Slides
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Company Presentation July 2026
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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. Forward-Looking Statements
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Range – Who We Are 3 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; ~$4.4 Billion since 2021 • Expect to Grow Production to 2.6 Bcfe per Day in 2027 at <50% Reinvestment Rate Peer-Leading Capital Efficiency • Large Contiguous Acreage Position Supports Efficient Operations and Peer-Leading Well Costs Diversified Market Outlets • Access to Growing Demand in Multiple Domestic and International Markets for Natural Gas and NGLs • Ability to Serve Growing In-Basin Demand Strong Balance Sheet • Leverage at 0.6x 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 • Maintained Net Zero Scope 1 and 2 GHG Emissions since 2024
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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 maintenance activity levels for 2.6 Bcfe/d. ~450,000 Net Acres in Southwest Pennsylvania ~70,000 Net Acres in Northeast Pennsylvania 27 Million Lateral Feet of Undrilled Marcellus at YE 2025 $/MMbtu Breakeven(a) >30 Years(b) of Undrilled Marcellus Inventory Breaks Even Under $2.50 30+ Years of High-Quality Marcellus Inventory Utica/Point Pleasant and Upper Devonian Further Extend Range’s Inventory Life
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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 Global Sales Portfolio Concentrated Marcellus Assets Access Multiple End-Markets for Natural Gas and NGL Price Diversification Oil-Linked Gas-Linked Mont Belvieu . Exports Local & Northeast . MidwestGulf Coast LNG Local & Northeast
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(a) Cash flow from operations before working capital less capital expenditures. (b) Cash flow from operations before working capital less capital expenditures. Assumes $65 WTI and $24 NGL realizations, 2026 midpoint production and capital expenditure guidance, 2027 production of 2.6 Bcfe/d and capital expenditures of $675 million, and hedges as of 7/10/26. Assumes effective cash tax rate of 2% in 2026, and 6% in 2027. 7 $4.50 NG $3.75 NG $3.00 NG 2026E-2027E FCF Sensitivity(b) Durable Free Cash Flow Through the Cycles History of Sustainable Free Cash Flow and Capital Returns $656 $1,580 $513 $453 $656 $- $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 2021 2022 2023 2024 2025 2026E 2027E RRC Free Cash Flow ($ MM)(a)
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8 Outlook Through 2027 ▪ Cumulative 2026-2027 FCF of >$1.7 billion(a) at $3.75 NYMEX natural gas and $24 NGL realizations ▪ $650 - $700 million annual capex ▪ Grows production to 2.6 Bcfe/d Growth into Strong End-Markets ▪ 300 Mmcf/d incremental processing being commissioned ▪ 250 Mmcf/d incremental natural gas takeaway linked to growing demand in Midwest and Gulf Coast markets ▪ 20 MBD NGL takeaway and export capacity utilizing new East Coast terminal Increasing Capital Returns ▪ <50% reinvestment rate at $3.75 NYMEX natural gas supports potential shareholder return increases while growing production Natural Gas and NGL Sensitivity ▪ Every $0.25 per mcf change in natural gas realizations is ~$300 million in cumulative 2026-2027 pre-hedge cash flow ▪ Every $1 per barrel change in NGL realizations is ~$70 million in cumulative 2026-2027 pre-hedge cash flow (a) Free cash flow represents cash from operations before working capital less capital expenditures. Estimated 2026-2027 EBITDAX and free cash flow assumes $3.75 NYMEX NG, $65 WTI, and $24 NGL realizations. Assumes effective cash tax rate of 2% in 2026, and 6% in 2027. Range Multiyear Outlook Efficient Growth into Increasing Demand 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 2,800 $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 2025A 2026E 2027E Daily Production (Mmcfe) EBITDAX and Free Cash Flow ($ MM)(a) Analyst FCF Pre-Tax FCF EBITDAX Production
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- 200,000 400,000 600,000 800,000 1,000,000 1,200,000 2023 2024 2025 2026E-2027E Annual Avg. Lateral Feet Lateral Feet Drilled Lateral Feet TIL Differentiated Inventory Position ▪ Countercyclical investments built productive capacity while peers maintained or drew down DUCs in 2025 ▪ Range is reducing reinvestment rate in 2026 & 2027, while growing production, which drives increased free cash flow and shareholder returns RRC Growth Inventory ▪ Added over 500k lateral feet of growth inventory in 2024 and 2025 ▪ This productive capacity provides capital efficiency tailwinds that drive Range’s growth profile through 2027 for similar capital vs. 2025 ▪ Expected annual TILs of ~950k lateral feet in 2026 and 2027 Potential Options Beyond 2027 ▪ Operational efficiencies could allow continued growth into 2028, without changing capital spend in 2026 and 2027. <$0.75 per mcfe OR ▪ Maintain 2028+ production levels of 2.6+ Bcfe per day with ~725k lateral feet of TILs, which is under $600 million of D&C capital. <$0.60 per mcfe (a) Enverus estimates as of 2/11/26; peers include AR, CNX, CRK, CTRA, EQT, EXE, and GPOR 9 RRC Lateral Feet Drilled and TIL Year-End 2025 DUC Inventory(a) Positioned for Capital-Efficient Growth Differentiated Investments in Inventory Drive Capital-Efficient Growth (8) (6) (4) (2) 0 2 4 6 8 0 2 4 6 8 10 12 14 RRC Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 4Q24 to 4Q25 DUC Inventory Change (Months) DUC Inventory (Months) 4Q24 4Q25 Y/Y Change [Right Axis] Build DrawBuild
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$500 $10 - $20 $120 - $140 $5 - $15 $15 - $25 $650 - $700 2026 Maintenance D&C 2026 Maintenance Land 2026+ Growth D&C 2026 Targeted Acreage 2026 Pneumatic Devices/Other 2026 Capital $ Million Maintain Existing Leases (a) 2026 Maintenance Capital for 2.24 Bcfe/d. (b) Pneumatic Upgrade capital is expected to be completed by year-end 2026. 10 Pneumatic Devices, Facilities, and Software Future InventoryGrowth (a) (b) 2026 Capital Investments Operational Plan Supports Efficient Wedge of Production Growth through 2027
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(a) Bloomberg sector estimates as of 7/17/26. RRC FCF assumes $65 WTI and $24 NGL realizations. RRC EV/EBITDA is Bloomberg consensus. 2027 FCF Yield(a) 2027 EV/EBITDA(a) 11 RRC at $4.50 NG RRC at $3.75 NG RRC at $3.00 NG Reinvestment Rate (% of Cash Flow)(b) b) Enverus estimates assuming strip price as of 6/19/26. Reinvestment rate represents estimated capital expenditures / (capital expenditures + free cash flow). Peers include AR, CNX, CRK, EQT, EXE, GPOR. ( c) ATAX PV-10 for $4/$5 cases use $65/$70 WTI, respectively. Assumes 21% tax rate in all cases, without accounting for expected NOL benefit. Year-end 2025 standardized measure value of $9.6 billion uses SEC-defined pricing of $3.39 natural gas/$65.68 WTI. ( Low reinvestment rate while growing production ATAX PV-10(c) of Proved Reserves per Share, Net of Debt Compelling Free Cash Flow and Valuation Range Offers Durable Free Cash Flow and Attractive Trading Multiple and Yield versus Other Sectors $35 $41 $60 Standardized Measure $4.00 $5.00 NYMEX Natural Gas Valuation of proved reserves only includes 2.5 million lateral feet (~9%) of Range’s ~27 million lateral feet of undeveloped core Marcellus inventory Proved Developed 12.8 Tcfe Proved Undeveloped 5.3 Tcfe 0% 20% 40% 60% 80% 100% 120% Peer 1 RRC Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 2026 2027 5.5x 9.7x 11.1x 12.9x 13.0x 13.1x 13.8x 14.5x 16.1x 19.1x 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x 18.0x 20.0x RRC Telecom Materials Russell 3000 Con. Discretionary Healthcare Tech Con. Staples Industrials Real Estate 1.8% 2.3% 3.4% 3.4% 4.0% 4.1% 4.3% 5.4% 5.6% ~14% 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% Materials Con. Discretionary Industrials Tech Russell 3000 Real Estate Con. Staples Telecom Healthcare RRC
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12 • Large Contiguous Acreage Position Provides 30+ Years of Low-Breakeven, High-Return Marcellus Inventory • History of Resilient Free Cash Flow Driven by 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 • Access to Growing Demand in 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 Why Invest In Range?
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13 Natural Gas & NGL Macro
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▪ Between 2005 and 2025, U.S. energy emissions declined while total global energy emissions increased ~27% ▪ Despite several IEA calls over the last decade that coal demand would peak, global coal demand hit record highs in 2025, 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 14 U.S. CO2 Emissions Reductions Driven by Coal Displacement (MMT)(a) ~14 Bcf/d ▪ Between 2005 and 2025, total U.S. energy emissions declined ~18%, driven by ~38% 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 Coal Consumption & CO2 Emissions from Energy (2005-2025 Change)(b) (a) Source: EIA (b) Source: Energy Institute Statistical Review of World Energy 2026 Natural Gas Plays Key Role in Reducing Emissions 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 2025 Power Gen. & All Other Sector Total Energy Total Energy Emissions Power Gen. Emissions All Other Sector Emissions -19% -29% 85% 146% 29% 35% 27% -65% -54% 66% 160% 53% 1% 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 15 Bcf/d from 2010-2025, while coal declined 21 Bcf/d(c) and renewables grew 12 Bcf/d(c) ▪ Natural gas has grown to 41% of the U.S. generation mix Market Share Growth Should Continue ▪ Approximately 14 Bcf/d of coal generation remains to be displaced, or ~17% of U.S. Power Generation Mix ▪ 110 GW of coal plant capacity retired from 2013-2025, and another 30 GW of coal plant retirements have been announced for 2026 -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 ~33% of global power generation, or ~206 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 ~54% of China’s power generation mix (~113 Bcf/d(c)) and ~71% of India’s power generation mix (~29 Bcf/d (c)) 15 U.S. Power Generation by Source(a) (a) Source: EIA (b) Source: Energy Institute Statistical Review of World Energy 2026 (c) Assumes 7x heat rate for gas equivalence Significant Global Coal Displacement Potential Remains (b) Natural Gas Supporting Electrification and Coal Displacement 48% 44% 45% 42% 37% 39% 39% 33% 30% 30% 28% 23% 19% 22% 20% 16% 15% 17% 21% 23% 24% 25% 30% 28% 28% 33% 34% 32% 35% 38% 41% 38% 40% 43% 43% 41% 3% 4% 4% 5% 5% 6% 7% 7% 8% 10% 10% 11% 12% 14% 15% 16% 17% 19% 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 2025 Bcf per Day Equivalent Coal Gas Nuclear Hydro Solar+Wind Other 49% 17% 54% 71% 33% 19% 41% 3% 2% 22% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% U.S. (2005) U.S. (2025) China (2025) India (2025) World Average (2025) Power Generation Mix Coal Natural Gas Nuclear Hydro Renewables Other
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16 Global LNG Exports (Bcf/d)(a) ▪ The U.S. became the world’s largest LNG exporter in 2023 ▪ U.S. LNG exports have grown from ~0 Bcf/d in 2015 to >18 Bcf/d in 2026 ▪ LNG export projects create strong economic benefits for local communities via jobs, taxes and royalties ▪ Disruptions in Qatar further strengthen demand for U.S. LNG ▪ 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 U.S. LNG Plays A Vital Role in Global Energy Security 12.0 12.9 5.7 2.1 2.8 1.0 2.2 2.9 7.0 7.6 5.7 9.1 0 5 10 15 20 25 30 35 40 45 2020 2021 2022 2023 2024 2025 Other LNG Norway Local Production + Other Pipe Russia via Pipeline U.S. LNG 20 24 28 32 36 40 44 48 52 56 60 64 68 0 2 4 6 8 10 12 14 16 18 20 Total (RHS) Australia Qatar United States of America
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102 106 110 114 118 122 126 130 134 2025 Demand ResCom Industrial & Other Electric Power Mexico Exports LNG Exports 2030 Demand Associated Gas Growth Other Basins Call on Gas Basins U.S. Demand (Bcf/d) 17 ~19 Bcf/d ▪ Demand grows ~25 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 ~5 Bcf/d of electric power demand growth related to AI data center load growth • LNG export demand projected to increase ~16 Bcf/d from average 2025 levels to ~32 Bcf/d in 2030 ▪ Outlook assumes associated gas growth of ~10 Bcf/d ▪ Even if oil basin activity increases with rising oil prices, significant growth is still needed from gassy basins to meet fut ure demand ▪ Additional infrastructure is needed for supply to meet demand Note: Associated gas supply assumes 5% CAGR. Other basin supply represents legacy shale, conventional, offshore and imports. Source: Range Resources Future Natural Gas Fundamentals Are Strong Natural Gas Plays Key Role in Meeting Growing Global Energy Demand
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18 2026-2030 Demand Outlook ▪ Total demand growth of +25 Bcf/d through 2030 from LNG and pipeline exports to Mexico, industrial and electric power demand growth ▪ Current LNG feedgas capacity ~20 Bcf/d as of July 2026 ▪ LNG projects under construction add ~18 Bcf/d through 2030 ▪ Continued coal (currently ~17% 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 >35 Bcf/d by 2030, and continue to grow in the 2030s ▪ Next-wave U.S. LNG projects of ~18 Bcf/d currently under construction expected to come online through 2030 ▪ Additional ~1-2 Bcf/d could FID in 2026 ▪ LNG vessels on order for delivery through 2031 represent a ~35% increase to the current global fleet to meet anticipated global demand Source: EIA, S&P Global Energy, LNG operator announcements, Range Resources Significant Natural Gas Demand Growth Through 2030 -2 0 2 4 6 8 10 12 14 16 18 20 22 24 26 2021-25 2026-30 R+C Industrial+Other Electric Power Mexico Exports LNG Exports Sabine Pass T1-T5Cove Point, 0.0 Cove PointElba Island Corpus Christi T1-T2 Cameron T1-T3 Freeport T1-T3 Corpus Christi T3Sabine Pass T6 Calcasieu Pass Golden Pass T1-T3 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 12/16 12/17 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&2 Rio Grande T4 Port Arthur Phase 2 Commonwealth Delfin
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PJM Projections of Future Load Growth (MW) (b) - 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 Strong Northeast Gas Demand Growth Potential ▪ PJM forecasts a ~25 GW increase in summer load demand for 2026 - 2030, and raised its 2026-2035 growth forecast to ~57 GW ▪ Assuming natural gas takes a ~50% share of PJM generation growth results in 2.1 Bcf/d of natural gas demand growth by 2030 and 4.8 Bcf/d by 2035 ▪ Data centers, battery & chip plants, 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, Shippingport Industrial Park, and Monarch Compute Campus expected to add ~1.8 Bcf/d of natural gas demand in Appalachia, with initial power generation startup projected by 2027 ▪ Potential NextEra gas generation hub in southwest PA and SB Energy data center site in OH could add >2 Bcf/d of natural gas demand ▪ Range strategic collaboration with Liberty Energy and Imperial Land to supply natural gas to proposed state-of-the-art power generation facility in Washington County, PA 19 Natural Gas Demand from Data Centers(c) Source: BCG, PJM Load Forecast Report January 2026 (a) Assumes 7x heat rate for gas equivalence (b) PJM Load Forecast Report January 2026 (c) Aggregation of various third-party estimates Third-party estimates project significant gas demand from electricity generation for data centers Growing Power Demand Highlights Critical Role of Natural Gas
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35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 2025 Demand + Takeaway Gas Power Demand (Data Centers, Chip Plants, Reshoring, EVs) Takeaway Expansions Coal Plant Retirements 2030 Demand + Takeaway Appalachia Demand and T akeaway (Bcf/d) 20 ~38 Bcf/d Source: Range Resources, EIA, Industrial Info Resources (a) Assumes 35% of Industrial Info Resources estimated pre-FID projects, 75% natural gas share (b) Based on Industrial Info Resources estimate of 51 GW of proposed PA/OH/WV projects with targeted ISD by 2030 Base Case High Case ~43-49 Bcf/d Data Centers ▪ High Case only includes ~4 Bcf/d of risked pre/post FID Northeast data center projects (a) ▪ Project proposals in Appalachia have a target capacity of ~9 Bcf/d, providing further demand potential beyond 2030(b) 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 add ~0.1 Bcf/d of demand each; Intel (OH), Micron (NY) ▪ Battery and solar manufacturing plants (OH) 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 Coal Retirements ▪ ~0.3-1.8 Bcf/d by 2030; 2.3 GW of Northeast coal plant retirements announced through 2030 Base Case High Case Appalachia Demand Fundamentals Improving ~5-11 Bcf/d of Demand Growth and Additional Takeaway Capacity Through 2030
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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) 2023 2024 2025 2026 21 Future U.S. Supply Growth Expected to be Limited by Infrastructure Constraints and Productivity Declines Source: S&P Global Energy, Range Resources Projected 2030 Demand Lower 48 Dry Gas Production
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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 2016-2025 Low 2016-2025 High 2016-2025 Avg 2025 2026 22 U.S. Natural Gas Days of Supply Are Below Average Source: Bloomberg Lack of additional storage built in the U.S. over the last decade likely results in increased natural gas price volatility, ultimately benefiting the lowest cost producers through cycles Lower 48 Storage – Days of Supply
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11,500 11,750 12,000 12,250 12,500 12,750 13,000 2025 Demand ResCom + Industry + Autogas + Other PDH Ethylene 2030 Demand Non-U.S. Supply Call on U.S. Supply Global LPG Demand (MBD) 23 ▪ Global ResCom consumption growth and chemical projects add ~1.0 MMBD of LPG demand through 2030 with the majority supplied by the U.S. ▪ Middle East LPG export terminal damage and ongoing Strait of Hormuz closure has cut off >1 MMBD of global LPG supply, increas ing demand for U.S. LPG exports ▪ U.S. LPG export terminal expansion projects will add ~950 MBD of nameplate capacity by 2029 to support expected call on U.S. supply ▪ Reduced naphtha exports from Russia and the Middle East are generating demand for replacement NGL feedstocks ~770 MBD Source: Platts, EIA, Energy Aspects, IEA, Range Resources NGL Macro Strengthens with International Demand Growth Increasing Global Demand Being Supplied by U.S. LPG
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Global LPG Supply and Demand Markets Shift ▪ U.S. share of global LPG exports has risen to 56% in 2026 ▪ U.S. LPG exports increased 475 MBD, or 20%, in 2Q26 vs. 2025 ▪ Reduced OPEC LPG exports to Asia increase demand for U.S. supply U.S. LPG Export Expansions Will Supply Global Demand ▪ Terminals expected to remain full in 2026 as Middle East LPG exporters struggle to restart business as usual ▪ U.S. LPG export capacity to grow ~950 MBD, or 36% by 2029 ▪ High terminal utilization reinforces tighter U.S. LPG fundamentals, supporting Mont Belvieu prices and premiums at U.S. docks 24 Growing U.S. LPG Market Share with Rising Exports Source: Platts, IEA, EIA, Energy Aspects, Vortexa, RRC estimates U.S. LPG Export Terminal Buildout U.S. LPG Supply Shifts to Unfulfilled OPEC Buyers U.S. Exports Efficiently Meet Global LPG Demand - 500 1,000 1,500 2,000 2,500 3,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1Q26 2Q26 U.S. LPG Export Destinations (MBD) China Asia (Ex-China and India) India Europe Americas Other 0% 10% 20% 30% 40% 50% 60% - 1,000 2,000 3,000 4,000 5,000 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 YTD U.S. Market Share Waterborne LPG Trade (MBD) U.S. Waterborne LPG Trade Non-U.S. Waterborne LPG Trade U.S. Market Share 2,626 3,573 360 300 60 132 400 55 2,500 2,700 2,900 3,100 3,300 3,500 3,700 2025 Base 2026 2027 2028 Total U.S. LPG Export Capacity (MBD) Enterprise-NR2 Flex 2026 Enterprise Repauno Targa Oneok/MPLX ET Nederland
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0 200 400 600 800 1,000 1,200 Ethylene Cash Cost by Feedstock ($/mt) 329 394 460 424 508 593 - 100 200 300 400 500 600 Ethane LPG Ethane LPG Ethane LPG Feedstock Equivalent (Rationalized Capacity - 50% Operating Rate) Feedstock Equivalent (Rationalized Capacity - 60% Operating Rate) Feedstock Equivalent (Rationalized Capacity - 70% Operating Rate) Ethylene Steam Cracker Feedstock Switching (MBD) Global Ethylene Production ▪ Although ethylene demand has grown by 8.5% since 2021, the global overbuild of ethylene production capacity has suppressed operating rates ▪ Asia and Europe are rationalizing older, less efficient naphtha-fed ethylene steam crackers ▪ Ethane and LPG fed crackers fill the void left by shuttered naphtha crackers. Naphtha crackers yield up to 20% propylene, and any lost naphtha-based propylene supply will shift to PDH units, benefiting PDH operating rates ▪ Global ethylene demand forecasted to grow ~+9.5% by 2028 ▪ Ethane & LPG-fed ethylene steam crackers are historically the lowest cash cost in the world, supporting continued demand for U.S. supply 25 Low Cash Cost U.S. NGLs Preferred Over Alternative Feedstocks Source: Platts, Energy Aspects, RRC estimates Ethane & LPG Supply Needed to Backfill Displaced Feedstock Demand Announced Naphtha-Fed Ethylene Production Closures Global Naphtha Cracking Rationalization Supports U.S. NGL Demand Feedstock Equivalent Demand Displaced Through 2028 U.S. NGLs at Low End of Cost Curve 424 130 220 49 823 - 100 200 300 400 500 600 700 800 900 2025 2026 2027 2028 Total Nameplate Naphtha Feedstock Closures (MBD)
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Incremental Exports Tighten Days of Supply Outlook ▪ Neches River Phase 2 operating at 90% capacity for the remainder of 2026 generates ~60 MMB of additional demand and deteriorates stock surplus to the 5-year average ▪ New Houston Ship Channel terminal adds ~300 MBD of terminal capacity in December of 2026 and the Repauno terminal adds 60 MBD of propane export capacity in 1Q27, supporting sustained LPG export growth ▪ Days of supply tightness to the 5-year average supports uplift in domestic prices towards the second half of 2026 Propane Export Capacity ▪ Neches River Phase 2 terminal has "flex" export capacity of ~180 MBD C2 / 360 MBD C3 ▪ Neches River Phase 2 is expected to be fully utilized exporting propane, bolstering U.S. nameplate LPG terminal capacity by ~+14% ▪ U.S. propane exports averaged ~2.1 MBD in May-June, +13% higher year-on-year, supported by the new capacity ▪ The majority of this new flex capacity is contracted to ethane buyers beginning in 2027, however additional LPG export capacity expected to come online early in 2027 keeps LPG export capacity levels constant 26 Robust Propane Exports Tighten Days of Supply Forecast Source: Platts, EIA, RRC estimates Propane Stocks Building at Historically Low Rates in 2026 New Flex Terminal Capacity Supports Tighter Propane Fundamentals ~722 MBD 31 28 10 15 20 25 30 35 40 45 50 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Propane Days of Supply 5-YR Range 5-YR Avg 2026 EIA STEO Forecast 2026 Export Adjusted Forecast (10) - 10 20 30 40 50 60 70 Apr May Jun Jul Aug Sep Cumulative Propane Stock Build (MMBBLs) 5-Yr Range 2022 2023 2024 2025 2026 5-Yr Avg
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4,500 4,750 5,000 5,250 5,500 5,750 6,000 United States + Canada China Rest of World 2025 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 ~750 MBD by 2030, requiring additional ethane supply ▪ Steam cracker demand capacity outside the U.S. and Canada accounts for ~500 MBD, or ~67% of new global projects. Since ethane-fed ethylene crackers are at the low end of the cost curve, they will benefit from higher operating rates compared to the rest of the ethylene fleet. 27 U.S. Supplies 100% of Global Waterborne Ethane Supply Source: Platts, IEA, EIA, Energy Aspects, Vortexa, 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 ~440 MBD of additional capacity, falling short of the call on U.S. supply ▪ VLEC fleet adding 47 newbuilds, or ~695 MBD in 2026-2027 to support U.S. terminal expansion projects ▪ Further U.S. ethane export terminal expansions will be required to satisfy remaining international demand growth ▪ New U.S. ethane export capacity will alleviate bottlenecks and support further growth projects Global Ethylene Demand Growth Drives U.S. Ethane Exports ~500 MBD 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% - 100 200 300 400 500 600 700 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 YTD U.S. Market Share Waterborne Ethane Trade (MBD) U.S. Waterborne Ethane Trade Non-U.S. Waterborne Ethane Trade U.S. Market Share
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28 ESG
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0.013% 0.007% 0.010% 0.005% 0.000% 0.010% 0.020% 0.030% 0.040% 0.050% 2023 2024 2025 Methane (CH4) Emissions Intensity as % of total oroduction from wells RRC CH4 Emissions Intensity (Pre-RY2025 Subpart W Amendments) RRC CH4 Emissions Intensity Industry-Leading Emissions Targets ▪ Maintained Net Zero for Scope 1 and 2 GHG emissions through direct emissions reductions and verified carbon credits ▪ Range maintained an “A” grade from MiQ following the 2026 certification of its Pennsylvania assets Comprehensive Emissions Management Framework ▪ LDAR survey frequency of 8x per year on 100% of our assets ▪ Continuous methane and ambient air monitoring programs to enhance emissions detection, facility designs and operational transparency ▪ Low end of methane emissions intensity compared to peers Commitment to Clean & Efficient Operations ▪ Recycled ~100% of produced water generated from our operations for more than a decade ▪ 49% of total water used for operations in 2025 was reuse water ▪ Water recycling lowers completion costs and LOE Top-Tier Emissions Management Program 29 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 for Range proxy peer group, most recent report covering reporting year 2023 Leading in Environmental Practices 0.00% 0.10% 0.20% 0.30% 0.40% 0.50% 0.60% 0.70% 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 (CH4) Emissions Intensity as % of total gas production from wells MiQ intensity threshold for Grade A – 0.05%
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30 ✓ Average Director tenure of five years ❖ Chris Kendall appointed to the Board in February 2025 ❖ Charles Griffie appointed to the Board in October 2023 ✓ Range seeks to achieve a diverse 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 Stewardship ✓ Over $5 billion paid to impact fees, royalty and lease payments, and charitable contributions through 2025 ✓ Volunteered 3,600+ employee hours in 2025 ✓ Named to Newsweek Magazine’s 2025 Most Responsible Companies list ✓ Recognized as one of JUST Capital’s Most JUST Companies ✓ Awarded 2026 Pittsburgh Excellence in Ethics Award ✓ Zero severe injuries in 2025 ✓ 62% reduction in Contractor and Range employee Days Away, Restricted, or Transferred since 2023 (DART) ✓ Safe Driving Campaign to focus on awareness, training, and equipment ✓ Five recordable Range employee incidents in 3.6 million work hours since 2023 Governance & Social Responsibility
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31 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 and S&P Oil & Gas E&P as peers to capture performance relative to the broader market ✓ 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 ✓ 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 Shareholder Outreach to Greater than 65% of Shares Outstanding Executive Compensation Aligned with Shareholders
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32 Appendix
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Utica/Point Pleasant 33 ▪ ~1.5 million net effective acres(a) in PA provides decades of drilling inventory ▪ Activity led by Core Marcellus development in Southwest PA ▪ ~1,600 producing Marcellus wells demonstrate consistent, high quality 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) 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 Appalachia – Stacked Pay 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 ▪ ~1,600 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 2026 activity on existing pads, similar to recent years ▪ Well results after several years from returning to existing pads show no degradation in recoveries 34 Southwest Pennsylvania = Existing Pad >30 Years(a) of High-Quality Marcellus Inventory that Breaks Even Below $2.50 Note: Highlighted areas represent townships where Range holds ~2,000 or more acres. Multi-Decade Inventory of Capital Efficient Wells (a) Based on maintenance activity levels for 2.6 Bcfe/d.
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35 ▪ Approximately 70,000 net acres prospective for Marcellus development ▪ 2025 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. Northeast Pennsylvania
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36 ▪ 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. Northwest Pennsylvania – Utica/Point Pleasant
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37 Gross Estimated Cumulative Recoveries by Year Note: 2026 plan costs and type curves assume 10,000 ft. average lateral length. Average SWPA NRI is ~79.5%. NGL recoveries assume 80% ethane extraction. Marcellus Modeling Data Liquids Rich Area ▪ ~350,000 Net Acres ▪ EUR / 1,000 ft. = 3.2 Bcfe ▪ 2026 D&C Cost / ft. = $850 Dry Gas Areas ▪ ~170,000 Net Acres ▪ EUR / 1,000 ft. = 2.2 Bcfe ▪ 2026 D&C Cost / ft. = $830 Year Residue (Mmcf) 1 3,685 2 5,600 3 7,007 5 9,113 10 12,594 20 16,745 EUR 21,561 Year Condensate (Mbbls) Residue (Mmcf) NGL (Mbbls) 1 24 1,910 340 2 31 3,085 549 3 36 3,998 712 5 43 5,426 966 10 52 7,974 1,420 20 61 11,236 2,001 EUR 70 15,050 2,680 Previous Wet and Super-Rich Area type curves combined into a single Liquids Rich Area as an increasing number of long laterals are extending across both areas. Dry Gas Areas type curve expanded to include Northeast Pennsylvania.
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% of RRC Barrel Mont Belvieu ($/gal) Avg. 2024 Avg. 2025 1Q 2026 2Q 2026 3Q 2026E 4Q 2026E Avg. 2026E 53% Ethane $0.19 $0.25 $0.23 $0.21 $0.22 $0.23 $0.23 27% Propane $0.78 $0.75 $0.66 $0.78 $0.74 $0.77 $0.74 8% Normal Butane $1.01 $0.91 $0.88 $1.08 $1.03 $1.05 $1.01 4% Isobutane $1.15 $0.95 $0.89 $1.12 $1.09 $1.06 $1.04 8% Natural Gasoline $1.51 $1.35 $1.50 $1.94 $1.78 $1.68 $1.72 $0.56 $0.55 $0.53 $0.61 $0.59 $0.59 $0.58 $23.44 $23.28 $22.21 $25.61 ~$24.75 ~$24.75 ~$24.25 $2.33 $0.87 $4.41 $3.49 ~$0.00-$1.00 ~$0.00-$1.00 $2.00-$2.50 $25.77 $24.15 $26.62 $29.10 ~$24.75-$25.75 ~$24.75-$25.75 ~$26.25-$26.75 Range-Equivalent Mont Belvieu Barrel ($/gal) Range-Equivalent Mont Belvieu Barrel ($/bbl) Range's Pre-Hedge Realization ($/bbl) Range's NGL Differential ($/bbl) 38 2026 Guidance Improved to a Premium of $2.00 to $2.50 above the Mont Belvieu Equivalent 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 7/17/2026. Calculations illustrate pre-hedge realizations. Conversion rate is 42 gallons : 1 barrel NGL Price Calculation Example
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39(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. Range 2026 Guidance Updated 2026 Prior 2026 Guidance Guidance - April Production per Day 2.35 - 2.40 Bcfe 2.35 - 2.40 Bcfe Capital Expenditures $650-$700 Million $650-$700 Million Maintenance Drilling & Completion $500 Million $500 Million Growth Drilling & Completion $120 - $140 Million $120 - $140 Million Maintenance Land $10 - $20 Million $10 - $20 Million Targeted Acreage to Increase Future Inventory $5 - $15 Million $5 - $15 Million Pneumatic Devices, Facilities and Software $15 - $25 Million $15 - $25 Million Cash Expense Guidance Direct Operating Expense per mcfe $0.12 - $0.13 $0.12 - $0.13 TGP&C Expense per mcfe $1.55 - $1.60 $1.55 - $1.60 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 $22 - $28 Million $22 - $28 Million Net Interest Expense per mcfe $0.07 - $0.09 $0.07 - $0.09 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 ($0.35) - ($0.40) ($0.35) - ($0.45) Natural Gas Liquids(a) +$2.00 to +$2.50 per barrel +$1.25 to +$2.50 per barrel Oil/Condensate Differential to WTI ($10.00) - ($12.00) ($10.00) - ($14.00)
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40 Range’s Hedging Strategy, Marketing Contracts, and Diversified Production Mix Support Consistent Operational Plans and Shareholder Returns Through the Cycles. Note: Hedges as of 7/10/26, 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). 2H 2026 Hedging 2027 Hedging Hedge Summary 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60%% of Revenue Natural Gas Oil NGLs 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60%% of Revenue Natural Gas Oil NGLs Avg. Floor Avg. Ceiling Natural Gas $4.04 $4.21 Oil - - Avg. Floor Avg. Ceiling Natural Gas $3.87 $4.58 Oil $65.00 $77.63 2028 Hedging 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60%% of Revenue Natural Gas Oil NGLs Avg. Floor Avg. Ceiling Natural Gas $3.50 $4.50 Oil - -
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$1.4 $1.2 $0.9 $4.1 $3.9 $3.2 $3.1 $2.7 $1.9 $1.6 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 2025 2Q26 $500 $381 $0 $500 $1,000 $1,500 $2,000 $2,500 2026 2027 2028 2029 2030 2030 Range Notes Bank Credit Facility RRC Net Debt(a) $ billion 41 RRC Maturity Profile(b) $ million (a) Borrowings as of 6/30/26 (b) 2Q26 weighted average interest rate 5.4%(b) 4.75% Resilient Balance Sheet Strong Balance Sheet Provides Flexibility Through the Cycles and Lower Debt Improves Cost Structure Ability to Maintain <1x Debt/EBITDAX at $3 NYMEX Natural Gas
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42 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 Contact Information