Range Resources Corporation · NYSE:RRC
Range Resources — Investor Presentation (October 2018)
43 slides from Range Resources's investor presentation, Oct 23, 2018
Slide 1: Company Presentation October 23, 2018
Company Presentation October 23, 2018
Slide 2: Forward Looking Statements
Forward Looking Statements This presentation contains certain “forward-looking statements” within the meaning of the federal securities laws, including the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s cur
Slide 3: Range Overview
Range Overview Market Snapshot NYSE Symbol: RRC Market Cap (a): $4.3B Net Debt (b): $4.2B Enterprise Value: $8.5B SEC Proved Reserve Value PV10 $8.1B Highlights Five-Year Outlook(d) 2018 Capital Program of $941 million ▪ ~$1 billion in cumulative free cash flow ▪ Targeting ~11% corporate growth with
Slide 4: Strategic Focus
Strategic Focus Returns-Focused Growth on a Per Share Debt-Adjusted Basis ▪ Growth within cash flow driven by high-return assets ▪ Consistent emphasis on debt-adjusted per share metrics in management incentives Improving Corporate Returns ▪ Corporate returns expected to improve through expanding mar
Slide 5: Five-Year Outlook Summary
Five-Year Outlook Summary Free Cash Flow Debt Reduction Growth <2.0x debt to ~13% debt ~$1 billion EBITDAX adjusted per share production CAGR FCF Yield(a) Recycle Ratio ~31% ~3.8x Underpinned by Large, De-risked, High Quality Marcellus Inventory Note: Five-year outlook assumes strip pricing as of 12
Slide 6: Large Core Marcellus Inventory
Large Core Marcellus Inventory Large contiguous acreage position allows for Range acreage long-lateral development outlined in green ~3,800 undrilled Core Marcellus wells (a) ~300 wells with 40+ Bcfe EUR ~400 wells with 30-40 Bcfe EUR ~1,400 wells with 20-30 Bcfe EUR ~1,400 wells with 15-20 Bcfe EUR
Slide 7: Low Maintenance Capital Drives Efficiencies
Low Maintenance Capital Drives Efficiencies • Significant improvement in Maintenance Capital post-2018 $1,600 ▪ Longer laterals lower base decline $1,400 ▪ Corporate base decline improves to Total Capital Spending ($s in millions)(a) <20% in 2019 $1,200 ▪ 2019 Maintenance Capital expected to $1,000
Slide 8: Two Years Ahead of Schedule on Leverage Target
Two Years Ahead of Schedule on Leverage Target Asset Sales and NGL Pricing Strength Have Accelerated Leverage Reduction. Range Now Expects <3.0x Net Debt to EBITDAX at YE18. Five-Year Outlook Current Expectation Announced January 2018 Leverage Under 3.0x Leverage Under 3.0x by 2020 by YE18 As Levera
Slide 9: Production Growth Within Cash Flow
Production Growth Within Cash Flow 4,000 3,500 3,000 2,500 Mmcfepd 2,000 1,500 1,000 500 0 2017A 2018E 2019E 2020E 2021E 2022E North Louisiana Marcellus Growing production at ~11% and spending within cash flow at strip pricing provides a steady path to improved leverage, while simultaneously driving
Slide 10: Differential Improvements Driving Margin Expansion
Differential Improvements Driving Margin Expansion Natural Gas Differential (a) NGL as a % of WTI (b) Condensate Differential $- 38% $- $(0.08) $(0.10) 37%- $(5.00)- 34% 38% $(3.00) $(4.77) $(6.00) $(0.20) 33% $(0.32) 30% $(6.00) $(0.30) $(9.13) $(0.45) 26% $(9.00) $(0.40) 26% $(0.52) $(12.00) $(0.5
Slide 11: Appalachian In-Basin Fractionation Advantage
Appalachian In-Basin Fractionation Advantage Appalachia ▪ Available fractionation capacity ▪ Control over purity product sales: domestic and international ▪ Producer access to international export pricing Mont Belvieu / Conway ▪ Limited fractionation capacity ▪ Access to exports limited to midstream
Slide 12: Improving Cost Structure Drives Cash Flow & Margin Growth
Improving Cost Structure Drives Cash Flow & Margin Growth $2.50 Cash Costs per mcfe $2.00 $1.50 $1.00 TGC&P improves by ~$0.25 per mcfe $0.50 over the 5-year outlook $- 2018E 2022 G&T Interest G&A LOE Production Taxes Largest improvement to cash unit costs is expected in gathering & transportation e
Slide 13: Free Cash Flow Profile
Free Cash Flow Profile $1,800 $1,600 $1,600 $1,400 Cumulative FCF ($s in millions) $1,400 Total Capital Spending and $1,200 $1,200 $1,000 in Millions $ in$ millions $1,000 $800 $800 $600 $600 $400 $400 $200 $200 $- 2018E 2019E 2020E 2021E 2022E Cumulative Free Cash Flow (Strip) Maintenance Capital G
Slide 14: Current Enterprise Value a Discount to YE17 PV-10
Current Enterprise Value a Discount to YE17 PV-10 YE17 PV-10 at $9.5 billion Strip Pricing(a) YE17 PV10 > Enterprise Value. Assumes no value for ~58 Tcfe of Marcellus resource potential(c). Enterprise $8.5 billion Value(b) YE17 Proved 15.3 Tcfe Reserves Trading at ~$0.56 per Proved Mcfe which exclud
Slide 15: Beyond the 5-Year Outlook
Beyond the 5-Year Outlook Production 3.5 Bcfe per day Snapshot Annual CF @ Strip $1.95 billion December Maintenance Capital ~$600 million 2022E Remaining Core Marcellus Inventory 3,200 Wells YE2022 Debt to EBITDAX <2.0x Range can hold 3.5 Bcfe per day flat for approximately $600 million per year of
Slide 16: Appendix
Appendix
Slide 17: Five-Year Outlook Assumptions and Definitions
Five-Year Outlook Assumptions and Definitions Assumptions: ▪ Production growth is driven by de-risked Marcellus inventory. ▪ North Louisiana production held relatively flat from YE18 through remainder of outlook. ▪ Strip pricing as of 12/29/2017: ▪ Henry Hub - $2.83 (2018), $2.84 (2019-2022 average)
Slide 18: Revenue Recognition Accounting Standard Adopted in 2018
Revenue Recognition Accounting Standard Adopted in 2018 Range adopted the new revenue recognition accounting standards in 1Q18 which changes our financial statement presentation related to revenue from certain gas processing contracts. As shown below, this is solely an accounting change and has no e
Slide 19: Appalachia Assets – Stacked Pay
Appalachia Assets – Stacked Pay ▪ ~1.5 million net effective acres (a) in SW PA leads to decades of drilling inventory ▪ Gas In Place (GIP) analysis shows the greatest potential is in Southwest Pennsylvania ▪ Hundreds of producing wells demonstrate Gas In Place high quality, consistent results acros
Slide 20: Southwest Appalachia Acreage Position
Southwest Appalachia Acreage Position Note: Grey area is greater ▪ Longer laterals and existing pads in 2018 provide low-risk Pittsburgh area. Range acreage outlined in green. PA efficiency gains OH ▪ Increased optionality due to quality of acreage position, gathering system, available locations and
Slide 21: North Louisiana Acreage Position
North Louisiana Acreage Position ▪ ~140,000(a) net acres of stacked pay potential in North Louisiana ▪ Acreage favorably located near growing Gulf Coast demand center provides improved price realizations and minimal transportation cost ▪ Currently focused on Terryville development while continuing t
Slide 22: Diversified Marketing Strategy
Diversified Marketing Strategy Appalachian Production Has Ability to Reach Multiple Markets ▪ Currently selling natural gas in the Gulf Coast, Midwest, Southeast and Northeast markets ▪ Exporting ethane and propane internationally with optionality of in-basin and Gulf Coast sales North Louisiana Pro
Slide 23: Innovative NGL Marketing Agreements Enhance Pricing
Innovative NGL Marketing Agreements Enhance Pricing ▪ First-mover on Appalachian NGL exports to Europe via ethane sales to INEOS using Mariner East capacity ▪ Range’s propane has been sold internationally since 2016 through Marcus Hook, with option to sell into premium NE winter markets ▪ Mariner We
Slide 24: Mariner East: Exporting Ethane and Propane
Mariner East: Exporting Ethane and Propane ▪ Only producer with current capacity on Mariner East 1 ▪ Historic first shipments of ethane from U.S. to Europe ▪ Optionality of selling propane internationally or in local markets ▪ Improved ethane and propane netbacks First VLGC Loading of Range Propane
Slide 25: SW PA Wet Area Marcellus 2018 Well Economics
SW PA Wet Area Marcellus 2018 Well Economics ▪ Southwestern PA – (Wet Gas case) ▪ ~225,000 Net Acres NYMEX Rate of ▪ EUR / 1,000 ft. – 2.95 Bcfe Gas Price Return ▪ EUR – 28.3 Bcfe Strip - 55% (77 Mbbls condensate, 2,330 Mbbls NGLs & 13.8 Bcf gas) ▪ Drill and Complete Capital $7.3 MM $3.00 - 64% ($76
Slide 26: SW PA - Wet Area 2018 Production Forecast
SW PA - Wet Area 2018 Production Forecast 3,000 Consistent normalized production results for many years 2,500 Normalized McfE/Day per 1,000 ft. 2,000 1,500 1,000 500 0 0 100 200 300 400 500 600 700 800 900 1000 Days On 2017 NORM MCFE PRODUCTION 2016 NORM MCFE PRODUCTION 2015 2015MCFE NORMPRODUCTION
Slide 27: SW PA Super-Rich Area Marcellus 2018 Well Economics
SW PA Super-Rich Area Marcellus 2018 Well Economics ▪ Southwestern PA – (Wet Gas case) ▪ ~110,000 Net Acres NYMEX Rate of ▪ EUR / 1,000 ft. – 2.60 Bcfe Gas Price Return ▪ EUR – 30.1 Bcfe Strip - 62% (416 Mbbls condensate, 2,309 Mbbls NGLs & 13.7 Bcf gas) ▪ Drill and Complete Capital $9.2 MM $3.00 -
Slide 28: SW PA – Super-Rich Area 2018 Production Forecast
SW PA – Super-Rich Area 2018 Production Forecast 3,500 3,000 Continued improvement in normalized well performance with 2017 being best year 2,500 Normalized McfE/Day per 1,000 ft. 2,000 1,500 1,000 500 0 0 100 200 300 400 500 600 700 800 900 1000 Days On 2017 NORM MCFE PRODUCTION 2016 NORM MCFE PROD
Slide 29: SW PA Dry Area Marcellus 2018 Well Economics
SW PA Dry Area Marcellus 2018 Well Economics ▪ Southwestern PA – (Dry Gas case) ▪ ~170,000 Net Acres NYMEX Rate of ▪ EUR / 1,000 ft. – 2.52 Bcf Gas Price Return ▪ EUR – 24.8 Bcf Strip - 58% ▪ Drill and Complete Capital $6.5 MM $3.00 - 70% ($656 K per 1,000 ft.) ▪ Average Lateral Length – 9,830 ft. ▪
Slide 30: SW PA - Dry Area 2018 Production Forecast
SW PA - Dry Area 2018 Production Forecast 3,500 3,000 Consistent normalized production results over many years Normalized Residue Mcf/Day per 1,000 ft. 2,500 2,000 1,500 1,000 500 Surface Facility Constraints 0 0 100 200 300 400 500 600 700 800 900 1000 Days On 2017 NORM RESIDUE GAS PRODUCTION 2016
Slide 31: Targeting / Downspacing Production Results
Targeting / Downspacing Production Results 3,000 2,500 ▪ Optimized targeting shows ~50% increase in cumulative production after 1,300 days 2,000 ▪ Normalized well costs were $850k less for optimized versus original 1,500 ▪ No detrimental production impact seen on the original wells 1,000 500 - 0 200
Slide 32: Return to Existing Pads – Marcellus
Return to Existing Pads – Marcellus 100,000 Drilled Wells - 2015 10,000 Additional 3 wells Wellhead Gas (MCFD) 1,000 Future Locations 100 Drilled 10 Wells - 2014 1 Mar-14 Sep-14 Apr-15 Oct-15 May-16 Nov-16 Jun-17 Dec-17 Wellhead Gas Ability to target our best areas with significant cost savings 32
Slide 33: Deep Utica
Deep Utica ▪ Range has drilled three Deep Utica wells ▪ Range’s third well appears to be one of the best dry gas Utica wells in the basin (next slide) ▪ Continued improvement in well performance due to higher sand concentration and improved targeting ▪ 400,000 net acres in SW PA prospective The Indu
Slide 34: Utica Wells – Wellhead Pressure vs. Cumulative Production
Utica Wells – Wellhead Pressure vs. Cumulative Production Range’s DMC Properties well one of the best in the Utica 34
Slide 35: N. LA Combined Lower Cotton Valley Well Economics
N. LA Combined Lower Cotton Valley Well Economics ▪ Combined Lower Cotton Valley ▪ ~140,000(a) Net Acres NYMEX Rate of ▪ a) ▪ EUR / 1,000 ft. – 1.61 Bcfe Gas Price Return ▪ EUR – 12.1 Bcfe Strip - 27% (11 Mbbls condensate, 408 Mbbls NGLs & 9.6 Bcf gas) ▪ Drill and Complete Capital $8.4 MM $3.00 - 33
Slide 36: N. LA 2018 Combined Lower Cotton Valley Production Forecast
N. LA 2018 Combined Lower Cotton Valley Production Forecast 4000 3500 3000 2500 MCFED / 1,000' LL 2000 1500 1000 500 0 0 100 200 300 400 500 600 700 Days On Offset Normalized Production CVCombined Combo TCLower Cotton Valley TC 36
Slide 37: 2017 Proved Reserves
2017 Proved Reserves Track Record of Reserve Growth 18 Year-End 2017 SEC PV10 of $8.1 billion 16 Total Proved Reserves (Tcfe) 14 12 10 8 6 4 2 0 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 ▪ Proved reserves of 15.3 Tcfe as of year end 2017 ▪ Proved reserves increased ~26% y/y excluding acquisi
Slide 38: Financial Detail
Financial Detail
Slide 39: Well-Structured, Resilient Balance Sheet
Well-Structured, Resilient Balance Sheet ▪ $4 billion credit facility, Capital Structure(a) ($3B borrowing base, $2B committed) (millions) 3Q18 ▪ No note maturities until 2021 Bank Debt (a) $ 971 Senior Notes 2,877 ▪ Simple capital structure Senior Sub Notes 49 Debt 3,897 ▪ Near-term cash flow prote
Slide 40: Recycle Ratio Calculation Example
Recycle Ratio Calculation Example Cash margin per mcfe / PUD development costs per mcfe. Numerator: Pre-Hedge Realized Price (a) $ 3.51 per mcfe All-In Cash Costs (Mid-Point of 2018 Expectations) (b) $ 2.07 per mcfe Adjusted Margin per Mcfe $ 1.44 per mcfe Denominator: Future Development Costs of YE
Slide 41: Natural Gas & Oil Hedging Status
Natural Gas & Oil Hedging Status Volumes Hedged Average Hedge Prices Time Period (Mmbtu/day) ($/Mmbtu) 4Q18 Swaps 1,380,000 $2.97 4Q18 Sold Calls 70,000 $3.10 Gas Swaps1 FY19 Swaps 892,603 $2.83 FY20 Swaps 10,000 $2.75 Volumes Hedged Average Hedge Prices Time Period (bbl/day) ($/bbl) 4Q18 Swaps 8,50
Slide 42: Liquids Hedging Status
Liquids Hedging Status Volumes Hedged Average Hedge Prices Time Period (bbls/day) ($/gal) 4Q18 Swaps 11,668 $0.74 4Q18 Collars 5,000 $0.95 x $1.04 Propane (C3)1 1H19 Swaps 7,500 $0.92 1Q19 Collars 6,500 $0.92 x $1.02 4Q18 Swaps 5,500 $0.91 Normal Butane (NC4) FY19 Swaps 2,250 $1.22 4Q18 Swaps 5,402
Slide 43: Contact Information
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
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