EX-99.2 3 d862091dex992.htm EX-99.2

Exhibit 99.2

Goldman Sachs Global Energy Conference 2020

Forward Looking Statements All statements, except for statements of historical fact, made in this presentation regarding activities, events or developments the Company expects, believes or anticipates will or may occur in the future 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.

Range – At a Glance Unmatched Southwest Appalachia Inventory â–ª Approximately one half million net acres provide decades of low-risk drilling inventory â–ª Contiguous position allows for efficient operations and long-lateral development â–ª Peer-leading well costs and productivity underpin top-tier recycle ratio –ª Proved Reserves of 18.2 Tcfe at YE2019 – SEC PV-10 of over $17 per share, net of debt(a) Sustainable Free Cash Flow â–ª Peer-leading well costs + Shallow base decline = Low maintenance capital requirements â–ª Low maintenance capital requirements support free cash flow through the cycles –ª Cost structure improvements enhance margins and durability of free cash flow â–ª Disciplined spending evidenced by consecutive years of spending below original budget Leader on Sustainability and Environmental Practices –ª Reduced environmental impact and enhanced profitability through: â–ª Water recycling and logistics â–ª Long-lateral development â–ª Electric-powered fracturing fleet â–ª Innovative facility designs â–ª Robust LDAR program (a) SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI

Unmatched Inventory in Southwest Appalachia ~3,700 undrilled core Marcellus wells(a) provide decades of low-risk drilling opportunities Marcellus resource potential(b) ~ 40 Tcf of natural gas ~ 3 billion barrels of NGLs ~ 149 million barrels of condensate Significant inventory of highly prolific Utica wells extends Range’s dry gas opportunity Existing natural gas and NGL infrastructure de-risks future development Contiguous acreage position provides for operational efficiencies and industry leading well costs: â–ª Long-lateral development â–ª Efficient water handling and long-term infrastructure utilization (a) Estimates as of YE2018; based on production history from ~1,000 Range-drilled wells. Includes ~300 locations not shown on map. Based on 10,000 ft lateral length (b) As of YE2018. Does not include over 18 Tcfe in proved reserves.

Value of Year-End 2019 Proved Reserves – Over $17 per share Included in SEC Reserves â–ª Only 5 years of development activity â–ª Proved Developed reserves of 9.9 Tcfe â–ª Proved Undeveloped reserves of 8.3 Tcfe â–ª Approximately 440 Marcellus locations Reserve Value Ignores Resource Potential â–ª Resource Potential of ~100 Tcfe â–ª Over 3,000 undrilled core Marcellus wells, or over 40 years of inventory at current drilling pace â–ª Potential from ~400,000 net acres of both core Utica and Upper Devonian Reserve History â–ª PUD Development Costs consistently better than Appalachia peers â–ª Positive performance revisions to reserves each year for the last decade Range Currently Has a $100 Million Share Buyback Program Designed to Repurchase Shares at a Steep Discount to Intrinsic Value Note: SEC PV-10 assumes $2.58/Mmbtu NYMEX natural gas and $55.73/bbl WTI

Capital Efficiency Driven by Peer-Leading Well Costs & Decline Rate Well Costs per Lateral Foot 2020 Decline Rate $1,400 40% $1,200 35% $1,000 30% 25% $800 20% $600 15% $400 $200 10% 5% $0 RRC RRC Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 0% 2020 2019 RRC Peer 2 Peer 1 Peer 4 Peer 3 Peer 5 Peer 6 D&C Capex per Mcfepd Reflects Relative Capital Efficiency 2018 Year-to-Date 2019 $606 $550 $553 $511 $453 $394 $377 $380 $338 $278 $301 $306 $259 $239 Peer 4 RRC Peer 1 Peer 6 Peer 3 Peer 2 Peer 5 RRC Peer 4 Peer 2 Peer 3 Peer 6 Peer 1 Peer 5 Peer-Leading Development Costs & Decline Rate Drive Lowest Development Costs per Unit of Production in Appalachia Note: Peers include AR, CNX, COG, EQT, GPOR and SWN. Peer estimates from company filings, presentations, transcripts, guidance and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only.

Cash Recycle Ratio Shows Quality and Durability of Asset Base 250% 200% 150% 100% 50% 0% Appalachia Gas Peer Oil Peer Source: MKM Partners. “Energy/Exploration & Production Outlook”. June 2019. Cash Recycle Ratio = Cash Operating Margin divided by Capital Intensity. Companies shown include APC, AR, CHK, CLR, CNX, COG, CRZO, CXO, DVN, ECA, EOG, EQT, GPOR, HES, HPR, LPI, MRO, MTDR, MUR, PDCE, PXD, SM, SRCI, SWN, WLL, WPX and XEC.

Maintenance Capital Drives Free Cash Flow Through the Cycles Sustainable Shallow Free Cash Base Decline Low Maintenance Capital Shallow Base Decline Driven by: â–ª Core Marcellus position â–ª 10+ years of drilling history in Marcellus provides solid base of low-decline wells –ª Infrastructure built to maximize returns, not peak initial rates â–ª 2020 base decline rate of ~20% is sustainable, even with modest growth in base production â–ª Shallow base decline, coupled with efficient operations allows for low maintenance capital Low Maintenance Capital Supports Sustainable Free Cash Flow â–ª Minimum capital requirements to maintain existing production levels compared to peers â–ª Generating free cash flow is priority in capital allocation process â–ª Free cash flow is durable given Range’s multi-decade core Marcellus inventory

Improving Cost Structure Enhances Cash Flow & Margin Growth $2.20 Over Half of Targeted $2.10 Savings Have Already e ) Been Achieved f mc $2.00 r p e $1.90 $ ( s $1.80 t Cos $1.70 g tin $1.60 a Oper $1.50 sh $1.40 Ca $1.30 $1.20 4Q18 1Q19 2Q19 3Q19 4Q19 4Q23 (Original Target) TGP&C LOE Production Taxes Cash G&A Interest Q4 2019 Unit Costs Expected to Be <$2.00 per Mcfe

Leading in Sustainability and Environmental Practices Environmental Responsibility Highlights Range is actively Ranked second among Range’s water sharing working to achieve zero top producers on water program is recycling net emissions across management 153% of its own and its operations and corporate offset producers water environmental policies1 1 Rankings according to “Disclosing the Facts 2019: Transparency and Risk in Water & Chemicals Management for Hydraulic Fracturing Operations”

Natural Gas Demand – Increases 21 Bcf/d in Next 5 Years 2019-2024 Demand Outlook â–ª Total demand growth of +21 Bcf/d through 2024 from LNG and Mexican exports, industrial and electric power demand growth â–ª LNG export capacity to increase by mid-2020 to 10 Bcf/d from projects under-construction â–ª Second Wave LNG Projects could add another +10 Bcf/d of exports by 2025 â–ª Continued coal (currently ~30% of power stack) and nuclear retirements (~20% of power stack) U.S. LNG Export Demand Outlook â–ª Second Wave of U.S. LNG Projects has started, with 5.1 Bcf/d already under-construction and another +5 Bcf/d likely to FID in 2019-2020 â–ª Over 30 Bcf/d of Second-Wave LNG projects have been proposed â–ª Futures prices support additional LNG exports â–ª Range forecasts U.S. LNG export capacity to reach ~13 Bcf/d in 2022 and ~18 Bcf/d by late 2023-early 2024 U.S. LNG Export Terminal Capacity (Bcf/d) 22 20 Port Arthur FERC Approved and/or >70% long-term offtake Magnolia LNG 18 signed. Potential Next Freeport T4 16 Wave Projects. Cameron T4-T5 14 Under Construction Golden Pass T1-T3 or In-Service Sabine Pass T6 12 Calcasieu Pass 10 Corpus Christi T3 Freeport T1-T3 8 Cameron T1-T3 6 Corpus Christi T1-T2 Elba Island 4 Cove Point 2 Sabine Pass T1-T5 0 12/16 12/17 12/18 12/19 12/20 12/21 12/22 12/23 12/24 Source: EIA, LNG Operator announcements Futures Market Indicates LNG Arb is OPEN 8.00 7.50 7.00 6.50 6.00 t u /MMb 5.50 $ 5.00 4.50 4.00 3.50 3.00 Nov-19 Nov-20 Nov-21 Nov-22 Nov-23 Nov-24 EU Gas (NBP) $/MMBtu USGC Delivered Full Cost to EU USGC Variable Cost to EU Bloomberg prices as of 10/21/19.

Natural Gas Supply—Base Decline & Capital Discipline Base Declines Offset Current Activity â–ª Average U.S. decline rate of 26% equates to ~27 Bcf/d of new gas required each year to simply hold production flat â–ª After drawing down DUCs, industry growth should slow meaningfully into 2H2020 and 2021 if strip prices hold Producer Discipline Materially Impacts Supply Forecast â–ª Industry spending being limited to cash flow in 2019 and beyond â–ª Consensus 4Q-4Q growth forecast now just ~4% (0.8 Bcf/d) for Appalachia peer group, significantly improving gas macro for late 2020 and 2021 â–ª Minimal Appalachia growth expected at current strip pricing and ~50 rigs â–ª Private Equity-backed operators may shift to a free cash flow model as traditional exit strategies become challenged (IPO, corporate M&A, etc.) Associated Gas Growth Not Capable of Offsetting Dry Gas Decline and Expected Demand Growth U.S. Natural Gas Base Decline Rate Source: RS Energy

NGL Macro Improving New Export Infrastructure 2019-2020 â–ª 2019 export capacity to increase by ~400 MBPD and by ~650 MBPD in 2020 versus EIA gas plant LPG supply of 2,559 MBPD in September 2019. â–ª U.S. waterborne export capacity increases equivalent to over 40% of U.S. LPG supply, which should tighten balances going forward â–ª Local Northeast propane differentials have narrowed since start up of Mariner East 2 Storage & Supply â–ª Export-adjusted storage days of supply 18% below the five-year average as end of November â–ª NGL supply growth to slow in 2020 with decreasing U.S. crude and natural gas supply growth. New Demand â–ª Indian LPG import terminal expansions under-construction/planned of 350 MBPD in 2020-25 â–ª In 2020, 5 PDH plants scheduled to start up in China with combined capacity of 115 MBPD propane demand â–ª Relative economics support use of LPG over naphtha for international steam crackers Range’s Ability to Export Provides Price Diversity Ethane Price Diversity Propane & Butane Mont Belvieu Northeast / Mont Belvieu Oil-Linked Gas-Linked Exports Note: Represents Appalachia only. Pie chart represents annual average. Range has the ability to increase domestic sales in winter months when local prices are strong. International Price Strength Versus Mont Belvieu $0.35 o n) gall $0.30 er $0.25 p ( $ Arb $0.20 e $0.15 Propan $0.10 ational $0.05 Inter n $0.00 ($0.05) 8 8 2018 2019 /2018 5 /201 /2018 /2018 5 5 /2018 /2018 /201 /2018 5 /2018 /2018 5 5 /2018 5 / /2019 /2019 /2019 /2019 /2019 5 /2019 /2019 /2019 5 /2019 / 5 5 /2019 5 /2019 1 /5 2/ 3 /5 4/ 5/ /5 6 /5 7 8/ 9 /5 / 10 / 11 / 12 /5 1 2 /5 /5 3 /5 4 /5 5 6/ /5 7 /5 8 9/ 10 / / 11 / 12 Note: Calculated as front-month European C3 price (ARA), less shipping costs from the U.S. Gulf Coast to Europe (ARA), relative to Mont Belvieu C3 price

Range is Positioned Well for Low Commodity Prices Self-Funded Business Model â–ª Flexible capital program as all of Range’s firm transportation commitments have been met â–ª Shallow base decline supports low maintenance capital requirement â–ª Low maintenance capital and high capital efficiency promote free cash flow generation through the cycles â–ª Marcellus inventory enables multi-decade, sustainable free cash flow profile Liquidity Profile â–ª Ample liquidity given sustainable free cash flow profile â–ª Over $1 billion in debt reduction since mid-2018 â–ª Credit facility unanimously ratified in March 2019 â–ª $4+ billion max conforming borrowing base â–ª Elected Commitment increased from $2.0 billion to $2.4 billion in October 2019 â–ª Revolver borrowings expected to be reduced via potential asset sales and free cash flow generation $4,500 $4,000 Max Conforming $3,500 $3,000 Borrowing Base $2,500 $2,000 $1,500 Elected Commitment $1,000 $500 Revolver Borrowings $0 Borrowings Credit Facility ($ millions) ($ millions) Note: Revolver borrowings as of 9/30/19.

Appendix

Peer-Leading Capital Efficiency Range’s Estimated 2020 Capital Efficiency Remains Consistent With Prior Year, Versus Some Peers Who May Rely on One-Time DUC Drawdowns. $500 Implied D&C Maintenance Capital per Mcfepd $450 $400 $384 $387 $388 $350 $325 $302 DUCs? DUCs? $300 $260 $250 $200 $150 RRC Peer 1 Peer 2 Peer 4 Peer 3 Peer 5 2018 2019 2020 3-Year Average 2016 2017 2018 2019E 2020E (a) (c) 4Q Production (Mmcfepd) 1,854 2,170 2,260 2,340 2,300 Decline Rate from Prior Year 4Q 24% 23% 20% 20% 4Q-4Q Base Decline (Mmcfepd) 449 508 452 468 (b) (b) 4Q-4Q Growth (Mmcfepd) 316 110 135 -40 Total Production Added (Mmcfepd) 765 617 587 428 D&C Costs Incurred ($ millions) $1,180 $836 $665 $500 D&C Capex per Mcfepd Added $1,542 $1,354 $1,133 $1,168 Implied D&C Maintenance Capital $692 $688 $512 $547 Implied D&C Maintenance Capital per Mcfepd $373 $317 $227 $234 Note: Southwest Appalachia peers include AR, CNX, EQT, GPOR and SWN. Peer estimates based on Company disclosures and Consensus estimates as of 12/31/19. (a) Includes 10 Bcfe of curtailments in 4Q18 from third-party processing downtime. (b) Pro forma asset sales. (c) Illustrative example based on full-year 2020 guidance. Does not represent quarterly guidance.

D&C Capex per Mcfepd Reflects Relative Capital Efficiency 2018 Quarterly Summary 1Q18 2Q18 3Q18 4Q18 $192 $177 $180 $171 $165 $156 $157 $152 $151 $152 $139 $137 $128 $124 $118 $117 $113 $108 $104 $97 $101 $84 $93 $84 $82 $74 $61 $41 2019 Quarterly Summary 1Q19 $202 2Q19 3Q19 4Q19E $169 $159 $139 $123 $123 $117 $119 $98 $93 $94 $92 $94 $92 $91 $92 $89 $91 $86 $80 $83 $79 $79 $66 $72 $47 $53 $37 Note: Peers include AR, CNX, COG, EQT, GPOR and SWN. Peer estimates from company filings, presentations, transcripts, guidance and Range estimates. SWN estimates for 2018 represent Appalachia production and capital expenditures only. 4Q19 estimates based on FactSet Consensus as of 12/31/19.

Appalachia Assets – Stacked Pay â–ª ~1.5 million net effective acres(a) in PA leads to decades of drilling inventory â–ª Gas In Place analysis shows the greatest potential is in Southwest Pennsylvania â–ª Approximately 1,000 producing Marcellus wells demonstrate high quality, consistent results across Range’s position â–ª Near-term activity led by Core Marcellus development in Southwest PA â–ª Range’s Utica wells continue to produce strongly and our most recent well continues to be one of the best in the play â–ª Adequate takeaway capacity in Southwest PA Stacked Pay and Existing Pads Allow for Multiple Development Opportunities (a) Assumes stacked pay opportunities in Marcellus, Utica and Upper Devonian Upper Devonian Marcellus Utica/Point Pleasant

Targeting / Downspacing Production Results 3,000 2,500 â–ª Optimized targeting shows ~50% ft . increase in cumulative production after 1,000 2,000 1,300 days per â–ª No detrimental production impact seen Mmcfe/Day 1,500 on the original wells Normalized 1,000 500 - 0 200 400 600 800 1000 1200 1400 AVERAGE ORIGINAL TARGETING AVERAGE OPTIMIZED TARGETING

Return to Existing Pads – Marcellus 100,000 10,000 Additional 3 wells (MCFD)1,000 Gas Wellhead 100 10 1 Mar-14 Oct-14 May-15 Dec-15 Jul-16 Mar-17 Oct-17 May-18 Dec-18 Wellhead Gas Ability to target our best areas with significant cost savings

Significant Utica Resource â–ª Range has drilled three Utica wells â–ª Range’s third well appears to be one of the best dry gas Utica wells in the basin (next slide) â–ª Continued improvement in well performance due to higher sand concentration and improved targeting â–ª 400,000 net acres in SW PA prospective The Industry Continues to Delineate the Utica around Range’s Acreage Note: Townships where Range holds ~2,000+ or more acres are shown outlined above

Utica Wells – Wellhead Pressure vs. Cumulative Production Range’s DMC Properties well one of the best in the Utica

Innovative NGL Marketing Agreements Enhance Pricing â–ª First-mover on Appalachian NGL exports to Europe via ethane sales to INEOS using Mariner East capacity â–ª Range’s propane has been sold internationally since 2016 through Marcus Hook, with option to sell into premium NE winter markets â–ª Mariner West ethane sent to Nova Chemical (Canada) â–ª ATEX moves Appalachia ethane to the Gulf Coast (Mont Belvieu)

High Quality Reserve Base â–ª Proved reserves of 18.2 Tcfe as of year end 2019 â–ª Future development costs for proved undeveloped reserves are estimated to be $0.35 per Mcfe at YE2019 20 2019 SEC PV10 18 of $7.6 billion 16 (Tcfe) 14 serves 12 R e 10 ved 8 P ro Total 6 4 2 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Positive Performance Revisions for Last Decade Indicate Quality of Reserves

Natural Gas & NGL Macro Outlook

Natural Gas—35% of the U.S. Generation Mix in 2018 Growing Market Share in Power Gen. â–ª Gas power demand grew by 11 Bcf/d from 2009-2018, while coal declined 11 Bcf/d(a) and renewables grew 5.3 Bcf/d(a) Market Share Growth Should Continue â–ª 25 Bcf/d of coal generation remains to be displaced, or ~27% of U.S. Power Generation Mix â–ª 53 GW of coal plant capacity retired from 2013-2018, and another 36 GW of plant retirements have already been announced for 2019-2024 â–ª More retirement announcements expected to occur in coming months/years â–ª Planned nuclear retirements also remove large base-load of power generation â–ª New gas-fired reciprocating engines being added to balance grid instability issues created by renewables (a) Assumes 7x Heat Rate for gas equivalence U.S. Power Generation by Source(a) 40 35 30 t 35% e n 33% 34% 32% 25 30% uival 28% 28% E q 25% 20 24% 23% Day 21% r p e 15 f Bc 10 8% 10% 10% 7% 7% 5 3% 4% 5% 6% 4% 5% 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Coal Gas Nuclear Hydro Solar+Wind Other Source: EIA Announced Coal & Nuclear Reactor Retirements 16,000 5.0 14,000 s Di 4.0 (MW) 12,000 10,000 3.0 placement 8,000 6,000 2.0 (Bcf/ Retirements 4,000d 1.0 2,000 equival 0 0.0 ent 2019 2020 2021 2022 2023 2024 2025 ) Coal Nuclear Cumulative Displacement Source: EIA

Shale Efficiency Gains Are Slowing Oil Basins â–ª Limited Tier-1 runway left in Williston, Mid-Con, DJ Basin and Eagle Ford as cores are believed to have been heavily drilled â–ª Up-spacing across several plays reduces core inventory life â–ª Efficiency gains from lateral length and proppant intensity now seeing diminishing returns versus three years ago â–ª Parent-child issues becoming more prevalent as child wells produce materially less than parent wells Haynesville â–ª Well productivity in the Haynesville appears to have plateaued â–ª Runway for current productivity may be limited given current pace of development in the play and that the core is known to be small â–ª Private operators may be forced to reduce growth as traditional exit strategies have become challenged 6-Month Daily Oil Production per 1,000 Lateral Ft. Source: Cowen and Company, Enverus Haynesville Production per 1,000 Lateral Ft. Source: RS Energy

Dry Gas Basin Break-Evens Suggest Higher Prices Supply Growth Needed from Dry Gas Basins â–ª EIA forecasts 6.7 Bcf/d of 2019-2024 supply growth from outside of Northeast (mostly associated gas) â–ª Demand growth forecast of +21 Bcf/d from 2019-2024 will require growth from dry gas basins to balance market Higher-Than-Strip Prices Will Be Needed to Support Dry Gas Basin Growth â–ª Northeast PA will face constraints given current lack of infrastructure â–ª Dry gas basins likely require >$3/Mmbtu natural gas to support sustainable growth Industry Break-Evens Above Current NYMEX Futures Curve $5.00 $4.50 $4.30 $4.00 $3.75 $3.32 $3.33 $3.37 $3.40 $3.50 $3.07 /mcf $3.00 $ $2.43 Gas $2.50 EX M $2.00 NY $1.50 $1.00 $0.50 $0.00 Marcellus—NE PA Marcellus—SW Marcellus—WV Marcellus—SW Marcellus—Upper Utica—Dry Gas Utica—Wet Gas Marcellus -PA Dry Dry PA—Wet Marcellus Ohio Central PA Source: J.P. Morgan. Break-evens assume 25% pre-tax full-cycle rate of return to account for corporate G&A, interest expense and acreage costs.

L48 Dry Gas Production Growth Slowing U.S. L48 Pipeline Flows (Bcf/d) 94 92 90 88 86 84 82 80 78 76 74 72 70 68 1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec 2017 2018 2019 Source: Platts

LNG Growth Expected to Continue U.S. LNG Export Terminal Capacity (Bcf/d) Second Wave 22 FIDs & Potential 20 Port Arthur FERC Approved and/or >70% long-term offtake Magnolia LNG 18 signed. Potential Next Freeport T4 16 Wave Projects. Cameron T4-T5 14 Under Construction Golden Pass T1-T3 or In-Service Sabine Pass T6 12 Calcasieu Pass 10 Corpus Christi T3 Freeport T1-T3 8 Cameron T1-T3 6 Corpus Christi T1-T2 Elba Island 4 Cove Point 2 Sabine Pass T1-T5 0 12/16 12/17 12/18 12/19 12/20 12/21 12/22 12/23 12/24 Source: Operator Estimates

U.S. Natural Gas Exports to Mexico Making New Highs U.S Natural Gas Exports to Mexico (Bcf/d) 6.5 6.0 5.5 5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 014 014 014 015 015 015 016 016 016 017 17 0 018 019 /2 1/5 /2 4/5 /2 7/5 /2014 /2 1/5 4/5 /2 /2 7/5 /2015 1/5 /2 /2 4/5 /2 7/5 /2016 /2 1/5 4/5/2017 7/5/2017 0/5 /2 1/5/2018 4/5/2018 7/5/2018 /2 0/5 1/5/2019 4/5/2019 7/5/2019 0/5 /2 10/5 10/5 10/5 1 1 1 Source: Bloomberg 31

NGL Macro Outlook NGL Demand â–ª IEA forecasts LPG (propane and butane) and ethane to be the fastest growing global oil products over medium and long term â–ª Demand growth driven primarily by petrochemical feedstock demand and residential demand in developing countries â–ª U.S. waterborne export capacity increases in 2019 equivalent to ~15% of U.S. LPG supply, which should tighten balances going forward U.S. Export Bottleneck Relieved â–ª 2019 saw the addition of ~400 MBPD of new export capacity â–ª 2020 is scheduled to add another 650 MBPD of new LPG export capacity â–ª This doesn’t include new ethane and ethylene export capacity additions in 2019 and 2020. 2017-2040 Change in Global Oil Product Demand by Scenario Source: IEA World Energy Outlook 2018 (NPS = New Policy Scenario, SDS = Sustainable Development Scenario) U.S. LPG Export Capacity (MMBL/D) Set to Increase 2.50 2.00 1.50 1.00 0.50 0.00 2017 2018 2019 2020 2021 Enterprise —Houston Targa—Galena Park Sunoco—Mariner South Phillips 66—Freeport Enlink—Riverside Buckeye—Corpus Christi DCP—Chesapeake Sunoco—Marcus Hook Petrogas—Ferndale Source: Operator Estimates

Global LPG Demand Forecast Absorbs Growing U.S. Exports Global LPG S&D Waterfall (MBL/D) 11,200 11,000 10,800 10,600 10,400 10,200 ~1.2 MMBPD 10,000 9,800 9,600 9,400 9,200 2018 Demand ResCom + Industry PDH Ethylene 2023 Demand Non-U.S. Supply Call on U.S. Supply +Autogas + Other â–ª U.S. LPG Export Capacity to expand by 1,050 MBL/D (78%) by end 2020. â–ª Global LPG demand grew ~4.5% 2013-18, and is forecast to grow ~3% 2018-23, driven by ~700 MBL/D of PDH and Ethylene plants under-construction or post-FID. â–ª ResComm (~51% of demand in 2018) is driven by continued adoption rates in China, India, Indonesia and others for those without access to electricity. â–ª Indian LPG import terminal expansions under-construction/planned of 350 MBL/D in 2020-2025 â–ª Relative economics support use of LPG over naphtha for international steam crackers. In an oversupply case, converting just 10% of the global naphtha ethylene cracking fleet would absorb a further 600 MBL/D of LPG. â–ª Call on U.S. Supply is 1,200 MBL/D 2018-23, versus consultant supply growth forecasts of ~750 MLB/D. Source: EIA, Energy Aspects, Genscape, IEA

Financial Detail

Well-Structured, Resilient Balance Sheet â–ª $4+ billion max conforming borrowing base ($3B elected borrowing base, $2.4B committed) â–ª Simple capital structure â–ª Near-term cash flow protected with hedges â–ª Ample cushion on financial covenants(a) â–ª Interest coverage ratio(b) of ~5.0x versus covenant of at least 2.5x â–ª Current ratio(c) of ~4.8x versus covenant of at least 1.0x â–ª Asset coverage test(d) of ~2.6x versus covenant of at least 1.5x Debt/Proved Developed Reserves $0.90 c f) / m $0.80 ( $ rves $0.70 s e e $0.60 R e d $0.50 l op v e $0.40 De e d $0.30 t/ Prov $0.20 e b D $0.10 Net $0.00 2013 2014 2015 2016 2017 2018 RRC Peer Average Note: Peer average includes AR, CHK, CNX, COG, EQT, GPOR and SWN. Capital Structure(a) (millions) 3Q19 Bank Debt $ 328 Senior Notes 2,784 Senior Sub Notes 49 Debt 3,161 Debt to Capitalization 43% Debt/TTM EBITDAX 3.2x Debt Maturity Schedule(a) $3,000 $3 Billion Borrowing Base Significant Liquidity $2,500 Potential of ~$2.4 billion $2.4 Billion Bank Commitment $2,000 i ons) Mill $1,500 n i $ $890 ( $1,000 $749 $750 $444 $328 $500 $- 2019 2020 2021 2022 2023 2023 2024 2025 Range Notes Senior Secured Revolving Credit Facility Interest Rate 5.75% 5.3%(e) 5.0% 4.875% (a) As of 9/30/19 (b) Excludes non-cash interest expense (c) Calculated as (Current assets excluding derivatives + unused revolver capacity) / (current liabilities excluding derivatives) (d) Defined as PV-9 of reserves divided by total debt (e) Weighted-average interest rate of 2022 notes

Natural Gas & NGL Hedging Status Volumes Hedged Average Hedge Prices Time Period (Mmbtu/day) ($/Mmbtu) 4Q19 Swaps 1,421,739 $2.82 1Q20 Swaps 1,007,253 $2.68 Natural Gas1 2Q20 Swaps 1,010,000 $2.62 (Henry Hub) 3Q20 Swaps 1,010,000 $2.62 4Q20 Swaps 976,848 $2.63 FY21 Swaps 50,000 $2.62 Volumes Hedged Average Hedge Prices Time Period (bbls/day) ($/gal) Propane (C3) 4Q19 Swaps 5,723 $0.54 Normal Butane (NC4) 4Q19 Swaps 4,804 $0.66 Normal Butane (NC4) 1Q20 Swaps 659 $0.73 Isobutane (iC4) 4Q19 Swaps 337 $0.78 Natural Gasoline (C5) 4Q19 Swaps 6,005 $1.29 Natural Gasoline (C5) 1Q20 Swaps 4,297 $1.21 *As of 12/31/19 1) Range also sold natural gas call swaptions of 140,000 Mmbtu/d for March-December 2020, and 100,000 Mmbtu/d for calendar 2021 at average strike prices of $2.53 and $2.69 per Mmbtu, respectively.

Oil Hedging Status Volumes Hedged Average Hedge Prices Time Period (bbl/day) ($/bbl) 4Q19 Collars 1,000 $63 x 73 4Q19 Swaps 9,168 $56.11 1Q20 Swaps 9,000 $58.62 Oil (WTI)1 2Q20 Swaps 9,000 $58.18 3Q20 Swaps 8,500 $58.15 4Q20 Swaps 5,500 $58.00 FY21 Swaps 1,000 $55.00 *As of 12/31/19 1) Range also sold WTI calls of 500 Bbls/d for 2Q-3Q 2020 at a strike price of $59 per Bbl and WTI call swaptions of 3,000 Bbls/d for calendar 2021 at an average strike price of $56.50 per Bbl.

Contact Information Range Resources Corporation 100 Throckmorton St., Suite 1200 Fort Worth, Texas 76102 Laith Sando, Vice President – Investor Relations (817) 869-4267 lsando@rangeresources.com Michael Freeman, Director – Investor Relations & Hedging (817) 869-4264 mfreeman@rangeresources.com John Durham, Senior Financial Analyst (817) 869-1538 jdurham@rangeresources.com www.rangeresources.com