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Range Resources Company Presentation - Oct 28, 2015

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Marcellus Drilling News
Marcellus Drilling News

An updated investor slide presentation loaded with details about Range's operations in the Marcellus/Utica, and details about drilling in the northeast in general.

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1 October 28, 2015 Company Presentation
2 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, such as those regarding future liquidity, future production growth, future completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position, future technical improvements, future marketing opportunities, future market improvements, maximizing future rates of return, strong inventory of uncompleted wells, expectation to create future value, expected lower well costs, acreage prospective for other horizons, expected future asset sales and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission ("SEC"), which are incorporated by reference. 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 the Company’s 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 and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion 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.
3 Range Resources Long-Term Focus • Per share growth of production and reserves each year on a debt- adjusted basis • Return-focused capital allocation process • Approximately 1.6 million acres of stacked pay potential • Majority of capital expected to be directed to the concentrated, stacked pay acreage position in SWPA with strong returns, low cost and repeatable projects • Portfolio allows redirection to dry, wet or super-rich • Reduce costs and improve capital efficiencies • Lowered per unit costs 47% since 2008 • One of the best EUR/1,000 ft. recoveries and cost/1,000 ft. in basin • Marketing innovation to improve margins and cash flow • Mariner East I project start-up imminent • Uniontown to Gas City pipeline project increased September gas price, after transportation, by more than $1.00 per mcf • New marketing arrangement for condensate production initiated in Q3 • Operate safely and be good stewards of the environment
4 4 Current Outlook for 2016 Capital Budget ~$270 million capital budget is estimated to maintain the 4Q15 production rate for 2016 equating to ~2% growth for the year ~ 10% Growth 0% 5% 10% 15% 20% ~ 20% Growth ~ $550 Million ~ $890 Million 2016 range of estimates %Y-O-YProductionGrowth 2016 Capital Budget is subject to Board approval
5 2016 Leverage and Liquidity Outlook • No debt covenant issues • EBITDAX to interest – minimum of 2.5x (latest 6.1x) • PV9 proved reserves value to debt – minimum of 1.5x (latest 2.8x) • Range has $1.9 billion liquidity under the $3 billion borrowing base • No note maturities until 2021 • Bank facility subject to renewal 2019 • Hedges lock in a significant portion of 2016 cash flow
6 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 Driving Down Unit Costs $/mcfe (1) Three-year average of drill bit F&D costs, excluding acreage 2008 2009 2010 2011 2012 2013 2014 2015E Reserve Replacement(1) $1.64 $1.25 $0.83 $0.68 $0.68 $0.66 $0.59 $0.56 LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41 $0.36 $0.35 $0.28 Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15 $0.13 $0.10 $0.07 G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46 $0.42 $0.35 $0.28 Interest $0.71 $0.74 $0.73 $0.69 $0.61 $0.51 $0.40 $0.33 Trans. & Gathering (2) $0.08 $0.32 $0.40 $0.62 $0.70 $0.75 $0.76 $0.76(3) Total $4.30 $3.84 $3.42 $3.29 $3.01 $2.84 $2.55 $2.28 $0.00 (2) Excludes non-cash stock compensation (3) Includes additional NGL & natural gas firm transport agreements & propane transport cost previously netted against NGL revenue. Incremental natural gas & NGL revenue will more than offset the 2015 increase in transport expense
7 Sustained Growth with Improving Capital Efficiency Growth achieved despite reducing capital, demonstrating improved efficiency * 2015 estimated production assuming announced target of 20% production growth and capital budget of $870 million $- $5 $10 $15 $20 $25 $30 0 250 500 750 1,000 1,250 1,500 2011 2012 2013 2014 2015E* $CapexperIncrementalmcfeProduction Production(Mmcfepd) Production (mmcfepd) $ Capex per Incremental mcfe Production$ Capex per incremental mcfe ProductionProduction (Mmcfepd)
8 Drilling Efficiencies/Competitive Advantages • Average lateral lengths expected to increase to 6,900 ft. in 2016 • Lateral lengths expected to continue to increase in the future, resulting in improved capital productivity each year • Managing costs, reducing drilling time and optimizing completions creates continued efficiencies • Capital efficiencies in core areas expected to be greater than non-core areas 3,123 3,975 4,915 6,000 6,900 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2012 2013 2014 2015 E 2016 E Feet SWPA Average Lateral Length
9 1,500 2,500 3,500 4,500 5,500 6,500 2011 2012 2013 2014 2015 Average Lateral Length $200 $400 $600 $800 $1,000 $1,200 2011 2012 2013 2014 2015 Drilling Cost/Lateral Length (includes vertical) $400 $600 $800 $1,000 $1,200 2011 2012 2013 2014 2015 Completion Cost/Lateral Length $700 $1,000 $1,300 $1,600 $1,900 $2,200 $2,500 2011 2012 2013 2014 2015 Well Cost/Lateral Length Cost & Efficiency Improvements – SW Pennsylvania
10 1,000 2,000 3,000 4,000 5,000 6,000 2011 2012 2013 2014 2015 Average Lateral Length $600 $900 $1,200 $1,500 $1,800 $2,100 $2,400 2011 2012 2013 2014 2015 Well Cost / Lateral Length $200 $400 $600 $800 $1,000 2011 2012 2013 2014 2015 Drilling Cost/Lateral Length (includes vertical) $300 $600 $900 $1,200 $1,500 2011 2012 2013 2014 2015 Completion Cost/Lateral Length Cost & Efficiency Improvements – NE Pennsylvania
11 SW Super-Rich SW Wet SW Dry NE Dry EUR 12.9 Bcfe 1,169 Mbbls & 5.9 Bcf 17.6 Bcfe 1,501 Mbbls & 8.6 Bcf 17.1 Bcf 15.2 Bcf EUR/1,000 ft. lateral 2.40 Bcfe 2.95 Bcfe 2.52 Bcf 2.67 Bcf EUR/stage 477 Mmcfe 586 Mmcfe 504 Mmcf 542 Mmcf Well Cost $5.9 MM $5.9 MM $6.0 MM $4.9 MM Cost/1,000 ft. lateral $1,099 K $991 K $883 K $865 K Stages 27 30 34 28 Lateral Length 5,367 ft. 5,955 ft. 6,798 ft. 5,663 ft. IRR – Strip (as of 6/30/2015) 26% 28% 60% 64% IRR – $4.00 33% 38% 101% 140% Range Marcellus – 2015 Well Economic Summary See appendix for complete assumptions and data on each area The different Marcellus areas provide optionality and a balanced approach to developing acreage and growing overall Marcellus production
12 Company Positions Total Reserves (tcfe) Breakeven (US$/mcf) Range 30.00 2.62 Rex 3.19 2.66 Cabot 18.18 2.71 EQT 15.84 2.74 Antero 23.87 2.88 Chesapeake 31.03 2.93 Statoil 21.46 2.98 Rice Energy 4.83 3.26 Seneca 4.69 3.33 Reliance 5.19 3.36 Enerplus 2.58 3.45 Mitsui 5.57 3.46 Anadarko 13.32 3.46 Chevron 17.89 3.47 Southwestern 9.83 3.55 Carrizo 0.17 3.60 EOG 1.05 3.65 Chief 9.88 3.67 Noble 17.80 3.68 CONSOL 16.44 3.73 WPX 2.00 3.90 MHR 2.93 3.99 Talisman 5.14 4.49 PDC 0.78 4.51 Ultra 0.84 4.65 Shell 2.89 4.72 ExxonMobil 6.08 4.94 BG 0.28 5.04 EXCO 0.28 5.04 Range: Low-Cost, Large Scale Range has both highest net risked resource and lowest breakeven price in the Marcellus per Wood Mackenzie Source = Wood Mackenzie Marcellus Shale only * * Portion sold to SWN
13 SW/NE Pennsylvania Stacked Pays Stacked pays allow for multiple development opportunities at 1,000 foot spacing between wells and later with 500 foot spacing. Upper Devonian 330,000 195,000 525,000 330,000 310,000 640,000 - 400,000 400,000 660,000 905,000 1,565,000 Marcellus Utica/Point Pleasant Wet Acreage Dry Acreage Total Net Acreage (1) (1) Excludes Northwest PA - 285,000 net acres, largely HBP
14 Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. When GIP analysis from the Marcellus, Upper Devonian and Point Pleasant are combined, the largest stacked pay resource is located in SW PA where Range has concentrated its acreage position
15 Utica/Point Pleasant Update • 1st well estimated to have 15 Bcf EUR, or 2.8 Bcf per 1,000 lateral foot • 2nd well completed with higher sand concentration and brought online in Q3 with choke management at 13 Mmcf per day • 2nd well EUR appears to be greater than the first well • 3rd well being drilled with completion expected in early 2016 • 400,000 net acres in SW PA prospective Note: Townships where Range holds ~3,000 or more acres are shown outlined above (As of 12/31/2014) OH PA WV
16 Two Near-Term Pricing Enhancements • Moves ~200 Mmcf per day of Range gas production as anchor shipper from local Appalachia M2 to Midwest markets effective September 1 • Added $5.7 million incremental revenue after transport cost in September, or $1.13 per mcf • Expecting $0.75 to $1.00 uplift for 4Q depending on M2 prices Spectra – Uniontown to Gas City Pipeline • Range has 20,000 barrels per day of ethane and 20,000 barrels per day of propane transportation to Marcus Hook • Access (80%) to 1 million barrels of propane cavern storage at Marcus Hook • Net increase in cash flow from Mariner East I, Mariner West and ATEX of ~$90 million per year, when all are fully operational • Expected fully operational late 4Q 2015 Mariner East I – Only Producer with Firm Capacity
17 Significant U.S. Natural Gas Demand Growth Projected * Exports include LNG and exports to MexicoSource: EIA, Bernstein estimates * Additional 20 Bcfd of demand by 2020, plus an additional 15 Bcfd by 2025
18 U.S. LNG Exports Expected to be ~8 Bcf/day by 2020 – per TPH Research report dated 10/8/2015
19 19 • Utica/Point Pleasant rig count down 55% from the peak in 2014 • Marcellus rig count down 66% from the peak in 2014 Appalachian Rig Counts Declining Source – RigData as of 10/12/2015 0 10 20 30 40 50 60 Utica / Point Pleasant Rig Count 20 40 60 80 100 120 140 Marcellus Rig Count
20 20 Year-to-Date Natural Gas Production is Slowing Source - ITG IR, Ventyx & Bloomberg 58 60 62 64 66 68 70 72 74 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 BCF/d Estimated Total L48 Gas Pipeline Flows 0 2 4 6 8 10 12 14 16 18 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 BCF/d Marcellus Pipeline Flows Lower 48 gas leveling out Marcellus production flat
21 21 20 25 30 35 40 45 50 Bcf/D-MajorU.S.GrowthRegions September EIA data for the 7 Major Growth Producing Regions – Marcellus, Eagle Ford, Permian, Haynesville, Niobrara, Utica & Bakken U.S. Natural Gas Production Growth is Slowing • 7 major regions account for 95% of domestic natural gas production growth • Significant reduction in Capital spending in the 7 regions would suggest continuation of this trend
22 22 3,000 3,500 4,000 4,500 5,000 5,500 6,000 September EIA data for the 7 Major Growth Producing Regions – Marcellus, Eagle Ford, Permian, Haynesville, Niobrara, Utica & Bakken Mbbls/D-MajorU.S.GrowthRegions • 7 major regions account for 95% of domestic oil production growth • Production appears to have peaked in 2nd Qtr. 2015 • Significant reduction in Capital spending in the 7 regions would suggest the trend will continue • Associated gas estimated to be 8 Bcf per day from growth in oil production. Declines in oil production expected to result in less associated gas. U.S. Domestic Oil Production Appears to Have Peaked
23 Range Resources – Quality, Efficiency, Strength at Low Cost 1. Largest acreage position in core of Marcellus, Upper Devonian and Utica 2. Marcellus development has driven down Company unit costs by 47%; capital costs down 57% or more on a per lateral foot basis 3. Continued efficiencies expected from longer laterals, technical improvements, stacked pay development and drilling in areas of existing infrastructure 4. Strong balance sheet and $1.9 billion of liquidity under the $3 billion borrowing base support 2016 growth of 10% - 20%
24 Portfolio Detail Appendix
25 Range is Focused on Per Share Growth, on a Debt-Adjusted Basis • Production/share = annual production divided by debt-adjusted year-end diluted shares outstanding • Reserves/share = year-end proven reserves divided by debt-adjusted year-end diluted shares outstanding Reserves/share – debt adjustedProduction/share – debt adjusted Mcfe/share Mcfe/share 2014 Increase of 27% 2014 Increase of 29% - 0.50 1.00 1.50 2.00 2.50 3.00 2010 2011 2012 2013 2014 - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 2010 2011 2012 2013 2014
26 SW PA Super-Rich Area Marcellus Projected 2015 Well Economics • Southwestern PA – (High Btu case) • EUR / 1,000 ft. – 2.40 Bcfe • EUR – 12.9 Bcfe (182 Mbbls condensate, 987 Mbbls NGLs, and 5.9 Bcf gas) • Drill and Complete Capital – $5.9 MM, ($1,099 K per 1,000 ft.) • Average Lateral Length – 5,367 ft. • F&D – $0.55/mcfe Strip pricing NPV10 = $5.2 MM NYMEX Gas Price 12.9 Bcfe Strip - 26% $3.00 - 26% $4.00 - 33% Estimated Cumulative Recoveries for 2015 TIL Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 39 533 90 2 Years 59 920 155 3 Years 74 1,253 211 5 Years 97 1,810 304 10 Years 129 2,836 477 20 Years 157 4,159 699 EUR 182 5,872 987 • Price includes current and expected differentials less gathering, transportation and processing costs • For flat pricing, oil price assumed to be $55/bbl for 2015, $65/bbl for 2016 then $75/bbl to life with no escalation • NGL price includes ethane contracts plus escalation in all cases • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf
27 0 500 1,000 1,500 2,000 2,500 3,000 0 50 100 150 200 250 300 350 400 NormalizedMcfe/Dayper1,000ft. Days Southwest PA - Super-Rich Area 2015 Turn in Line Forecast 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Improvements Between Years EUR (Bcfe) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 12.3 $6.8 5,300 2015 Type Curve - TIL 12.9 $5.9 5,367 System designed to maximize project economics
28 Southwest PA – Super-Rich Marcellus 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcfe)/1,000ft. EUR per 1,000 ft. 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 2013 2014 2015 EUR(Bcfe) EUR by Year Gas NGLs Condensate 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2013 Actual 2014 Actual 2015 Forecast Feet Horizontal Length (TIL) All comparisons based on Turned In Line (TIL) wells for each year
29 SW PA Wet Area Marcellus Projected 2015 Well Economics • Southwestern PA – (Wet Gas case) • EUR / 1,000 ft. – 2.95 Bcfe • EUR – 17.6 Bcfe (48 Mbbls condensate, 1,453 Mbbls NGLs, and 8.6 Bcf gas) • Drill and Complete Capital – $5.9 MM, ($991 K per 1,000 ft.) • Lateral Length – 5,955 ft. • F&D – $0.41/mcfe • Price includes current and expected differentials less gathering, transportation and processing costs • For flat pricing, oil price assumed to be $55/bbl for 2015, $65/bbl for 2016 then $75/bbl to life with no escalation • NGL price includes ethane contracts plus escalation in all cases • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf Strip pricing NPV10 = $6.4 MM NYMEX Gas Price 17.6 Bcfe Strip - 28% $3.00 - 26% $4.00 - 38% Estimated Cumulative Recoveries for 2015 TIL Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 17 1,035 174 2 Years 26 1,721 290 3 Years 31 2,277 383 5 Years 37 3,154 531 10 Years 43 4,666 786 20 Years 47 6,524 1,098 EUR 48 8,629 1,453
30 0 500 1,000 1,500 2,000 2,500 3,000 3,500 0 50 100 150 200 250 300 350 400 NormalizedMcfe/Dayper1,000ft. Days Southwest PA - Wet Area 2015 Turn in Line Forecast Improvements Between Years EUR (Bcfe) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 12.3 $6.1 4,200 2015 Type Curve - TIL 17.6 $5.9 5,955 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production
31 Southwest PA – Wet Marcellus 5 10 15 20 25 30 35 2013 2014 2015 Stages Average Number of Stages 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcfe) EUR by Year Gas NGLs Condensate 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 2013 2014 2015 Feet Horizontal Length (TIL) 1.0 1.5 2.0 2.5 3.0 3.5 2013 2014 2015 EUR(Bcfe)/1,000ft. EUR per 1,000 ft. Actual Actual Forecast All comparisons based on Turned In Line (TIL) wells for each year
32 • Southwestern PA – (Dry Gas case) • EUR / 1,000 ft. – 2.52 Bcf • EUR – 17.1 Bcf • Drill and Complete Capital $6.0 MM, ($883 K per 1,000 ft.) • Average Lateral Length – 6,798 ft. • F&D – $0.43/mcf Strip pricing NPV10 = $10.2 MM NYMEX Gas Price 17.1 Bcf Strip - 60% $3.00 - 46% $4.00 - 101% Estimated Cumulative Recoveries for 2015 TIL Forecast Residue (Mmcf) 1 Year 2,975 2 Years 4,567 3 Years 5,722 5 Years 7,407 10 Years 10,088 20 Years 13,205 EUR 17,132 • Price includes current and expected differentials less gathering and transportation costs • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf • Based on Washington County wells, which represent ~85% of expected SW PA dry activity in 2015 SW PA Dry Area Marcellus Projected 2015 Well Economics
33 0 1,000 2,000 3,000 4,000 5,000 6,000 0 50 100 150 200 250 300 350 400 NormalizedMcf/Dayper1,000ft. Days Improvements Between Years EUR (Bcf) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 13.4 $6.6 5,200 2015 Type Curve - TIL 17.1 $6.0 6,798 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Southwest PA – Dry Area 2015 Turn in Line Forecast Based on Washington County wells, which represent ~85% of expected wells TIL
34 2,000 3,000 4,000 5,000 6,000 7,000 8,000 2013 2014 2015 Feet Horizontal Length (TIL) Actual Actual Forecast 5 10 15 20 25 30 35 40 2013 2014 2015 Stages Average Number of Stages 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcf)/1,000ft. EUR per 1,000 ft. 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcf) EUR by Year Southwest PA – Dry Marcellus All comparisons based on Turned In Line (TIL) wells for each year
35 • Northeastern PA – (Dry Gas case) • EUR / 1,000 ft. – 2.67 Bcf • EUR – 15.2 Bcf • Drill and Complete Capital $4.9 MM, ($865 K per 1,000 ft.) • Average Lateral Length – 5,663 ft. • F&D – $0.38/mcf • Price includes current and expected differentials less gathering and transportation costs • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf • All 2015 TIL wells are located in Lycoming County Strip pricing NPV10 = $7.7 MM NYMEX Gas Price 15.2 Bcf Strip - 64% $3.00 - 42% $4.00 - 140% Estimated Cumulative Recoveries for 2015 TIL Forecast Residue (Mmcf) 1 Year 3,282 2 Years 4,735 3 Years 5,725 5 Years 7,123 10 Years 9,302 20 Years 11,823 EUR 15,172 NE PA Dry Area Marcellus Projected 2015 Well Economics
36 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 50 100 150 200 250 300 350 400 NormalizedMcf/Dayper1,000ft. Days Improvements Between Years EUR (Bcf) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 13.1 $4.7 4,800 2015 Type Curve - TIL 15.1 $4.9 5,663 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Northeast PA – Dry Area 2015 Turn in Line Forecast
37 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2013 2014 2015 Feet Horizontal Length (TIL) Actual Actual Forecast 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcf)/1,000ft. EUR per 1,000 ft. 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcf) EUR by Year Northeast PA – Dry Marcellus All comparisons based on Turned In Line (TIL) wells for each year
38 Results of Marcellus Tighter Spacing Pilot Projects 0 500 1,000 1,500 2,000 2,500 3,000 1 365 729 1093 1457 1821 2185 NormalizedMcfe/Dayper1,000ft. Projects conducted in the Wet and Super Rich areas of the Marcellus 500 ft Wells 1,000 ft Wells Year 1 Year 3Year 2 Year 4 Year 5 Year 6 • 500 foot spaced wells produced 79% of 1,000 foot spaced wells over a five-and-a-half-year period • Well performance not reflective of improved targeting & completion design • Normalized for lateral length
39 0 500 1000 1500 2000 2500 3000 3500 0 100 200 300 400 500 600 700 AverageMcfe/dayper1000ft. Days On Average Normalized Time Zero Decline Curves AVERAGE ORIGINAL TARGETING AVERAGE OPTIMIZED TARGETING Targeting/Down Spacing Test Results Encouraging • Optimized targeting shows a ~50% increase in cumulative production after 500 days • Normalized well costs were $850,000 less for optimized versus original • No detrimental production impact seen on the original wells Represents New Optimized Completion Method 900 ft. spacing 700 ft. spacing
40 Range’s Natural Gas Liquids Provide Revenue Uplift $3.19 $2.00 $1.70 - $1.80 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 Unprocessed Gas Processed Gas - Ethane Extraction Gas (1055 Btu) 24% shrink NGLs (C2+) Gas (1275 Btu) $/Wellhead Gas Assumptions: $3.00 NYMEX Gas, Local NG differential ($0.50), $55.00 WTI, 30% WTI (C3+), 5.50 GPM (ethane extraction), processing and shrink included, third-party NGL transport reported separately. Based on SWPA wet gas quality (1,275 processing plant inlet Btu). Based on full utilization of current ethane/propane agreements. NOTE: Wet Gas (Ethane Extraction) equals 1.54 mcfe. Projected – After Mariner East I fully operational • Range is one of the largest NGL producers in Appalachia, with the highest Btu inlet gas • Higher Btu gas receives increased uplift as it contains heavier NGLs • This revenue uplift is unique to Range’s contracts $3.70 - $3.80
41 45% 31% 4% 10% 10% Weighted Avg. Composite Barrel(1) Ethane C2 Propane C3 Iso Butane iC4 Normal Butane NC4 Natural Gasoline C5+ (1) Based on NGL volumes in 2Q 2015 (2) Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus Marcellus NGL Pricing Realized Marcellus NGL Prices 2014 2015 1Q 2Q 3Q 4Q 1Q 2Q 3Q NYMEX – WTI (per bbl) $98.61 $102.97 $96.99 $73.11 $48.62 $57.88 $46.61 Mont Belvieu Weighted Priced Equivalent $37.22 $33.43 $32.14 $24.38 $18.05 $18.32 $17.16 Plant Fees plus Diff. (8.02) (9.79) (10.53) (6.77) (7.16) (10.64) (11.20) Marcellus average price before NGL hedges $29.20 $23.64 $21.61 $17.61 $10.89 $7.71 $5.96 % of WTI (NGL Pre-hedge / Oil NYMEX) 30% 23% 22% 24% 22% 13% 13% (2)
42 Range NGLs Add Cash Flow • Range has a diverse portfolio of contracts with an expected substantial uplift in price realizations in 2016 • Mariner West – 15,000 bbls/day of ethane - Gas price index - no transportation cost • Mariner East I – 20,000 bbls/day propane - provides cost savings versus truck & rail when fully operational • 20,000 bbls/day ethane to Ineos - supplying crackers in Norway • Expected $90 million of added annualized cash flow • Benefits for Range upon Marcus Hook harbor facilities completion in late 2015 • Improved efficiencies from loading larger vessels • Access to 800,000 bbls of cavern storage for propane • Possible export of butane and other products • Range has the highest Btu gas and a large liquids resource base • Range has size and scale • Range has a competitive advantage in pricing as most large projects require/benefit from Range’s participation • Range’s unique contracts provide a value uplift
43 Freely Flowing Overbuilt 0 10 20 30 40 50 Bcf/d Appalcahia Consumption Regional Storage Injections Announced Takeaway Additions Appalachia Production 2013 2014 2015 2016 2017 2018 Appalachia Production Year End Exit Rate 13.7 17.9 20.9 23.0 26.5 27.6 Appalachia Consumption + Injections 13.4 14.6 14.2 14.6 15.0 15.2 A Appalachia Gas Surplus for Export 0.3 3.3 6.7 8.4 11.5 12.4 Takeaway Projects - Northeast (cumulative year-end) 0.6 1.1 1.8 3.4 3.0 Takeaway Projects - Southwest (cumulative year-end) 2.8 3.6 4.6 7.6 5 B Total Takeaway Projects (cumulative year-end) 3.4 8.1 14.5 25.5 33.5 Excess Takeaway (B – A) 0.1 1.4 6.1 14.0 21.1 Takeaway Largely Overbuilt by 2016-2017 Source: Analyst estimates • LNG exports starting in late 2015 • Appears to have sufficient takeaway capacity by 2016 ConstrainedAs of Year-End
44 Northeast PA Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2014 Northeast Connector Williams Transco NE Q4'14 0.1 Y Y Iroquois Access Dominion Iroquois NE Q4'14 0.3 Y Y Rose Lake Expansion Kinder Morgan TGP NE Q4'14 0.2 Y Y 2015 Niagara Expansion Kinder Morgan TGP Canada Q4'15 0.2 Y Y Northern Access 2015 NFG National Fuel Canada Q4'15 0.1 Y Y Leidy Southeast Williams Transco Mid-Atlantic/SE Q4'15 0.5 Y Y East Side Expansion Nisource Columbia Mid-Atlantic/SE Q4'15 0.3 Y Y 2016 Northern Access 2016 NFG National Fuel Canada 2016 0.4 Y Y SoNo Iroquois Access Dominion Iroquois Canada Q2'16 0.3 N N Constitution Williams Constitution NE H2'16 0.7 Y Y Algonquin AIM Spectra Algonquin NE Q4'16 0.4 Y Y 2017 Atlantic Sunrise Williams Transco Mid-Atlantic/SE H2'17 1.7 Y Y PennEast AGT NE H2'17 1.0 Y Y Atlantic Bridge Spectra Algonquin NE H2'17 0.7 N Y 2018 Access Northeast Spectra Algonquin NE H2'18 1.0 N N Diamond East Williams Transco NE H2'18 1.0 N N TGP Northeast Expansion Kinder Morgan TGP NE H2'18 1.0 Y Y Southwest Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2014 Lebanon Lateral Reversal Transcanada ANR Midwest Q1'14 0.4 Y Y Utica Backhaul Kinder Morgan TGP Midwest Q2'14 0.5 Y Y REX Seneca Lateral Tall Grass REX Midwest H1'14 0.6 Y Y TEAM 2014 Spectra TETCO Gulf Coast Q4'14 0.6 Y Y TEAM South Spectra TETCO Gulf Coast Q4'14 0.3 Y Y West Side Expansion Nisource Columbia Gulf Coast Q4'14 0.4 Y Y 2015 REX Zone 3 Full Reversal Tall Grass REX Midwest Q2'15 1.2 Y Y TGP Backhaul / Broad Run Kinder Morgan TGP Gulf Coast Q4'15 0.6 Y Y TETCO OPEN Spectra TETCO Gulf Coast Q4'15 0.6 Y Y Uniontown to Gas City Spectra TETCO Midwest Q3'15 0.4 Y Y Glen Karn 2015 Transcanada ANR Midwest Q4'15 0.8 N N Announced Appalachian Basin Takeaway Projects – 1 of 2 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating.
45 Southwest Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2016 Gulf Expansion Ph1 Spectra TETCO Gulf Coast Q4'16 0.3 Y Y Clarington West Expansion Tall Grass REX Midwest Q4'16 1.6 N N Zone 3 Capacity Enhancement Tall Grass REX Midwest Q4'16 0.8 N N Rover Ph1 ETP Midwest/Canada/ Gulf Coast Q4'16 1.9 Y Y 2017 Rayne/Leach Xpress Nisource Columbia Gulf Coast Q3'17 1.5 Y Y SW Louisiana Kinder Morgan TGP Gulf Coast Q3'17 0.9 Y N Rover Ph2 ETP Midwest/Canada/ Gulf Coast Q3'17 1.3 Y Y TGP Backhaul / Broad Run Expansion Kinder Morgan TGP Gulf Coast Q4'17 0.2 Y Y Adair SW Spectra TETCO Gulf Coast Q4'17 0.2 Y N Access South Spectra TETCO Gulf Coast Q4'17 0.3 Y N Gulf Expansion Ph2 Spectra TETCO Gulf Coast Q4'17 0.4 Y Y NEXUS Spectra Midwest/Canada Q4'17 1.5 Y Y ANR Utica Transcanada ANR Midwest/Canada Q4'17 0.6 N N Cove Point LNG Dominion NE Q4'17 0.7 Y Y 2018 Mountain Valley NextEra/EQT Mid-Atlantic/SE Q4'18 2.0 Y Y Western Marcellus Williams Transco Mid-Atlantic/SE Q4'18 1.5 N N Atlantic Coast Duke/Dominion Mid-Atlantic/SE Q4'18 1.5 Y Y Total NE Appalachia to Canada 1.0 Total NE Appalachia to NE 6.4 Total NE Appalachia to Mid-Atlantic/SE 2.5 Total NE Appalachia Additions 9.9 Total SW Appalachia to Mid-Atlantic/SE 5.0 Total SW Appalachia to Midwest/Canada 10.0 Total SW Appalachia to Gulf Coast 7.9 Total SW Appalachia to NE 0.7 Total SW Appalachia Additions 23.6 Overall Total Additions for Appalachian Basin 33.5 Announced Appalachian Basin Takeaway Projects – 2 of 2 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating.
46 Projected YE 2015 Projected YE 2016 Projected YE 2018 Regional Direction Mmbtu/day (Gross) Transport Cost per Mmbtu Mmbtu/day (Gross) Transport Cost per Mmbtu Mmbtu/day (Gross) Transport Cost per Mmbtu Firm Transportation Appalachia/Local 360,000 $ 0.22 360,000 $ 0.18 360,000 $ 0.18 Gulf Coast 270,000 $ 0.30 420,000 $ 0.41 945,000 $ 0.48 Midwest/Canada 285,000 $ 0.26 285,000 $ 0.26 585,000 $ 0.50 Northeast 210,000 $ 0.57 210,000 $ 0.57 210,000 $ 0.57 Southeast 100,000 $ 0.39 100,000 $ 0.39 100,000 $ 0.39 Firm Sales/Released Capacity 175,000 -- 270,000 -- 300,000 -- Total Takeaway Capacity 1,400,000 $ 0.28 1,645,000 $ 0.28 2,500,000 $ 0.39 Appalachia Gas Transportation Arrangements Capacity listed above reflects actual amounts of production that can flow under these arrangements. We believe these firm arrangements provide adequate capacity to meet our growth projections through 2018 Range net production would be approximately 83% of the gross amounts shown. Does not include current intermediary pipeline capacity of > 650,000 Mmbtu/day, and assumes full utilization. Cost associated with Firm Sales/Released Capacity is assumed as a deduction to price. Based on anticipated project start dates.
47 What Does the Future’s Strip Price Indicate for Regional Basis? TCO Pool 2015 -$0.12 2020 -$0.36 Dom South 2015 -$1.26 2020 -$0.76 TETCO M3 2015 -$0.43 2020 +$0.06 Chicago CG 2015 +$0.13 2020 -$0.15 CG Mainline 2015 -$0.07 2020 -$0.05 Dawn 2015 +$0.25 2020 -$0.11 MichCon 2015 +$0.15 2020 -$0.19 Algonquin 2015 +$2.34 2020 +$1.27 Transco Z6 (NY) 2015 +$1.13 2020 +$0.97 Transco Z4 2015 $0.00 2020 +$0.05 Source = Bloomberg, Inside-FERC Basis (10/20/15) Prices $/Mmbtu North East anticipated takeaway projects should improve future basis in the Appalachian Basin Transco Z6 (NNY) 2015 +$0.46 2020 +$0.33
48 PointLogic – Estimated Daily Production from Pipeline Flows -6 -4 -2 0 2 4 6 8 10 Oct-13 Dec-13 Feb-14 Apr-14 Jun-14 Aug-14 Oct-14 Dec-14 Feb-15 Apr-15 Jun-15 Aug-15 Gross Wellhead Production Estimates - Year-over-Year Change (Bcf/d) Northeast (From Pipeline Flows) Ex.Northeast (From Pipeline Flows) TOTAL L48 (From Pipeline Flows) Y-O-YGrowth–Bcf/d Source - PointLogic October, 2015
49 PointLogic - Northeast Daily Pipeline Flows – Year-over-Year -1 0 1 2 3 4 5 6 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Daily Local Production from Pipeline Flows – Year-over-Year Change (Bcf/d) Total L48 OH PA WV Source - PointLogic October, 2015 Y-O-YGrowth–Bcf/d
50 Gas In Place (GIP) – Marcellus Shale Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. • GIP is a function of pressure, temperature, thermal maturity, porosity, hydrocarbon saturation and net thickness • Two core areas have been developed in the Marcellus • Condensate and NGLs are in gaseous form in the reservoir
51 Gas In Place (GIP) – Point Pleasant Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. Outlined portion represents the area of the highest pressure gradients in the Point Pleasant
52 Gas In Place (GIP) – Upper Devonian Shale • The greatest GIP in the Upper Devonian is found in SW PA • A significant portion of the GIP in the Upper Devonian is located in the wet gas window Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates.
53 Southern Appalachia– Strategic Marketing Advantages • Nora is strategically positioned to provide gas to southeast markets • Contracts in place for ~100 Mmcf/d at $0.20/Mmbtu above NYMEX for the next 12 months • ~50 Mmcf/d of existing unused transport capacity to allow for planned production growth • Recent completion technology advances result in substantially higher returns for CBM and tight gas wells • Recent CBM results are 2.5x better than the historical field average, with moderate cost increases of only $15,000 per well • Deeper exploration potential upside 465,000 net acres - Range owns minerals on most of the acreage Mineral Rights
54 2014 Nora Enhanced Results From New Completion Design 2014 CBM • Pumping sand at higher pressures during completion operations has significantly increased production • Cost increase is only $15,000 per well, primarily to upgrade production pipe to withstand higher pressure • Early results indicate that production levels are 3 times historical field average • New completions designs for Nora tight gas, costing approximately $12,000 per well, have improved production results by over 40% over historical field results • 13 wells were brought online in 2014 2014 Tight Gas 0 20 40 60 80 100 120 140 160 180 1 26 51 76 101 126 151 176 201 226 251 276 301 326 351 MCFD Days CBM Weighted Average - last 7 years 2014 High Rate Frac (22 Wells) 2014 wells with new completion design 0 100 200 300 400 500 600 700 1 26 51 76 101 126 151 MCFD Days Tight Gas Weighted Average - last 7 years 2014 High Rate Frac (13 Wells) 2014 wells with new completion design
55 Financial and Reserve Detail Appendix
56 Disciplined Financial Approach Strong, Simple Balance Sheet • Bank debt, long-term bonds and common stock • No near-term maturities, first bond maturity in 2021. Bank credit facility matures in 2019 • Recent 4.875% senior notes offering met with strong investor demand, resulting in the lowest yield achieved by any non-investment grade issuer in 2015 • Liquidity of $1.9 billion under borrowing base Solid Hedge Position • Range hedges a significant portion of projected upcoming 12 months of production • 4Q15 Gas is approximately 85% hedged at an average floor of $3.70 • 4Q15 Oil is approximately 90% hedged at a floor of $98.92 • 4Q15 NGLs are over 60% hedged • For 2016, 630,000 Mmbtu per day gas hedged at average floor of $3.42, 4,247 barrels per day of oil at average floor of $65.27 and 27,000 barrels per day of NGL’s at favorable prices Debt Metrics • Debt trades near investment grade peers • Annual borrowing base unanimously approved • Debt Covenants with ample flexibility: • EBITDAX/Interest expense - minimum of 2.5x (latest ratio 6.1X) • PV9 proved reserves value to debt - minimum of 1.5x (latest ratio 2.8X) Well Structured Bank Credit Facility • 29 banks with no bank holding more than 6% of total • Commitment amount of $2.0 billion; current borrowing base of $3.0 billion
57 $- $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 2010 2011 2012 2013 2014 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 2010 2011 2012 2013 2014 A History of Strong Credit Metrics Debt / Production ($/boepd) EBITDAX / Interest Moody’s Investment Grade Range • Range has a long history of disciplined financial management • Strong EBITDAX coverage of interest expense evidences the low-cost structure and Range’s resiliency • While developing an unrivaled project inventory in terms of size and scale, Range has consistently grown production while prudently managing debt • Debt/Production is consistent with Moody’s Investment Grade rankings
58 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x 18.0x 2010 2011 2012 2013 2014 Long Life Reserves Enhances Credit Profile Proved Developed Reserves / Production Debt / Proved Developed ($/mcfe) The peer group is comprised of companies in the GICS Oil & Gas Exploration & Production sub-industry with a corporate family rating between Ba3 and Ba1 from Moody’s and between BB- and BB+ from S&P. BB / Ba Peer Avg for 2014 • With a best-in-class reserve life index, Range’s low production decline provides more stable cash flow and both low capital reinvestment and low reinvestment risk • Low production decline also allows Range to grow more efficiently • Proved developed reserves provide exceptional coverage of debt at levels consistent with high investment grade measures $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 $1.75 2010 2011 2012 2013 2014 Moody’s Investment Grade Range Range well above the average
59 Selected Rating Agency Commentary 59 Standard & Poor’s Oct. 26, 2015 Corporate Rating: BB+ / Stable Outlook “Range has one of the lowest cost profiles in its peer group, reflecting its prolific gas assets.” “The Company's financial risk profile benefits from a consistent hedging program that mitigates a portion of the volatility of commodity prices.” “We assess Range’s liquidity as ‘strong,’ as per our criteria.” Range’s credit ratings were recently reaffirmed by both rating agencies Moody’s Oct. 12, 2015 Corporate Rating: Ba1 / Stable Outlook “Range’s Ba1 Corporate Family Rating (CFR) reflects its leading position in the Marcellus Shale region, its investment grade size and scale, and its history of strong operational execution. The Company has a deep, low full-cycle cost, drilling inventory in the Marcellus, providing good visibility to continued production growth.”
60 $500 $600 $750 $750 0 100 200 300 400 500 600 700 800 900 $364 Senior Secured Revolving Credit Facility. Maximum facility size of $4 billion, with borrowing base of $3 billion and bank commitment of $2 billion. Debt Maturities Range maintains an orderly debt maturity ladder ($Millions) Senior Subordinated Notes Senior Notes Interest Rate 1.8% 5.75% 5.0% 5.0% 4.875%
61 Strong, Simple Balance Sheet YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 Q1 2015 Q2 2015 ($ in millions) Bank borrowings $274 $187 $739 $500 $723 $912 $364 Sr. Notes 750 Sr. Sub. Notes 1,686 1,788 2,139 2,641 2,350 2,350 2,350 Less: Cash (3) (0) (0) (0) (0) (0) (0) Net debt 1,957 1,975 2,878 3,141 3,073 3,262 3,464 Common equity 2,224 2,392 2,357 2,414 3,456 3,490 3,381 Total capitalization $4,181 $4,367 $5,235 $5,555 $6,529 $6,752 $6,845 Debt-to- capitalization(1) 47% 45% 55% 57% 47% 48% 50% Debt/EBITDAX(1) 2.8x 2.3x 3.2x 2.8x 2.6x 2.9x 3.3x Liquidity(2) $971 $1,284 $927 $1,166 $1,172 $980 $1,527 (1) Ratios are net of cash balances. (2) Liquidity based on current bank commitment amount, which excludes additional liquidity under total borrowing base. Q3 2015 $987 750 1,850 (0) 3,587 3,085 $6,672 54% 3.7x $876
62 Period Volumes Hedged (Mmbtu/day) Average Floor Price ( $ / Mmbtu) Average Cap Price ( $ / Mmbtu) Gas Hedging 4Q 2015 Swaps 727,500 $3.63 4Q 2015 Collars 145,000 $4.07 $4.56 2016 Swaps 2017 Swaps 630,000 20,000 $3.42 $3.49 Oil Hedging 4Q 2015 Swaps 8,750 $98.92 2016 Swaps 4,247 $65.27 Gas and Oil Hedging Status As of 10/23/2015 – For quarterly detail of hedges, see RRC website
63 Natural Gas Liquids Hedging Status (1) NGL hedges have Mont Belvieu as the underlying index. Conversion Factor: One barrel = 42 gallons Period Volumes Hedged (bbls/day) Hedged(1) Price ($/gal) Propane (C3) 4Q 2015 Swaps 2016 Swaps 12,000 5,500 $0.55 $0.60 Normal Butane (NC4) 4Q 2015 Swaps 2016 Swaps 3,500 2,500 $0.72 $0.72 Natural Gasoline (C5) 4Q 2015 Swaps 2016 Swaps 4,000 2,500 $1.16 $1.23 As of 10/23/2015 – For quarterly detail of hedges, see RRC website
64 Capital Efficiencies Driving Growth Capital Efficiencies Driving Growth with Less Capital Completed lateral lengths in Marcellus expected to average ~ 6,900 ft. in 2015 Improved targeting and completion techniques have increased recoveries significantly 95% of 2015 capital focused in Marcellus Budget by AreaBudget = $870 Million Drilling Acreage & Seismic Pipelines, Facilities & Others Marcellus Nora/Midcontinent 95%13% 83% 4% 5% 93%
65 Track Record of Building Reserves at Low Costs (1) Excludes Utica/Point Pleasant potential YE 2009 YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 Proved Reserves (Tcfe) 3.1 4.4 5.1 6.5 8.2 10.3 Drill Bit Finding Cost (per Mcfe) $0.69 $0.59 $0.76 $0.67 $0.57 $0.55 Net Unproved Resource Potential (Tcfe) 24 - 32 35 - 52 44 - 60 48 - 68 65 - 86 66 - 87 Proved reserves have increased by 27% per year on a compounded basis since 2009 (1) Moved 8.8 Tcfe of Resource Potential into Proved Reserves in the Last Five Years Track Record of Building Reserves at Low Costs
66 Contact Information Range Resources Corporation 100 Throckmorton, Suite 1200 Fort Worth, Texas 76102 Main: 817.870.2601 Fax: 817.870.2316 Rodney Waller, Senior Vice President rwaller@rangeresources.com David Amend, Investor Relations Manager damend@rangeresources.com Laith Sando, Research Manager lsando@rangeresources.com Michael Freeman, Senior Financial Analyst mfreeman@rangeresources.com www.rangeresources.com

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Range Resources Company Presentation - Oct 28, 2015

  • 2. 2 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, such as those regarding future liquidity, future production growth, future completion of ethane projects, estimated gas in place, future rates of return, future low costs, low reinvestment risk, future earnings and per-share value, future capital spending plans, increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, maximized realized natural gas prices, acreage quality, access to multiple gas markets, expected drilling and development plans, improved capital efficiency, future financial position, future technical improvements, future marketing opportunities, future market improvements, maximizing future rates of return, strong inventory of uncompleted wells, expectation to create future value, expected lower well costs, acreage prospective for other horizons, expected future asset sales and future guidance information are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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, including, but not limited to, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of actual drilling and operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drilling equipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes. Range undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in Range's filings with the Securities and Exchange Commission ("SEC"), which are incorporated by reference. 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 the Company’s 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 and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion 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.
  • 3. 3 Range Resources Long-Term Focus • Per share growth of production and reserves each year on a debt- adjusted basis • Return-focused capital allocation process • Approximately 1.6 million acres of stacked pay potential • Majority of capital expected to be directed to the concentrated, stacked pay acreage position in SWPA with strong returns, low cost and repeatable projects • Portfolio allows redirection to dry, wet or super-rich • Reduce costs and improve capital efficiencies • Lowered per unit costs 47% since 2008 • One of the best EUR/1,000 ft. recoveries and cost/1,000 ft. in basin • Marketing innovation to improve margins and cash flow • Mariner East I project start-up imminent • Uniontown to Gas City pipeline project increased September gas price, after transportation, by more than $1.00 per mcf • New marketing arrangement for condensate production initiated in Q3 • Operate safely and be good stewards of the environment
  • 4. 4 4 Current Outlook for 2016 Capital Budget ~$270 million capital budget is estimated to maintain the 4Q15 production rate for 2016 equating to ~2% growth for the year ~ 10% Growth 0% 5% 10% 15% 20% ~ 20% Growth ~ $550 Million ~ $890 Million 2016 range of estimates %Y-O-YProductionGrowth 2016 Capital Budget is subject to Board approval
  • 5. 5 2016 Leverage and Liquidity Outlook • No debt covenant issues • EBITDAX to interest – minimum of 2.5x (latest 6.1x) • PV9 proved reserves value to debt – minimum of 1.5x (latest 2.8x) • Range has $1.9 billion liquidity under the $3 billion borrowing base • No note maturities until 2021 • Bank facility subject to renewal 2019 • Hedges lock in a significant portion of 2016 cash flow
  • 6. 6 $- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 Driving Down Unit Costs $/mcfe (1) Three-year average of drill bit F&D costs, excluding acreage 2008 2009 2010 2011 2012 2013 2014 2015E Reserve Replacement(1) $1.64 $1.25 $0.83 $0.68 $0.68 $0.66 $0.59 $0.56 LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41 $0.36 $0.35 $0.28 Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15 $0.13 $0.10 $0.07 G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46 $0.42 $0.35 $0.28 Interest $0.71 $0.74 $0.73 $0.69 $0.61 $0.51 $0.40 $0.33 Trans. & Gathering (2) $0.08 $0.32 $0.40 $0.62 $0.70 $0.75 $0.76 $0.76(3) Total $4.30 $3.84 $3.42 $3.29 $3.01 $2.84 $2.55 $2.28 $0.00 (2) Excludes non-cash stock compensation (3) Includes additional NGL & natural gas firm transport agreements & propane transport cost previously netted against NGL revenue. Incremental natural gas & NGL revenue will more than offset the 2015 increase in transport expense
  • 7. 7 Sustained Growth with Improving Capital Efficiency Growth achieved despite reducing capital, demonstrating improved efficiency * 2015 estimated production assuming announced target of 20% production growth and capital budget of $870 million $- $5 $10 $15 $20 $25 $30 0 250 500 750 1,000 1,250 1,500 2011 2012 2013 2014 2015E* $CapexperIncrementalmcfeProduction Production(Mmcfepd) Production (mmcfepd) $ Capex per Incremental mcfe Production$ Capex per incremental mcfe ProductionProduction (Mmcfepd)
  • 8. 8 Drilling Efficiencies/Competitive Advantages • Average lateral lengths expected to increase to 6,900 ft. in 2016 • Lateral lengths expected to continue to increase in the future, resulting in improved capital productivity each year • Managing costs, reducing drilling time and optimizing completions creates continued efficiencies • Capital efficiencies in core areas expected to be greater than non-core areas 3,123 3,975 4,915 6,000 6,900 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2012 2013 2014 2015 E 2016 E Feet SWPA Average Lateral Length
  • 9. 9 1,500 2,500 3,500 4,500 5,500 6,500 2011 2012 2013 2014 2015 Average Lateral Length $200 $400 $600 $800 $1,000 $1,200 2011 2012 2013 2014 2015 Drilling Cost/Lateral Length (includes vertical) $400 $600 $800 $1,000 $1,200 2011 2012 2013 2014 2015 Completion Cost/Lateral Length $700 $1,000 $1,300 $1,600 $1,900 $2,200 $2,500 2011 2012 2013 2014 2015 Well Cost/Lateral Length Cost & Efficiency Improvements – SW Pennsylvania
  • 10. 10 1,000 2,000 3,000 4,000 5,000 6,000 2011 2012 2013 2014 2015 Average Lateral Length $600 $900 $1,200 $1,500 $1,800 $2,100 $2,400 2011 2012 2013 2014 2015 Well Cost / Lateral Length $200 $400 $600 $800 $1,000 2011 2012 2013 2014 2015 Drilling Cost/Lateral Length (includes vertical) $300 $600 $900 $1,200 $1,500 2011 2012 2013 2014 2015 Completion Cost/Lateral Length Cost & Efficiency Improvements – NE Pennsylvania
  • 11. 11 SW Super-Rich SW Wet SW Dry NE Dry EUR 12.9 Bcfe 1,169 Mbbls & 5.9 Bcf 17.6 Bcfe 1,501 Mbbls & 8.6 Bcf 17.1 Bcf 15.2 Bcf EUR/1,000 ft. lateral 2.40 Bcfe 2.95 Bcfe 2.52 Bcf 2.67 Bcf EUR/stage 477 Mmcfe 586 Mmcfe 504 Mmcf 542 Mmcf Well Cost $5.9 MM $5.9 MM $6.0 MM $4.9 MM Cost/1,000 ft. lateral $1,099 K $991 K $883 K $865 K Stages 27 30 34 28 Lateral Length 5,367 ft. 5,955 ft. 6,798 ft. 5,663 ft. IRR – Strip (as of 6/30/2015) 26% 28% 60% 64% IRR – $4.00 33% 38% 101% 140% Range Marcellus – 2015 Well Economic Summary See appendix for complete assumptions and data on each area The different Marcellus areas provide optionality and a balanced approach to developing acreage and growing overall Marcellus production
  • 12. 12 Company Positions Total Reserves (tcfe) Breakeven (US$/mcf) Range 30.00 2.62 Rex 3.19 2.66 Cabot 18.18 2.71 EQT 15.84 2.74 Antero 23.87 2.88 Chesapeake 31.03 2.93 Statoil 21.46 2.98 Rice Energy 4.83 3.26 Seneca 4.69 3.33 Reliance 5.19 3.36 Enerplus 2.58 3.45 Mitsui 5.57 3.46 Anadarko 13.32 3.46 Chevron 17.89 3.47 Southwestern 9.83 3.55 Carrizo 0.17 3.60 EOG 1.05 3.65 Chief 9.88 3.67 Noble 17.80 3.68 CONSOL 16.44 3.73 WPX 2.00 3.90 MHR 2.93 3.99 Talisman 5.14 4.49 PDC 0.78 4.51 Ultra 0.84 4.65 Shell 2.89 4.72 ExxonMobil 6.08 4.94 BG 0.28 5.04 EXCO 0.28 5.04 Range: Low-Cost, Large Scale Range has both highest net risked resource and lowest breakeven price in the Marcellus per Wood Mackenzie Source = Wood Mackenzie Marcellus Shale only * * Portion sold to SWN
  • 13. 13 SW/NE Pennsylvania Stacked Pays Stacked pays allow for multiple development opportunities at 1,000 foot spacing between wells and later with 500 foot spacing. Upper Devonian 330,000 195,000 525,000 330,000 310,000 640,000 - 400,000 400,000 660,000 905,000 1,565,000 Marcellus Utica/Point Pleasant Wet Acreage Dry Acreage Total Net Acreage (1) (1) Excludes Northwest PA - 285,000 net acres, largely HBP
  • 14. 14 Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. When GIP analysis from the Marcellus, Upper Devonian and Point Pleasant are combined, the largest stacked pay resource is located in SW PA where Range has concentrated its acreage position
  • 15. 15 Utica/Point Pleasant Update • 1st well estimated to have 15 Bcf EUR, or 2.8 Bcf per 1,000 lateral foot • 2nd well completed with higher sand concentration and brought online in Q3 with choke management at 13 Mmcf per day • 2nd well EUR appears to be greater than the first well • 3rd well being drilled with completion expected in early 2016 • 400,000 net acres in SW PA prospective Note: Townships where Range holds ~3,000 or more acres are shown outlined above (As of 12/31/2014) OH PA WV
  • 16. 16 Two Near-Term Pricing Enhancements • Moves ~200 Mmcf per day of Range gas production as anchor shipper from local Appalachia M2 to Midwest markets effective September 1 • Added $5.7 million incremental revenue after transport cost in September, or $1.13 per mcf • Expecting $0.75 to $1.00 uplift for 4Q depending on M2 prices Spectra – Uniontown to Gas City Pipeline • Range has 20,000 barrels per day of ethane and 20,000 barrels per day of propane transportation to Marcus Hook • Access (80%) to 1 million barrels of propane cavern storage at Marcus Hook • Net increase in cash flow from Mariner East I, Mariner West and ATEX of ~$90 million per year, when all are fully operational • Expected fully operational late 4Q 2015 Mariner East I – Only Producer with Firm Capacity
  • 17. 17 Significant U.S. Natural Gas Demand Growth Projected * Exports include LNG and exports to MexicoSource: EIA, Bernstein estimates * Additional 20 Bcfd of demand by 2020, plus an additional 15 Bcfd by 2025
  • 18. 18 U.S. LNG Exports Expected to be ~8 Bcf/day by 2020 – per TPH Research report dated 10/8/2015
  • 19. 19 19 • Utica/Point Pleasant rig count down 55% from the peak in 2014 • Marcellus rig count down 66% from the peak in 2014 Appalachian Rig Counts Declining Source – RigData as of 10/12/2015 0 10 20 30 40 50 60 Utica / Point Pleasant Rig Count 20 40 60 80 100 120 140 Marcellus Rig Count
  • 20. 20 20 Year-to-Date Natural Gas Production is Slowing Source - ITG IR, Ventyx & Bloomberg 58 60 62 64 66 68 70 72 74 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 BCF/d Estimated Total L48 Gas Pipeline Flows 0 2 4 6 8 10 12 14 16 18 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 BCF/d Marcellus Pipeline Flows Lower 48 gas leveling out Marcellus production flat
  • 21. 21 21 20 25 30 35 40 45 50 Bcf/D-MajorU.S.GrowthRegions September EIA data for the 7 Major Growth Producing Regions – Marcellus, Eagle Ford, Permian, Haynesville, Niobrara, Utica & Bakken U.S. Natural Gas Production Growth is Slowing • 7 major regions account for 95% of domestic natural gas production growth • Significant reduction in Capital spending in the 7 regions would suggest continuation of this trend
  • 22. 22 22 3,000 3,500 4,000 4,500 5,000 5,500 6,000 September EIA data for the 7 Major Growth Producing Regions – Marcellus, Eagle Ford, Permian, Haynesville, Niobrara, Utica & Bakken Mbbls/D-MajorU.S.GrowthRegions • 7 major regions account for 95% of domestic oil production growth • Production appears to have peaked in 2nd Qtr. 2015 • Significant reduction in Capital spending in the 7 regions would suggest the trend will continue • Associated gas estimated to be 8 Bcf per day from growth in oil production. Declines in oil production expected to result in less associated gas. U.S. Domestic Oil Production Appears to Have Peaked
  • 23. 23 Range Resources – Quality, Efficiency, Strength at Low Cost 1. Largest acreage position in core of Marcellus, Upper Devonian and Utica 2. Marcellus development has driven down Company unit costs by 47%; capital costs down 57% or more on a per lateral foot basis 3. Continued efficiencies expected from longer laterals, technical improvements, stacked pay development and drilling in areas of existing infrastructure 4. Strong balance sheet and $1.9 billion of liquidity under the $3 billion borrowing base support 2016 growth of 10% - 20%
  • 25. 25 Range is Focused on Per Share Growth, on a Debt-Adjusted Basis • Production/share = annual production divided by debt-adjusted year-end diluted shares outstanding • Reserves/share = year-end proven reserves divided by debt-adjusted year-end diluted shares outstanding Reserves/share – debt adjustedProduction/share – debt adjusted Mcfe/share Mcfe/share 2014 Increase of 27% 2014 Increase of 29% - 0.50 1.00 1.50 2.00 2.50 3.00 2010 2011 2012 2013 2014 - 10.00 20.00 30.00 40.00 50.00 60.00 70.00 2010 2011 2012 2013 2014
  • 26. 26 SW PA Super-Rich Area Marcellus Projected 2015 Well Economics • Southwestern PA – (High Btu case) • EUR / 1,000 ft. – 2.40 Bcfe • EUR – 12.9 Bcfe (182 Mbbls condensate, 987 Mbbls NGLs, and 5.9 Bcf gas) • Drill and Complete Capital – $5.9 MM, ($1,099 K per 1,000 ft.) • Average Lateral Length – 5,367 ft. • F&D – $0.55/mcfe Strip pricing NPV10 = $5.2 MM NYMEX Gas Price 12.9 Bcfe Strip - 26% $3.00 - 26% $4.00 - 33% Estimated Cumulative Recoveries for 2015 TIL Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 39 533 90 2 Years 59 920 155 3 Years 74 1,253 211 5 Years 97 1,810 304 10 Years 129 2,836 477 20 Years 157 4,159 699 EUR 182 5,872 987 • Price includes current and expected differentials less gathering, transportation and processing costs • For flat pricing, oil price assumed to be $55/bbl for 2015, $65/bbl for 2016 then $75/bbl to life with no escalation • NGL price includes ethane contracts plus escalation in all cases • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf
  • 27. 27 0 500 1,000 1,500 2,000 2,500 3,000 0 50 100 150 200 250 300 350 400 NormalizedMcfe/Dayper1,000ft. Days Southwest PA - Super-Rich Area 2015 Turn in Line Forecast 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Improvements Between Years EUR (Bcfe) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 12.3 $6.8 5,300 2015 Type Curve - TIL 12.9 $5.9 5,367 System designed to maximize project economics
  • 28. 28 Southwest PA – Super-Rich Marcellus 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcfe)/1,000ft. EUR per 1,000 ft. 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 2013 2014 2015 EUR(Bcfe) EUR by Year Gas NGLs Condensate 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2013 Actual 2014 Actual 2015 Forecast Feet Horizontal Length (TIL) All comparisons based on Turned In Line (TIL) wells for each year
  • 29. 29 SW PA Wet Area Marcellus Projected 2015 Well Economics • Southwestern PA – (Wet Gas case) • EUR / 1,000 ft. – 2.95 Bcfe • EUR – 17.6 Bcfe (48 Mbbls condensate, 1,453 Mbbls NGLs, and 8.6 Bcf gas) • Drill and Complete Capital – $5.9 MM, ($991 K per 1,000 ft.) • Lateral Length – 5,955 ft. • F&D – $0.41/mcfe • Price includes current and expected differentials less gathering, transportation and processing costs • For flat pricing, oil price assumed to be $55/bbl for 2015, $65/bbl for 2016 then $75/bbl to life with no escalation • NGL price includes ethane contracts plus escalation in all cases • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf Strip pricing NPV10 = $6.4 MM NYMEX Gas Price 17.6 Bcfe Strip - 28% $3.00 - 26% $4.00 - 38% Estimated Cumulative Recoveries for 2015 TIL Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 17 1,035 174 2 Years 26 1,721 290 3 Years 31 2,277 383 5 Years 37 3,154 531 10 Years 43 4,666 786 20 Years 47 6,524 1,098 EUR 48 8,629 1,453
  • 30. 30 0 500 1,000 1,500 2,000 2,500 3,000 3,500 0 50 100 150 200 250 300 350 400 NormalizedMcfe/Dayper1,000ft. Days Southwest PA - Wet Area 2015 Turn in Line Forecast Improvements Between Years EUR (Bcfe) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 12.3 $6.1 4,200 2015 Type Curve - TIL 17.6 $5.9 5,955 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production
  • 31. 31 Southwest PA – Wet Marcellus 5 10 15 20 25 30 35 2013 2014 2015 Stages Average Number of Stages 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcfe) EUR by Year Gas NGLs Condensate 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 6,500 2013 2014 2015 Feet Horizontal Length (TIL) 1.0 1.5 2.0 2.5 3.0 3.5 2013 2014 2015 EUR(Bcfe)/1,000ft. EUR per 1,000 ft. Actual Actual Forecast All comparisons based on Turned In Line (TIL) wells for each year
  • 32. 32 • Southwestern PA – (Dry Gas case) • EUR / 1,000 ft. – 2.52 Bcf • EUR – 17.1 Bcf • Drill and Complete Capital $6.0 MM, ($883 K per 1,000 ft.) • Average Lateral Length – 6,798 ft. • F&D – $0.43/mcf Strip pricing NPV10 = $10.2 MM NYMEX Gas Price 17.1 Bcf Strip - 60% $3.00 - 46% $4.00 - 101% Estimated Cumulative Recoveries for 2015 TIL Forecast Residue (Mmcf) 1 Year 2,975 2 Years 4,567 3 Years 5,722 5 Years 7,407 10 Years 10,088 20 Years 13,205 EUR 17,132 • Price includes current and expected differentials less gathering and transportation costs • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf • Based on Washington County wells, which represent ~85% of expected SW PA dry activity in 2015 SW PA Dry Area Marcellus Projected 2015 Well Economics
  • 33. 33 0 1,000 2,000 3,000 4,000 5,000 6,000 0 50 100 150 200 250 300 350 400 NormalizedMcf/Dayper1,000ft. Days Improvements Between Years EUR (Bcf) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 13.4 $6.6 5,200 2015 Type Curve - TIL 17.1 $6.0 6,798 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Southwest PA – Dry Area 2015 Turn in Line Forecast Based on Washington County wells, which represent ~85% of expected wells TIL
  • 34. 34 2,000 3,000 4,000 5,000 6,000 7,000 8,000 2013 2014 2015 Feet Horizontal Length (TIL) Actual Actual Forecast 5 10 15 20 25 30 35 40 2013 2014 2015 Stages Average Number of Stages 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcf)/1,000ft. EUR per 1,000 ft. 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcf) EUR by Year Southwest PA – Dry Marcellus All comparisons based on Turned In Line (TIL) wells for each year
  • 35. 35 • Northeastern PA – (Dry Gas case) • EUR / 1,000 ft. – 2.67 Bcf • EUR – 15.2 Bcf • Drill and Complete Capital $4.9 MM, ($865 K per 1,000 ft.) • Average Lateral Length – 5,663 ft. • F&D – $0.38/mcf • Price includes current and expected differentials less gathering and transportation costs • Strip dated 06/30/15 with 10-year average $65.87/bbl and $3.58/mcf • All 2015 TIL wells are located in Lycoming County Strip pricing NPV10 = $7.7 MM NYMEX Gas Price 15.2 Bcf Strip - 64% $3.00 - 42% $4.00 - 140% Estimated Cumulative Recoveries for 2015 TIL Forecast Residue (Mmcf) 1 Year 3,282 2 Years 4,735 3 Years 5,725 5 Years 7,123 10 Years 9,302 20 Years 11,823 EUR 15,172 NE PA Dry Area Marcellus Projected 2015 Well Economics
  • 36. 36 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 0 50 100 150 200 250 300 350 400 NormalizedMcf/Dayper1,000ft. Days Improvements Between Years EUR (Bcf) Well Costs ($ MM) Lateral Lengths (ft.) 2014 Type Curve - Drilling 13.1 $4.7 4,800 2015 Type Curve - TIL 15.1 $4.9 5,663 System designed to maximize project economics 2014 Actual Production2014-15 Unrestricted Type Curve 2015 Forecasted Production Northeast PA – Dry Area 2015 Turn in Line Forecast
  • 37. 37 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2013 2014 2015 Feet Horizontal Length (TIL) Actual Actual Forecast 5 10 15 20 25 30 2013 2014 2015 Stages Average Number of Stages 1.0 1.5 2.0 2.5 3.0 2013 2014 2015 EUR(Bcf)/1,000ft. EUR per 1,000 ft. 0.0 5.0 10.0 15.0 20.0 2013 2014 2015 EUR(Bcf) EUR by Year Northeast PA – Dry Marcellus All comparisons based on Turned In Line (TIL) wells for each year
  • 38. 38 Results of Marcellus Tighter Spacing Pilot Projects 0 500 1,000 1,500 2,000 2,500 3,000 1 365 729 1093 1457 1821 2185 NormalizedMcfe/Dayper1,000ft. Projects conducted in the Wet and Super Rich areas of the Marcellus 500 ft Wells 1,000 ft Wells Year 1 Year 3Year 2 Year 4 Year 5 Year 6 • 500 foot spaced wells produced 79% of 1,000 foot spaced wells over a five-and-a-half-year period • Well performance not reflective of improved targeting & completion design • Normalized for lateral length
  • 39. 39 0 500 1000 1500 2000 2500 3000 3500 0 100 200 300 400 500 600 700 AverageMcfe/dayper1000ft. Days On Average Normalized Time Zero Decline Curves AVERAGE ORIGINAL TARGETING AVERAGE OPTIMIZED TARGETING Targeting/Down Spacing Test Results Encouraging • Optimized targeting shows a ~50% increase in cumulative production after 500 days • Normalized well costs were $850,000 less for optimized versus original • No detrimental production impact seen on the original wells Represents New Optimized Completion Method 900 ft. spacing 700 ft. spacing
  • 40. 40 Range’s Natural Gas Liquids Provide Revenue Uplift $3.19 $2.00 $1.70 - $1.80 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 Unprocessed Gas Processed Gas - Ethane Extraction Gas (1055 Btu) 24% shrink NGLs (C2+) Gas (1275 Btu) $/Wellhead Gas Assumptions: $3.00 NYMEX Gas, Local NG differential ($0.50), $55.00 WTI, 30% WTI (C3+), 5.50 GPM (ethane extraction), processing and shrink included, third-party NGL transport reported separately. Based on SWPA wet gas quality (1,275 processing plant inlet Btu). Based on full utilization of current ethane/propane agreements. NOTE: Wet Gas (Ethane Extraction) equals 1.54 mcfe. Projected – After Mariner East I fully operational • Range is one of the largest NGL producers in Appalachia, with the highest Btu inlet gas • Higher Btu gas receives increased uplift as it contains heavier NGLs • This revenue uplift is unique to Range’s contracts $3.70 - $3.80
  • 41. 41 45% 31% 4% 10% 10% Weighted Avg. Composite Barrel(1) Ethane C2 Propane C3 Iso Butane iC4 Normal Butane NC4 Natural Gasoline C5+ (1) Based on NGL volumes in 2Q 2015 (2) Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus Marcellus NGL Pricing Realized Marcellus NGL Prices 2014 2015 1Q 2Q 3Q 4Q 1Q 2Q 3Q NYMEX – WTI (per bbl) $98.61 $102.97 $96.99 $73.11 $48.62 $57.88 $46.61 Mont Belvieu Weighted Priced Equivalent $37.22 $33.43 $32.14 $24.38 $18.05 $18.32 $17.16 Plant Fees plus Diff. (8.02) (9.79) (10.53) (6.77) (7.16) (10.64) (11.20) Marcellus average price before NGL hedges $29.20 $23.64 $21.61 $17.61 $10.89 $7.71 $5.96 % of WTI (NGL Pre-hedge / Oil NYMEX) 30% 23% 22% 24% 22% 13% 13% (2)
  • 42. 42 Range NGLs Add Cash Flow • Range has a diverse portfolio of contracts with an expected substantial uplift in price realizations in 2016 • Mariner West – 15,000 bbls/day of ethane - Gas price index - no transportation cost • Mariner East I – 20,000 bbls/day propane - provides cost savings versus truck & rail when fully operational • 20,000 bbls/day ethane to Ineos - supplying crackers in Norway • Expected $90 million of added annualized cash flow • Benefits for Range upon Marcus Hook harbor facilities completion in late 2015 • Improved efficiencies from loading larger vessels • Access to 800,000 bbls of cavern storage for propane • Possible export of butane and other products • Range has the highest Btu gas and a large liquids resource base • Range has size and scale • Range has a competitive advantage in pricing as most large projects require/benefit from Range’s participation • Range’s unique contracts provide a value uplift
  • 43. 43 Freely Flowing Overbuilt 0 10 20 30 40 50 Bcf/d Appalcahia Consumption Regional Storage Injections Announced Takeaway Additions Appalachia Production 2013 2014 2015 2016 2017 2018 Appalachia Production Year End Exit Rate 13.7 17.9 20.9 23.0 26.5 27.6 Appalachia Consumption + Injections 13.4 14.6 14.2 14.6 15.0 15.2 A Appalachia Gas Surplus for Export 0.3 3.3 6.7 8.4 11.5 12.4 Takeaway Projects - Northeast (cumulative year-end) 0.6 1.1 1.8 3.4 3.0 Takeaway Projects - Southwest (cumulative year-end) 2.8 3.6 4.6 7.6 5 B Total Takeaway Projects (cumulative year-end) 3.4 8.1 14.5 25.5 33.5 Excess Takeaway (B – A) 0.1 1.4 6.1 14.0 21.1 Takeaway Largely Overbuilt by 2016-2017 Source: Analyst estimates • LNG exports starting in late 2015 • Appears to have sufficient takeaway capacity by 2016 ConstrainedAs of Year-End
  • 44. 44 Northeast PA Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2014 Northeast Connector Williams Transco NE Q4'14 0.1 Y Y Iroquois Access Dominion Iroquois NE Q4'14 0.3 Y Y Rose Lake Expansion Kinder Morgan TGP NE Q4'14 0.2 Y Y 2015 Niagara Expansion Kinder Morgan TGP Canada Q4'15 0.2 Y Y Northern Access 2015 NFG National Fuel Canada Q4'15 0.1 Y Y Leidy Southeast Williams Transco Mid-Atlantic/SE Q4'15 0.5 Y Y East Side Expansion Nisource Columbia Mid-Atlantic/SE Q4'15 0.3 Y Y 2016 Northern Access 2016 NFG National Fuel Canada 2016 0.4 Y Y SoNo Iroquois Access Dominion Iroquois Canada Q2'16 0.3 N N Constitution Williams Constitution NE H2'16 0.7 Y Y Algonquin AIM Spectra Algonquin NE Q4'16 0.4 Y Y 2017 Atlantic Sunrise Williams Transco Mid-Atlantic/SE H2'17 1.7 Y Y PennEast AGT NE H2'17 1.0 Y Y Atlantic Bridge Spectra Algonquin NE H2'17 0.7 N Y 2018 Access Northeast Spectra Algonquin NE H2'18 1.0 N N Diamond East Williams Transco NE H2'18 1.0 N N TGP Northeast Expansion Kinder Morgan TGP NE H2'18 1.0 Y Y Southwest Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2014 Lebanon Lateral Reversal Transcanada ANR Midwest Q1'14 0.4 Y Y Utica Backhaul Kinder Morgan TGP Midwest Q2'14 0.5 Y Y REX Seneca Lateral Tall Grass REX Midwest H1'14 0.6 Y Y TEAM 2014 Spectra TETCO Gulf Coast Q4'14 0.6 Y Y TEAM South Spectra TETCO Gulf Coast Q4'14 0.3 Y Y West Side Expansion Nisource Columbia Gulf Coast Q4'14 0.4 Y Y 2015 REX Zone 3 Full Reversal Tall Grass REX Midwest Q2'15 1.2 Y Y TGP Backhaul / Broad Run Kinder Morgan TGP Gulf Coast Q4'15 0.6 Y Y TETCO OPEN Spectra TETCO Gulf Coast Q4'15 0.6 Y Y Uniontown to Gas City Spectra TETCO Midwest Q3'15 0.4 Y Y Glen Karn 2015 Transcanada ANR Midwest Q4'15 0.8 N N Announced Appalachian Basin Takeaway Projects – 1 of 2 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating.
  • 45. 45 Southwest Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2016 Gulf Expansion Ph1 Spectra TETCO Gulf Coast Q4'16 0.3 Y Y Clarington West Expansion Tall Grass REX Midwest Q4'16 1.6 N N Zone 3 Capacity Enhancement Tall Grass REX Midwest Q4'16 0.8 N N Rover Ph1 ETP Midwest/Canada/ Gulf Coast Q4'16 1.9 Y Y 2017 Rayne/Leach Xpress Nisource Columbia Gulf Coast Q3'17 1.5 Y Y SW Louisiana Kinder Morgan TGP Gulf Coast Q3'17 0.9 Y N Rover Ph2 ETP Midwest/Canada/ Gulf Coast Q3'17 1.3 Y Y TGP Backhaul / Broad Run Expansion Kinder Morgan TGP Gulf Coast Q4'17 0.2 Y Y Adair SW Spectra TETCO Gulf Coast Q4'17 0.2 Y N Access South Spectra TETCO Gulf Coast Q4'17 0.3 Y N Gulf Expansion Ph2 Spectra TETCO Gulf Coast Q4'17 0.4 Y Y NEXUS Spectra Midwest/Canada Q4'17 1.5 Y Y ANR Utica Transcanada ANR Midwest/Canada Q4'17 0.6 N N Cove Point LNG Dominion NE Q4'17 0.7 Y Y 2018 Mountain Valley NextEra/EQT Mid-Atlantic/SE Q4'18 2.0 Y Y Western Marcellus Williams Transco Mid-Atlantic/SE Q4'18 1.5 N N Atlantic Coast Duke/Dominion Mid-Atlantic/SE Q4'18 1.5 Y Y Total NE Appalachia to Canada 1.0 Total NE Appalachia to NE 6.4 Total NE Appalachia to Mid-Atlantic/SE 2.5 Total NE Appalachia Additions 9.9 Total SW Appalachia to Mid-Atlantic/SE 5.0 Total SW Appalachia to Midwest/Canada 10.0 Total SW Appalachia to Gulf Coast 7.9 Total SW Appalachia to NE 0.7 Total SW Appalachia Additions 23.6 Overall Total Additions for Appalachian Basin 33.5 Announced Appalachian Basin Takeaway Projects – 2 of 2 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating.
  • 46. 46 Projected YE 2015 Projected YE 2016 Projected YE 2018 Regional Direction Mmbtu/day (Gross) Transport Cost per Mmbtu Mmbtu/day (Gross) Transport Cost per Mmbtu Mmbtu/day (Gross) Transport Cost per Mmbtu Firm Transportation Appalachia/Local 360,000 $ 0.22 360,000 $ 0.18 360,000 $ 0.18 Gulf Coast 270,000 $ 0.30 420,000 $ 0.41 945,000 $ 0.48 Midwest/Canada 285,000 $ 0.26 285,000 $ 0.26 585,000 $ 0.50 Northeast 210,000 $ 0.57 210,000 $ 0.57 210,000 $ 0.57 Southeast 100,000 $ 0.39 100,000 $ 0.39 100,000 $ 0.39 Firm Sales/Released Capacity 175,000 -- 270,000 -- 300,000 -- Total Takeaway Capacity 1,400,000 $ 0.28 1,645,000 $ 0.28 2,500,000 $ 0.39 Appalachia Gas Transportation Arrangements Capacity listed above reflects actual amounts of production that can flow under these arrangements. We believe these firm arrangements provide adequate capacity to meet our growth projections through 2018 Range net production would be approximately 83% of the gross amounts shown. Does not include current intermediary pipeline capacity of > 650,000 Mmbtu/day, and assumes full utilization. Cost associated with Firm Sales/Released Capacity is assumed as a deduction to price. Based on anticipated project start dates.
  • 47. 47 What Does the Future’s Strip Price Indicate for Regional Basis? TCO Pool 2015 -$0.12 2020 -$0.36 Dom South 2015 -$1.26 2020 -$0.76 TETCO M3 2015 -$0.43 2020 +$0.06 Chicago CG 2015 +$0.13 2020 -$0.15 CG Mainline 2015 -$0.07 2020 -$0.05 Dawn 2015 +$0.25 2020 -$0.11 MichCon 2015 +$0.15 2020 -$0.19 Algonquin 2015 +$2.34 2020 +$1.27 Transco Z6 (NY) 2015 +$1.13 2020 +$0.97 Transco Z4 2015 $0.00 2020 +$0.05 Source = Bloomberg, Inside-FERC Basis (10/20/15) Prices $/Mmbtu North East anticipated takeaway projects should improve future basis in the Appalachian Basin Transco Z6 (NNY) 2015 +$0.46 2020 +$0.33
  • 48. 48 PointLogic – Estimated Daily Production from Pipeline Flows -6 -4 -2 0 2 4 6 8 10 Oct-13 Dec-13 Feb-14 Apr-14 Jun-14 Aug-14 Oct-14 Dec-14 Feb-15 Apr-15 Jun-15 Aug-15 Gross Wellhead Production Estimates - Year-over-Year Change (Bcf/d) Northeast (From Pipeline Flows) Ex.Northeast (From Pipeline Flows) TOTAL L48 (From Pipeline Flows) Y-O-YGrowth–Bcf/d Source - PointLogic October, 2015
  • 49. 49 PointLogic - Northeast Daily Pipeline Flows – Year-over-Year -1 0 1 2 3 4 5 6 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Daily Local Production from Pipeline Flows – Year-over-Year Change (Bcf/d) Total L48 OH PA WV Source - PointLogic October, 2015 Y-O-YGrowth–Bcf/d
  • 50. 50 Gas In Place (GIP) – Marcellus Shale Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. • GIP is a function of pressure, temperature, thermal maturity, porosity, hydrocarbon saturation and net thickness • Two core areas have been developed in the Marcellus • Condensate and NGLs are in gaseous form in the reservoir
  • 51. 51 Gas In Place (GIP) – Point Pleasant Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates. Outlined portion represents the area of the highest pressure gradients in the Point Pleasant
  • 52. 52 Gas In Place (GIP) – Upper Devonian Shale • The greatest GIP in the Upper Devonian is found in SW PA • A significant portion of the GIP in the Upper Devonian is located in the wet gas window Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2014), and estimated as prospective, are outlined green. GIP – Range estimates.
  • 53. 53 Southern Appalachia– Strategic Marketing Advantages • Nora is strategically positioned to provide gas to southeast markets • Contracts in place for ~100 Mmcf/d at $0.20/Mmbtu above NYMEX for the next 12 months • ~50 Mmcf/d of existing unused transport capacity to allow for planned production growth • Recent completion technology advances result in substantially higher returns for CBM and tight gas wells • Recent CBM results are 2.5x better than the historical field average, with moderate cost increases of only $15,000 per well • Deeper exploration potential upside 465,000 net acres - Range owns minerals on most of the acreage Mineral Rights
  • 54. 54 2014 Nora Enhanced Results From New Completion Design 2014 CBM • Pumping sand at higher pressures during completion operations has significantly increased production • Cost increase is only $15,000 per well, primarily to upgrade production pipe to withstand higher pressure • Early results indicate that production levels are 3 times historical field average • New completions designs for Nora tight gas, costing approximately $12,000 per well, have improved production results by over 40% over historical field results • 13 wells were brought online in 2014 2014 Tight Gas 0 20 40 60 80 100 120 140 160 180 1 26 51 76 101 126 151 176 201 226 251 276 301 326 351 MCFD Days CBM Weighted Average - last 7 years 2014 High Rate Frac (22 Wells) 2014 wells with new completion design 0 100 200 300 400 500 600 700 1 26 51 76 101 126 151 MCFD Days Tight Gas Weighted Average - last 7 years 2014 High Rate Frac (13 Wells) 2014 wells with new completion design
  • 56. 56 Disciplined Financial Approach Strong, Simple Balance Sheet • Bank debt, long-term bonds and common stock • No near-term maturities, first bond maturity in 2021. Bank credit facility matures in 2019 • Recent 4.875% senior notes offering met with strong investor demand, resulting in the lowest yield achieved by any non-investment grade issuer in 2015 • Liquidity of $1.9 billion under borrowing base Solid Hedge Position • Range hedges a significant portion of projected upcoming 12 months of production • 4Q15 Gas is approximately 85% hedged at an average floor of $3.70 • 4Q15 Oil is approximately 90% hedged at a floor of $98.92 • 4Q15 NGLs are over 60% hedged • For 2016, 630,000 Mmbtu per day gas hedged at average floor of $3.42, 4,247 barrels per day of oil at average floor of $65.27 and 27,000 barrels per day of NGL’s at favorable prices Debt Metrics • Debt trades near investment grade peers • Annual borrowing base unanimously approved • Debt Covenants with ample flexibility: • EBITDAX/Interest expense - minimum of 2.5x (latest ratio 6.1X) • PV9 proved reserves value to debt - minimum of 1.5x (latest ratio 2.8X) Well Structured Bank Credit Facility • 29 banks with no bank holding more than 6% of total • Commitment amount of $2.0 billion; current borrowing base of $3.0 billion
  • 57. 57 $- $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 2010 2011 2012 2013 2014 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 2010 2011 2012 2013 2014 A History of Strong Credit Metrics Debt / Production ($/boepd) EBITDAX / Interest Moody’s Investment Grade Range • Range has a long history of disciplined financial management • Strong EBITDAX coverage of interest expense evidences the low-cost structure and Range’s resiliency • While developing an unrivaled project inventory in terms of size and scale, Range has consistently grown production while prudently managing debt • Debt/Production is consistent with Moody’s Investment Grade rankings
  • 58. 58 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 14.0x 16.0x 18.0x 2010 2011 2012 2013 2014 Long Life Reserves Enhances Credit Profile Proved Developed Reserves / Production Debt / Proved Developed ($/mcfe) The peer group is comprised of companies in the GICS Oil & Gas Exploration & Production sub-industry with a corporate family rating between Ba3 and Ba1 from Moody’s and between BB- and BB+ from S&P. BB / Ba Peer Avg for 2014 • With a best-in-class reserve life index, Range’s low production decline provides more stable cash flow and both low capital reinvestment and low reinvestment risk • Low production decline also allows Range to grow more efficiently • Proved developed reserves provide exceptional coverage of debt at levels consistent with high investment grade measures $- $0.25 $0.50 $0.75 $1.00 $1.25 $1.50 $1.75 2010 2011 2012 2013 2014 Moody’s Investment Grade Range Range well above the average
  • 59. 59 Selected Rating Agency Commentary 59 Standard & Poor’s Oct. 26, 2015 Corporate Rating: BB+ / Stable Outlook “Range has one of the lowest cost profiles in its peer group, reflecting its prolific gas assets.” “The Company's financial risk profile benefits from a consistent hedging program that mitigates a portion of the volatility of commodity prices.” “We assess Range’s liquidity as ‘strong,’ as per our criteria.” Range’s credit ratings were recently reaffirmed by both rating agencies Moody’s Oct. 12, 2015 Corporate Rating: Ba1 / Stable Outlook “Range’s Ba1 Corporate Family Rating (CFR) reflects its leading position in the Marcellus Shale region, its investment grade size and scale, and its history of strong operational execution. The Company has a deep, low full-cycle cost, drilling inventory in the Marcellus, providing good visibility to continued production growth.”
  • 60. 60 $500 $600 $750 $750 0 100 200 300 400 500 600 700 800 900 $364 Senior Secured Revolving Credit Facility. Maximum facility size of $4 billion, with borrowing base of $3 billion and bank commitment of $2 billion. Debt Maturities Range maintains an orderly debt maturity ladder ($Millions) Senior Subordinated Notes Senior Notes Interest Rate 1.8% 5.75% 5.0% 5.0% 4.875%
  • 61. 61 Strong, Simple Balance Sheet YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 Q1 2015 Q2 2015 ($ in millions) Bank borrowings $274 $187 $739 $500 $723 $912 $364 Sr. Notes 750 Sr. Sub. Notes 1,686 1,788 2,139 2,641 2,350 2,350 2,350 Less: Cash (3) (0) (0) (0) (0) (0) (0) Net debt 1,957 1,975 2,878 3,141 3,073 3,262 3,464 Common equity 2,224 2,392 2,357 2,414 3,456 3,490 3,381 Total capitalization $4,181 $4,367 $5,235 $5,555 $6,529 $6,752 $6,845 Debt-to- capitalization(1) 47% 45% 55% 57% 47% 48% 50% Debt/EBITDAX(1) 2.8x 2.3x 3.2x 2.8x 2.6x 2.9x 3.3x Liquidity(2) $971 $1,284 $927 $1,166 $1,172 $980 $1,527 (1) Ratios are net of cash balances. (2) Liquidity based on current bank commitment amount, which excludes additional liquidity under total borrowing base. Q3 2015 $987 750 1,850 (0) 3,587 3,085 $6,672 54% 3.7x $876
  • 62. 62 Period Volumes Hedged (Mmbtu/day) Average Floor Price ( $ / Mmbtu) Average Cap Price ( $ / Mmbtu) Gas Hedging 4Q 2015 Swaps 727,500 $3.63 4Q 2015 Collars 145,000 $4.07 $4.56 2016 Swaps 2017 Swaps 630,000 20,000 $3.42 $3.49 Oil Hedging 4Q 2015 Swaps 8,750 $98.92 2016 Swaps 4,247 $65.27 Gas and Oil Hedging Status As of 10/23/2015 – For quarterly detail of hedges, see RRC website
  • 63. 63 Natural Gas Liquids Hedging Status (1) NGL hedges have Mont Belvieu as the underlying index. Conversion Factor: One barrel = 42 gallons Period Volumes Hedged (bbls/day) Hedged(1) Price ($/gal) Propane (C3) 4Q 2015 Swaps 2016 Swaps 12,000 5,500 $0.55 $0.60 Normal Butane (NC4) 4Q 2015 Swaps 2016 Swaps 3,500 2,500 $0.72 $0.72 Natural Gasoline (C5) 4Q 2015 Swaps 2016 Swaps 4,000 2,500 $1.16 $1.23 As of 10/23/2015 – For quarterly detail of hedges, see RRC website
  • 64. 64 Capital Efficiencies Driving Growth Capital Efficiencies Driving Growth with Less Capital Completed lateral lengths in Marcellus expected to average ~ 6,900 ft. in 2015 Improved targeting and completion techniques have increased recoveries significantly 95% of 2015 capital focused in Marcellus Budget by AreaBudget = $870 Million Drilling Acreage & Seismic Pipelines, Facilities & Others Marcellus Nora/Midcontinent 95%13% 83% 4% 5% 93%
  • 65. 65 Track Record of Building Reserves at Low Costs (1) Excludes Utica/Point Pleasant potential YE 2009 YE 2010 YE 2011 YE 2012 YE 2013 YE 2014 Proved Reserves (Tcfe) 3.1 4.4 5.1 6.5 8.2 10.3 Drill Bit Finding Cost (per Mcfe) $0.69 $0.59 $0.76 $0.67 $0.57 $0.55 Net Unproved Resource Potential (Tcfe) 24 - 32 35 - 52 44 - 60 48 - 68 65 - 86 66 - 87 Proved reserves have increased by 27% per year on a compounded basis since 2009 (1) Moved 8.8 Tcfe of Resource Potential into Proved Reserves in the Last Five Years Track Record of Building Reserves at Low Costs
  • 66. 66 Contact Information Range Resources Corporation 100 Throckmorton, Suite 1200 Fort Worth, Texas 76102 Main: 817.870.2601 Fax: 817.870.2316 Rodney Waller, Senior Vice President rwaller@rangeresources.com David Amend, Investor Relations Manager damend@rangeresources.com Laith Sando, Research Manager lsando@rangeresources.com Michael Freeman, Senior Financial Analyst mfreeman@rangeresources.com www.rangeresources.com