2024 Low 2016-2024 High 2016-2024 Avg 2024 2025 Lack of additional storage built in the U.S. over the last decade likely results in increased volatility for natural gas, ultimately benefiting the lowest cost producers through cycles
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11,000 11,250 11,500 11,750 12,000 12,250 12,500 12,750 13,000 13,250 2024 Demand ResCom + Industry + Autogas + Other PDH Ethylene 2030 Demand Non-U.S. Supply Call on U.S. Supply Global LPG Demand (MBD) NGL Macro Strengthens with International Demand Growth 23 Increasing Global Demand Being Supplied by U.S. LPG ▪ Global ResCom consumption growth and chemical projects add ~1.5 MMBD of LPG demand by 2030 with the majority supplied by the U.S. ▪ China has been the dominant demand growth source in the chemical sector over the past 5 years; China’s share of global demand is expected to remain near current levels of ~50% going forward ▪ Asian countries are shifting away from older naphtha-fed steam crackers and turning towards lower-cost LPG for chemical feedstock ▪ OPEC+ unwinding ~3.5 MMBD of crude oil production curtailments adds ~250 MMBD of LPG supply, meeting just 17% of projected gl obal LPG demand growth ▪ U.S. LPG export terminal expansion projects will add ~1.0 MMBD of nameplate capacity by 2028 to meet call on U.S. supply and potential future growth ~860 MBD Source: Platts, EIA, Energy Aspects, IEA, Range Resources
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Global LPG Supply and Demand Markets Shift ▪ U.S. share of global LPG exports has doubled to 48% since 2014 ▪ U.S. LPG exports have increased ~3% in 2025 through July ▪ Incremental U.S. LPG flows to Japan, India, Vietnam and Indonesia have offset ~80% of reduced U.S. to China flows since April U.S. LPG Export Expansions Will Supply Global Demand ▪ Terminals expected to remain full in 2026 as ~220 MBD of new propane-fed petrochemical capacity buildouts are completed in China ▪ U.S. LPG export capacity to grow ~1.0 MMBD, or 42% by 2030 ▪ High terminal utilization reinforces tighter U.S. LPG fundamentals, supporting Mont Belvieu prices and premiums at U.S. docks U.S. Exports Efficiently Meet Global LPG Demand 24 Growing U.S. LPG Market Share with Rising Exports Source: Platts, IEA, EIA, Energy Aspects, KPLER, RRC estimates U.S. LPG Export Terminal Capacity and Utilization U.S. LPG Supply Shifts to Markets Outside of China 71% 72% 82% 89% 100% 100% 40% 50% 60% 70% 80% 90% 100% 110% - 500 1,000 1,500 2,000 2,500 3,000 3,500 2021 2022 2023 2024 2025 2026 Utilization % MBD Export Capacity Forecast Yearly LPG Exports Forecast Export Capacity Utilization Forecast 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% - 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 YTD U.S. Market Share Waterborne LPG Trade (MBD) U.S. Waterborne LPG Trade Non-U.S. Waterborne LPG Trade U.S. Market Share - 500 1,000 1,500 2,000 2,500U.S. LPG Export Destinations (MBD) China Asia (Ex-China and India) Europe Americas Other India
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4,500 4,700 4,900 5,100 5,300 5,500 5,700 5,900 United States China Rest of World 2024 Demand Steam Cracker Demand 2030 Demand Non - U.S. Supply Call on U.S. Supply Global Ethane Demand (MBD) Global Ethane Demand ▪ Demand growth for packaging, automobiles, and electronics requires additional ethylene production ▪ Ethylene steam cracking capacity is expected to increase by ~705 MBD by 2028, requiring additional ethane supply ▪ International ethylene steam cracker demand capacity accounts for ~575 MBD, or ~81% of new global projects ▪ Ethane-fed ethylene steam crackers are historically the lowest cash cost in the world, supporting continued demand for U.S. supply Global Ethylene Demand Growth Drives U.S. Ethane Exports 25 U.S. Supplies 100% of Global Waterborne Ethane Supply Source: Platts, IEA, EIA, Energy Aspects, KPLER, RRC estimates Global Ethane Demand Creates Significant Call on U.S. Supply U.S. Export Growth Needed to Meet Global Demand Growth ▪ Currently planned U.S. ethane export terminal expansion projects will add ~445 MBD of additional capacity, falling short of the call on U.S. supply ▪ Further U.S. ethane export terminal expansions of ~130 MBD will be required to satisfy remaining international demand growth ▪ New U.S. ethane export capacity will alleviate bottlenecks and support further growth projects 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% - 100 200 300 400 500 600 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 YTD U.S. Market Share Waterborne Ethane Trade (MBD) U.S. Waterborne Ethane Trade Non-U.S. Waterborne Ethane Trade U.S. Market Share ~705 MBD
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ESG 26
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Industry-Leading Emissions Targets ▪ Achieved Net Zero for 2024 Scope 1 and 2 GHG emissions ▪ Achieved “A” grade through MiQ certification for Range’s PA assets ▪ 83% reduction in methane emissions intensity since 2019 ▪ LDAR survey frequency of 8x per year Commitment to Clean & Efficient Operations ▪ Recycled >100% of produced water volume in 2024 through Range’s water recycling and sharing program ▪ 56% of total water used for operations in 2024 was reuse water ▪ Water recycling lower completion costs and LOE Water Recycling Program Reduces Fresh Water Use Leading in Environmental Practices 27 Lowest Methane Intensity Compared to Peers(a) Note: For additional information, Range’s Corporate Sustainability Report can be found on the Company’s website. (a) Enverus data as of April 2025 for Range proxy peer group 44% 63% 62% 76% 58% 56% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 0 5 10 15 20 25 30 35 40 2019 2020 2021 2022 2023 2024 Reuse Water as % of T otal Water Used Volume of Water (Million Bbls) Total Fresh Water Used Reuse Water (from Range) Reuse Water (from Other Operators) Reuse Water (Containment/Rainwater) Recycled Water as % of Total Water Used 0.00% 0.10% 0.20% 0.30% 0.40% 0.50% 0.60% Range Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Methane (CH 4) Emissions Intensity as % of total gas production from wells
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Governance & Social Responsibility 28 ✓ Average Director tenure of five years ❖ Chris Kendall appointed to the Board in February 2025 ❖ Charles Griffie appointed to the Board in October 2023 ❖ Reggie Spiller appointed to the Board in September 2021 ✓ Diversity remains a priority, as Range seeks to achieve a combination of knowledge, experience and skills ✓ 33% of independent directors are women ✓ 50% of committees chaired by women ✓ Independent Chairperson ✓ Actively engage directly with shareholders ✓ Formed ESG & Safety Committee with all independent directors currently serving Director Independence All directors are independent except the CEO Board Governance Social Responsibility Range Is Committed to Strong Governance and Social Responsibility. Range Views These Objectives as Core to Delivering Long-Term Value for Shareholders. Safety Leadership Community Impact ✓ ~$5 billion paid to impact fees, royalty and lease payments, and charitable contributions through 2024 ✓ Volunteered 3,100+ employee hours in 2024 ✓ Named to Newsweek Magazine’s 2025 Most Responsible Companies list ✓ Recognized as one of JUST Capital’s Most JUST Companies ✓ Zero severe injuries in 2024 ✓ 42% reduction in Contractor and Range employee Days Away, Restricted, or Transferred in 2024 (DART) ✓ 2024 Safety Culture survey placed Range in top quartile of oil and gas industry peer group ✓ Three recordable Range employee incidents in 3.6 million work hours over three years from 2022 to 2024
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Executive Compensation Aligned with Shareholders 29 Long-Term Equity Incentive Plan Long-term incentives focused on absolute and relative shareholder returns. ✓ 60% Performance-Based & 40% Time-Based RSU ✓ Greater than 85% of CEO compensation at-risk ✓ Relative TSR component with absolute performance modifier ✓ S&P 400 introduced as peer to better align performance ✓ Additional weighting placed on performance relative to natural gas peers ✓ Restricted stock subject to 3-year cliff vesting Annual Incentive Targets Short-term incentives focused on key financial and ESG framework targets, prioritizing returns, cost efficiencies and environmental, health & safety measures. ✓ Free Cash Flow to promote resilience through commodity price cycles ✓ Returns metrics focus on consistent value creation ▪ Return on Capital ▪ Drilling Rate-of-Return ✓ EHS component relies heavily on quantitative assessments including: ▪ TRIR for employees and contractors ▪ Preventable vehicle incidents ▪ Spills and leak rates ▪ Notices of violations ✓ Cash Unit Costs & Drilling & Completion Cost per Mcfe Changes to Incentive Plans Have Been Informed by the Board’s Direct Outreach to Stakeholders, Annual Outreach Targets Greater than 65% of Shares Outstanding
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Appendix 30
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Utica/Point Pleasant Appalachia – Stacked Pay 31 ▪ ~1.5 million net effective acres(a) in PA leads to decades of drilling inventory ▪ Activity led by Core Marcellus development in Southwest PA ▪ ~1,500 producing Marcellus wells demonstrate high quality, consistent results across Range’s position ▪ ~400,000 net acres in SW PA prospective for Utica / Point Pleasant ▪ Range’s third dry gas Utica/Point Pleasant well (2016) appears to be one of the best in the basin Stacked Pay and Existing Pads Allow for Multiple Development Opportunities Gas In Place For All Zones Upper Devonian Marcellus (a) Assumes stacked pay opportunities in Marcellus, Utica/Point Pleasant, and Upper Devonian Gas in Place Analysis Shows the Greatest Potential is in Southwest Pennsylvania
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Range Has Delineated Its Entire Acreage Position ▪ Since pioneering the Marcellus in 2004, Range has drilled across its Appalachian position ▪ ~1,500 producing wells in PA provide control data for new development activity ▪ Contiguous acreage provides for operational efficiencies and industry leading well costs: • Long-lateral development • Efficient water handling and sourcing • Optimization of electric fracturing fleet and existing infrastructure Track Record of Returning to Existing Pads ▪ Network of over 250 existing pads with an average of 6 producing wells versus capacity designed for an average of 20 wells ▪ Drives savings through use of existing surface infrastructure ▪ Over 50% of 2025 activity on existing pads, similar to recent years ▪ Well results after several years from returning to existing pads show no degradation in recoveries Multi-Decade Inventory of Capital Efficient Wells 32 Southwest Pennsylvania = Existing Pad >30 Years of High-Quality Marcellus Inventory that Breaks Even Below $2.50 at Current Activity Level Note: Highlighted areas represent townships where Range holds ~2,000 or more acres.
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Northeast Pennsylvania 33 ▪ Approximately 70,000 net acres prospective for Marcellus development ▪ 2024 Northeast PA production averaged over 100 Mmcf per day ▪ Utilizing existing infrastructure to bolster efficiencies and returns Range’s Northeast Marcellus Assets Provide Additional Dry Gas Marcellus Inventory Northeast Pennsylvania = Existing Pad Note: Highlighted areas represent townships where Range holds ~2,000 or more acres.
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Northwest Pennsylvania – Utica/Point Pleasant 34 ▪ Range has approximately 220,000 net acres with Utica/Point Pleasant potential ▪ ~190,000 net acres have similar thermal maturity and liquids potential as EOG’s liquids play in Ohio ▪ The play on Range’s acreage is at a similar depth and pressure regime as EOG’s activity in Ohio ▪ Retained deep rights from divested properties. Acreage is held by production. Range’s Northwest Utica/Point Pleasant Assets Provides Potential Liquids Opportunity Northwest Pennsylvania Note: Highlighted areas represent townships where Range holds ~2,000 or more acres.
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Southwest Appalachia Marcellus Modeling Data 35 Super-Rich Area ▪ ~100,000 Net Acres ▪ EUR / 1,000 ft. = 2.70 Bcfe ▪ 2025 D&C Cost / ft. = $910 Wet Area ▪ ~240,000 Net Acres ▪ EUR / 1,000 ft. = 3.26 Bcfe ▪ 2025 D&C Cost / ft. = $840 Dry Area ▪ ~100,000 Net Acres ▪ EUR / 1,000 ft. = 2.32 Bcfe ▪ 2025 D&C Cost / ft. = $830 Gross Estimated Cumulative Recoveries by Year Year Condensate (Mbbls) Residue (Mmcf) NGL (Mbbls) 1 19 1,976 343 2 25 3,188 553 3 28 4,133 717 5 34 5,650 981 10 41 8,369 1,453 20 50 11,807 2,049 EUR 60 15,797 2,742 Year Residue (Mmcf) 1 3,957 2 5,914 3 7,335 5 9,461 10 13,041 20 17,524 EUR 23,172 Year Condensate (Mbbls) Residue (Mmcf) NGL (Mbbls) 1 87 1,158 208 2 122 1,962 353 3 146 2,655 477 5 179 3,817 685 10 230 5,965 1,067 20 291 8,744 1,557 EUR 360 11,973 2,111 Note: 2025 plan costs and type curves assume 10,000 ft. average lateral length. Average SWPA NRI is ~79.5%. NGL recoveries assume 80% ethane extraction.
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% of RRC Barrel Mont Belvieu ($/gal) Avg. 2023 Avg. 2024 1Q 2025 2Q 2025 3Q 2025 4Q 2025E Avg. 2025E 53% Ethane $0.25 $0.19 $0.27 $0.24 $0.23 $0.25 $0.25 27% Propane $0.71 $0.78 $0.90 $0.78 $0.69 $0.65 $0.75 8% Normal Butane $0.91 $1.01 $1.06 $0.88 $0.86 $0.85 $0.91 4% Isobutane $1.00 $1.15 $1.07 $0.93 $0.92 $0.88 $0.95 8% Natural Gasoline $1.52 $1.51 $1.53 $1.32 $1.30 $1.25 $1.35 $0.56 $0.56 $0.64 $0.55 $0.52 $0.51 $0.55 $23.37 $23.44 $26.74 $23.12 $21.76 ~$21.50 ~$23.25 $1.24 $2.33 $1.05 $0.61 $0.33 ~$0.15-$1.15 $0.50-$0.75 $24.61 $25.77 $27.79 $23.73 $22.09 ~$21.65-$22.65 ~$23.75-$24.00 Range-Equivalent Mont Belvieu Barrel ($/gal) Range-Equivalent Mont Belvieu Barrel ($/bbl) Range's Pre-Hedge Realization ($/bbl) Range's NGL Differential ($/bbl) NGL Price Calculation Example 36 2025 Guidance is the Range-Equivalent Mont Belvieu Barrel Plus $0.50 to $0.75 Additional Considerations • Range NGL differential can be influenced by factors including: • Naphtha vs. ethane prices • International prices vs. Mont Belvieu • Timing of LPG cargoes • Barrel mix • Ethane recovery • Natural gas prices vs. ethane Note: Prices represent strip pricing as of 10/24/2025. Calculations illustrate pre-hedge realizations. Conversion rate is 42 gallons : 1 barrel
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Range 2025 Guidance 37(a) Represents differential to Mont Belvieu-equivalent barrel, based on a weighting of 53% ethane, 27% propane, 8% normal butane, 4% iso-butane, and 8% natural gasoline. Updated 2025 Prior 2025 Guidance Guidance - July Production per Day ~2.23 Bcfe ~2.225 Bcfe Capital Expenditures $650-$680 Million $650-$680 Million Maintenance Drilling, Completion, Land, and Facilities $520 Million $520 Million Added In-Process Well Inventory and Growth $80 - $100 Million $80 - $100 Million Targeted Acreage to Increase Future Inventory ~$30 Million ~$30 Million Pneumatic Devices and Facility Upgrades $20 - $30 Million $20 - $30 Million Cash Expense Guidance Direct Operating Expense per mcfe $0.12 - $0.13 $0.12 - $0.13 TGP&C Expense per mcfe $1.50 - $1.52 $1.50 - $1.55 Taxes Other than Income per mcfe $0.03 - $0.04 $0.03 - $0.04 G&A Expense per mcfe $0.17 - $0.18 $0.17 - $0.18 Exploration Expense $24 - $28 Million $24 - $28 Million Net Interest Expense per mcfe $0.12 - $0.13 $0.12 - $0.13 DD&A Expense per mcfe $0.45 - $0.46 $0.45 - $0.46 Net Brokered Marketing Expense $8 - $12 Million $8 - $12 Million Pricing Guidance Natural Gas Differential to NYMEX ($0.40) - ($0.43) ($0.40) - ($0.48) Natural Gas Liquids(a) +$0.50 to +$0.75 per barrel +$0.40 to +$1.25 per barrel Oil/Condensate Differential to WTI ($10.00) - ($15.00) ($10.00) - ($15.00)
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0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%% of Revenue Natural Gas Oil NGLs Hedge Summary 38 Range’s Hedging Strategy, Marketing Contracts, and Diversified Production Mix Support Consistent Operational Plans and Shareholder Returns Through the Cycles. Note: Hedges as of 10/17/25, rounded to nearest 5%. For a detailed monthly summary of Range’s hedges, please visit the Company’s website. NGL hedges include physical sales contracts with price floors (puts). 4Q 2025 Hedging 2026 Hedging Avg. Floor Avg. Ceiling Natural Gas $4.08 $4.43 Oil - - Avg. Floor Avg. Ceiling Natural Gas $4.03 $4.56 Oil - - 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%% of Revenue Natural Gas Oil NGLs (a) 10,000 MMBtu per day calendar 2026 $4.12 average strike call swaptions. 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50%% of Revenue Natural Gas Oil NGLs Swaptions(a) 2027 Hedging Swaptions(b) (b) 150,000 MMBtu per day calendar 2027 $4.05 average strike call swaptions. Avg. Floor Avg. Ceiling Natural Gas $4.05 $4.05 Oil - -
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$600 $500 $129 $0 $500 $1,000 $1,500 $2,000 $2,500 2025 2026 2027 2028 2029 2030 2030 Range Notes Bank Credit Facility Resilient Balance Sheet Strong Balance Sheet Provides Flexibility Through the Cycles and Lower Debt Improves Cost Structure RRC Net Debt(a) $ billion 39 RRC Maturity Profile(b) $ million (a) Target debt of $1.0-$1.5 billion, net of cash (b) Borrowings as of 9/30/25 (c) 3Q25 weighted average interest rate 6.4%(c) 8.25% 4.75% $1.4 $1.23 $4.1 $3.9 $3.2 $3.1 $2.7 $1.9 $1.6 <$1.5 8.4x 8.6x 8.8x 9.0x 9.2x 9.4x 9.6x 9.8x 10.0x $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 2017 2018 2019 2020 2021 2022 2023 2024 3Q25 Target
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Contact Information 40 Range Resources Corporation 100 Throckmorton Street, Suite 1200 Fort Worth, Texas 76102 Laith Sando, CPA (817) 869-4267 lsando@rangeresources.com Matt Schmid (817) 869-1538 mschmid@rangeresources.com www.rangeresources.com