Range Resources Presentation at UBS Global Oil & Gas Conference


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A presentation by Mike Middlebrook, vice president of Northern Marcellus Shale Division of Range Resources, delivered at the UBS conference on May 21, 2013. The presentaion focuses mostly on the Marcellus (and Utica) region, updating investors on Range's activities with shale drilling.

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Range Resources Presentation at UBS Global Oil & Gas Conference

  1. 1. May 21, 2013UBS Global Oil & Gas ConferenceMike Middlebrook – VP Northern Marcellus Shale Division
  2. 2. Forward-Looking StatementsStatements concerning well drilling and completion costs assume a development mode of operation; additionally, estimates of future capital expenditures,production volumes, reserve volumes, reserve values, resource potential, resource potential including future ethane extraction, number of development andexploration projects, finding costs, operating costs, overhead costs, cash flow, NPV10, EUR and earnings are forward-looking statements. Our forwardlooking statements, including those listed in the previous sentence are based on our assumptions concerning a number of unknown future factors includingcommodity prices, recompletion and drilling results, lease operating expenses, administrative expenses, interest expense, financing costs, and other costsand estimates we believe are reasonable based on information currently available to us; however, our assumptions and the Company’s future performanceare both subject to a wide range of risks including, the volatility of oil and gas prices, the results of our hedging transactions, the costs and results of drillingand operations, the timing of production, mechanical and other inherent risks associated with oil and gas production, weather, the availability of drillingequipment, changes in interest rates, litigation, uncertainties about reserve estimates, environmental risks and regulatory changes, and there is noassurance that our projected results, goals and financial projections can or will be met. This presentation includes certain non-GAAP financialmeasures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our website at www.rangeresources.com.The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering datademonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well asthe option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings withthe SEC. Range uses certain broader terms such as "resource potential," or "unproved resource potential,” "upside" and “EURs per well” or otherdescriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possiblereserves as defined by the SECs guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. TheSEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculativethan estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. Unprovedresource potential refers to Ranges internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recoveredwith additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitutereserves within the meaning of the Society of Petroleum Engineers Petroleum Resource Management System and does not include proved reserves. Areawide unproven, unrisked resource potential has not been fully risked by Ranges management. “EUR,” or estimated ultimate recovery, refers to ourmanagement’s internal estimates of per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as aproducer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’sPetroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Our management estimated these EURs based on our previousoperating experience in the given area and publicly available information relating to the operations of producers who are conducting operating in theseareas. Actual quantities that may be ultimately recovered from Ranges interests will differ substantially. Factors affecting ultimate recovery include thescope of Ranges drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability ofdrilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas inplace, length of horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimatesof resource potential may change significantly as development of our resource plays provides additional data. In addition, our production forecasts andexpectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and theundertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors areurged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or bywritten request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-SEC-0330.2
  3. 3. Range Resources Strategy3 Focus on PER SHAREGROWTH of productionand reserves at top-quartile or better coststructure while highgrading the inventory Maintain simple, strongfinancial position Operate safely and be agood steward of theenvironmentProven track record of performanceMarcellus Shale26 to 34 Tcfe resource potentialUpper Devonian Shale12 to 18 Tcfe resource potentialUtica ShaleMidcontinentMississippian, St. Louis, Cana Woodford, Granite Wash7 to 11 Tcfe resource potentialWest TexasCline Shale, Wolfberry1.1 to 1.9 Tcfe resource potentialNora AreaBerea, Big Lime, Huron Shale, CBM2.6 to 3.2 Tcfe resource potentialTotal Resource Potential48 to 68 Tcfe without Utica Shale
  4. 4. 4Range – Significant Growth Potential for Many Years• 20%-25% line-of-sight production growth for many years• Cash flow growth is expected to outpace production growth• High rate of return, high growth, large scale assets• Low cost structure• Resource potential 7-10 times proved reserves• Excellent technical and support teams• Strong financial position
  5. 5. Financial Position Strong, Simple Balance Sheet– Bank debt, subordinated notes and common stock– No debt maturity until 2016 (bank) and 2019 (notes)– Available liquidity of $1.6 billion Well Structured Bank Credit Facility– 28 banks with no bank holding more than 9% of total– Current borrowing base of $2.0 billion; commitment amount of $1.75 billion– Expect to maintain or improve BB/Ba2 corporate rating during growth Solid Hedge Position– Range typically hedges a significant portion of upcoming 12 months ofproduction– For 2013, over 70% of production is hedged– For 2014, approximately 50% of production is hedged– Hedging in 2015 has started.5
  6. 6. Resilient Credit Metrics Driven by Low Cost Growth6Debt / EBITDAX Debt / Total Proved ($/mcfe)Debt / Production ($/boepd) Debt / Proved Developed ($/mcfe)Covenant$0.10$0.20$0.30$0.40$0.50$0.60$0.70$0.80$0.90$1.002008 2009 2010 2011 2012 2012PF$10,000$15,000$20,000$25,000$30,000$35,0002008 2009 2010 2011 2012 2012PF$0.70$0.80$0.90$1.00$1.10$1.20$1.30$1.40$1.502008 2009 2010 2011 2012 2012PFNote: 2012PF calculations include pro forma adjustments for the ~$275mm pending Permian asset sale.BB / Ba2 Peer Average for 2011BB / Ba2 Peer Average for 2011BB / Ba2 Peer Average for 20111.0x1.5x2.0x2.5x3.0x3.5x4.0x4.5x2008 2009 2010 2011 2012 2012PF
  7. 7. 2008 2009 2010 2011 20125101520253035402007 2008 2009 2010 2011 2012Range is Focused on Per Share Growth, on a Debt-Adjusted BasisProduction/share – debt adjusted Reserves/share – debt adjusted2012 increase of 29% 2012 increase of 22% Production/share = annual production divided by debt-adjusted year-end diluted sharesoutstanding Reserves/share = year-end proven reserves divided by debt-adjusted year-end diluted sharesoutstanding7McfeMcfe
  8. 8. Ten Years of Double-Digit Production Growth010020030040050060070080090010002003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013EMmcfe/dIncludes impact of acquisitions and asset sales820%-25% Growth Projected for 2013
  9. 9. Unit Costs Are a Key Focus$/mcfe(1) Three-year average of drill bit F&D costs, excluding acreage (2) Excludes non-cash stock compensation (3) Excludes retroactive payments for PA impact fee in 2012.92008 2009 2010 2011 2012ReserveReplacement(1) $1.64 $1.25 $0.83 $0.68 $0.67LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15(3)G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46Interest $0.71 $0.74 $0.73 $0.69 $0.61Trans. &Gathering$0.08 $0.32 $0.40 $0.62 $0.70Total $4.30 $3.84 $3.42 $3.29 $3.00$-$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00$4.50$5.00$0.00
  10. 10. $-$2.00$4.00$6.00$8.00$10.00$12.00$14.00$16.00$18.00$20.00Lease Operating Expense G&A Expense Interest Expense 3-year All-in F&D10Source: Bank of America/Merrill Lynch 2012 E&P Full-Cycle Margin & Reserve Digest** Three-year reserve replacement cost not calculated due to negative reserve revisions.Note: LOE includes production taxes, gathering, & transportation; Interest includes preferred dividends and capitalized interest; and G&A expense excludes equity-based compensationRange – #1 Low Cost Producer in 20122012 Average1st, 2nd, or 3rd in the Bank of America Study for Each of the Last 9 years** ** **
  11. 11.’s Reserve Base and Upside are GrowingSize = Resource PotentialPlacement = Proved ReservesProvedReserves(Tcfe) Moved 4.7 Tcfe of resource potential into proved reserves in last three years Proved reserves have increased by 23% per year on a compounded basis Resource potential was 7-10 times proved reserves at year-end Improving capital efficiency(1) Net unproved resource potential. Resource potential prior to 2009 was referred to as “Emerging Plays”.(2) Proforma 3.5 Tcfe after Barnett sale.(Tcfe) YE 2007 YE 2008 YE 2009 YE 2010 YE 2011 YE 2012ProvedReserves2.2 2.7 3.1 4.4(2) 5.1 6.5ResourcePotential (1)16.2 - 21.9 20.5 - 28.2 24.0 - 31.7 35 - 52 44 - 60 48-681121.928.2 31.752.060.068.0
  12. 12. Northeast145,000 net acres~ 69% HBPSouthwest540,000 net acres(2)~ 51% HBPNorthwest315,000 net acres(1)~ 89% HBPGreaterPittsburgh~1 Million Net Acres Prospective for Shale in PANote: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2012)(1) Approximately 150,000 acres prospective for Marcellus; ~181,000 acres prospective for wet Utica (2) Extends partially into WV12
  13. 13. GreaterPittsburgh13Southwest PA – Range’s 540,000 Net Acres are Highly Prospective Approximately 1,650wells likely havedefined the productivelimits of the Marcellus(1,150 horizontal & 500vertical) Range’s acreageappears highlyprospective forMarcellus Range tested thediscovery well for theMarcellus in 2004 andfirst production beganin 2005Greene FayetteAlleghenyBeaverButlerSomersetWestmorelandArmstrongIndianaWashingtonNote: Townships where Range holds ~3,000 or more acres are shown in yellowBlue dots represent historical Marcellus wells
  14. 14. 14Small Percentage of Acreage Drilled▪ Prospective acreage 540,000▪ Assumed spacing 80 acres▪ Potential Marcellus Shale locations 6,750▪ Producing horizontal wells ~430▪ Drilled wells divided by potential locations ~6%Southwest PA – Large Upside Potential~500 Mmcfe/d net being produced from ~6%of Range’s acreage in SW PA
  15. 15. Dry Gas210,000 acres15 Over 200 wells placed onproduction in wet gas areaover the last four years withvarying lateral lengths andfrac stages As of the end of 2012, Rangehas placed 62 wells onproduction with an averagelateral length of 3,200 feet and13 frac stages With planned full ethaneextraction, the average EUR =8.7 Bcfe712 Mbbls (27 Mbblscondensate and 685 MbblsNGLs) and 4.4 Bcf For 2013, Range plans to drill3,200 feet laterals with 13 fracstages as its “typical” well.Economics are based on a“typical” well.Southwest PA – Wet MarcellusWVHouston PlantMajorsville PlantGreeneSuper-Rich110,000 acresWet Gas220,000 acresNote: Townships where Range holds ~3,000+ acres are shown in yellow• Drilled well
  16. 16. SW PA Wet MarcellusProjected Development Mode Economics Southwestern PA – (wet gas case) withPennsylvania State Impact Fee EUR – 712 Mbbls & 4.4 Bcf – (8.7 Bcfe) Drill and Complete Capital $4.9MM F&D – $ 0.66/mcfe0%20%40%60%80%100%120%$3.00 $4.00 $5.00Gas Price, $/Mmbtu NYMEXIRR(1)(2)(3)(1) Includes gathering, pipeline and processing costs(2) Oil price assumed to be $90.00/bbl with no escalation(3) NGL price (except for ethane) assumed to be 52% of WTI(4) Ethane price tied to ethane contracts plus gas price escalation(5) Strip dated 03/28/13 with 10 year average $86.86/bbl and $4.79/mcfStrip pricing NPV10 = $11.1 MMNYMEX GasPrice 8.7 BcfeStrip(4)(5) - 85%$3.00 - 56%$4.00 - 77%$5.00 - 101%16Reserves and economics based onplanned 2013 activity of 3,200 footlateral length with 13 frac stages
  17. 17. 17WVHouston PlantMajorsville PlantGreeneSuper-Rich110,000 acresWet Gas220,000 acresDry Gas210,000 acresSouthwest PA – Super-Rich MarcellusNote: Townships where Range holds ~3,000+ acres are shown in yellow• Drilled well Range plans to add more fracstages to wells drilled in thesuper-rich area in 2013 As of the end of 2012, Rangehas turned to sales 51 super-rich wells with an averagelateral length of 3,895 feet and15 frac stages Historical 2012 results withfull ethane extraction indicatean average EUR = 1.32 Mmboe754 Mbbls (104 Mbblscondensate and 650Mbbls NGLs) and 3.4 Bcf 2013 activity with planned fullethane extraction and 18stages have projected EUR =1.44 Mmboe824 Mbbls (109 Mbblscondensate and 715Mbbls NGLs) and 3.7 Bcf
  18. 18. SW PA Super-Rich Area MarcellusProjected Development Mode Economics Southwestern PA – (High BTU case) withPennsylvania State Impact Fee EUR – 824 Mbbls & 3.7 Bcf – (1.44Mmboe) Drill and Complete Capital $5.1 MM F&D – $ 4.16/boe40%60%80%100%120%$3.00 $4.00 $5.00Gas Price, $/Mmbtu NYMEXIRR(1)(2)(3)(1) Includes gathering, pipeline and processing costs(2) Oil price assumed to be $90.00/bbl with no escalation(3) NGL price (except for ethane) assumed to be 52% of WTI(4) Ethane price tied to ethane contracts plus same comparable escalation as gas price(5) Strip dated 03/28/13 with 10 year average $86.86/bbl and $4.79/mcfStrip pricing NPV10 = $12.8 MMNYMEX GasPrice 8.6 BcfeStrip(4)(5) - 97%$3.00 - 71%$4.00 - 88%$5.00 - 105%18Reserves and economics based onplanned 2013 activity of ~3,800 footlateral length with 18 frac stages
  19. 19. Marcellus Wet Gas Provides Significant Price Uplift$4.16 $3.92$3.20 $3.20$1.53$1.53 $1.53$2.09$0.00$1.00$2.00$3.00$4.00$5.00$6.00$7.00$8.00Dry Gas Wet Gas - 43% WTI Wet Gas - 43% WTI Wet Gas - 50% WTIGas(1140 Btu)14% shrinkCondensateNGLs(C3+)Gas(1055 Btu)24% shrinkCondensateNGLs(C2+)$7.54$7.80- $7.90$3.07 -$3.17Gas(1040 Btu)$4.16$/Wellhead McfAssumptions: $4.00 NG, $90.00 WTI, 43% WTI, 2.27 GPM (ethane rejection), 5.60 GPM (ethane extraction), all processing, shrink, fuel & ethane transport included. Based onSWPA wet gas quality (1275 processing plant inlet btu). Wet Gas (Projected) based on full utilization of current ethane / propane agreements.$8.15 - $8.25$3.42 -$3.52Gas(1055 Btu)24% shrinkCondensateNGLs(C2+)Current – ethane rejection Projected – ethane extraction19
  20. 20. 20Mariner WestATEXMariner EastInnovative NGL MarketingMariner East & West haveaccess to internationalmarkets and premium exportpricing for future contractsATEX gives access to largestethane market and storage inthe U.S. and allows foroperational flowAll of the markets are scalableExisting Contractual Agreements:• Mariner West – 15,000 bbl/d of ethane• ATEX – 20,000 bbl/d of ethane• Mariner East – 20,000 bbl/d of ethane– 20,000 bbl/d of propane Ties to northeast markets Both propane and ethane Allows for international exportWith existing ethane arrangements and minimumethane extraction to meet pipeline quality, Rangecan grow wet Marcellus alone to 1.8 Bcf/dEthane export toCanada 2013Ethane/Propane can betied into NE markets or beexported internationally2013/2015Ethane pipeline toMont Belvieu markets2014
  21. 21. 21Ethane Ship Currently Being Used by EvergasPhoto Courtesy of Evergas
  22. 22. Red dots represent a 10+ Bcf well Purple dots represent a 5-10 Bcf well22Southwest PA – Industry Activity in Dry Gas AcreageGreaterPittsburgh Range has ~210,000 netacres in the dry gas window 53% of horizontal dry gasMarcellus wells drilled byindustry in SW PA haveprojected recoveries from 5to over 20 Bcf per well Range’s SW Pennsylvaniadry gas acreage ispredominantly held byproduction Range’s dry gas acreageposition can providesignificant productiongrowth Additional pipeline projectexpansions are planned inthe areaNote: Townships where Range holds ~3,000 or more acres are shown in yellowGreene FayetteBeaverButlerSomersetWestmorelandArmstrongIndianaWashington210,000 netacres
  23. 23. SW PA Dry Gas MarcellusDevelopment Mode Economics23 Southwestern PA – (dry gas) withPennsylvania State Impact Fee EUR – 7.5 Bcf (Based on 16 wellscompleted in 2012) Drill and Complete Capital $4.5 MM F&D – $ 0.74/mcf – (7.5 Bcf)0%20%40%60%80%100%$3.00 $4.00 $5.00Gas Price, $/Mmbtu NYMEXIRR(1)(2)(3)2,900’ lateral length & 10 stages(1) Includes gathering, pipeline and processing costs(2) Oil price assumed to be $90.00/bbl in all scenarios(3) Strip dated 03/28/13 with 10 year average $86.86/bbl and $4.79/mcfStrip pricing NPV10 = $7.4 MMNYMEXGas Price 7.5 BCFStrip(3) - 57%$3.00 - 23%$4.00 - 50%$5.00 - 88%Future drilling is expected to havelonger laterals and more stages
  24. 24. 24Additional Upside- Significant acreage positions in two areasSW PA – dry gasNW PA – wet gasFirst well tested at 1.4 Mmcfe/dResults indicate well located in wetgas windowApproximately 25 industry wellsplanned in 20132013 plans – observe & study industryactivity as acreage is largely HBP- First three wells encouraging- 100,000 acres prospective- Approximately 50 industry wellsplanned in 2013- 2013 plans – observe & study industry activityas acreage is largely HBP- Range’s first four wells successful- Latest well – 24 hour test rate10.0 Mmcfe/d composed of4.0 Mmcf/d gas172 bbls condensate826 bbls NGLs- Industry has drilled ~20 successful wells- 6 verticals completed in 2012. Average IP 513Boe/d(262 Boe/day + 133 Boe/d NGLs + 977 Mcf/d)- Expected development on 20 acre spacing- Five wells planned for 2013Utica/Point PleasantCline ShaleUpper DevonianWolfberry
  25. 25. 25Oklahoma/Kansas - Horizontal Mississippian Over 4,500 Mississippianwells have defined theproductive limits On 80 acre spacing (4,000 footlaterals) Range has theopportunity to drill ~2,000potential horizontal wells Mississippian could equate toalmost a billion barrelequivalent field net for Range Highest average cumulativeoil production from verticalwells are located in KayCounty; Cowley & Sumnercounties are also high• Blue dots represent historic vertical Mississippian wellsNote: Sections where Range has acreage are shown in yellow, and average cumulative oil production per vertical well shown in maroon textRange’s ~160,000 netacres appear prospectivebased on vertical wellcontrol*Internal estimates indicate 64 MBO cumulative production for Cowley County wells. Based on data from 598 wells with first production prior to 12/31/1985.64 MBO*67 MBO27 MBO24 MBO 53 MBO85 MBO57 MBO16 MBO
  26. 26. 0%20%40%60%80%100%120%140%160%$80.00 $90.00 $100.00Horizontal Mississippian Development Mode Economics Based on 25 wells (2009-2012) EUR – 485 Mboe (2009-2011 wells)600 Mboe (2012 wells) Drill & Complete Capital $3.4 MM All cases include $200 M for SWD F&D – $ 8.91/boe – (485 Mboe)$ 7.27/boe – (600 Mboe)Oil Price, $/bbl NYMEXIRR(1)(2)(3)NYMEX 485 Mboe 600 MboeOil Price (2009-2011) (2012)Strip(2) - 91% 133%$ 80.00 - 65% 96%$ 90.00 - 81% 118%$100.00 - 98% 142%(1) Includes gathering, pipeline and processing costs(2) Strip dated 03/28/13 with 10 year average $86.86/bbl and $4.79/mcf(3) Gas price assumed to be $4.00/mcf in all scenariosStrip Pricing NPV10 = $4.8 MM (485 Mboe)Strip Pricing NPV10 = $7.5 MM (600 Mboe)26
  27. 27. New Markets Increasing Demand for Natural Gas Power Generation Sector Utilities using more gas versus coal due to an increasingly reliable supply, environmental advantagesand cost Per EIA, 2012 natural gas used for power generation in the U.S. increased by 4.3 Bcf/day compared to2011, representing 6% of current U.S natural gas demand The EIA estimates that natural gas fired power plants will supply 46% of all new power plant additionsthrough 2035- compared to 37% for renewables, 12% for coal and 3% for nuclear Petrochemical Due to the large price difference in naptha (oil-based) versus ethane (gas-based), U.S. internationalpetrochemical companies are converting their feedstocks from naptha to ethane. A study from the American Chemistry Council titled, “Shale Gas and New Petrochemicals Investment”,estimates investment of $16.2 billion in petrochemical plants & equipment over the next several years Natural Gas Exports In just a few years, the outlook has changed from the U.S. being a net importer of natural gas tobecoming a net exporter A Department of Energy Study in December 2012 concluded that natural gas exports would bebeneficial for the U.S. under any pricing scenario. “Across all these scenarios, the U.S. was projectedto gain net economic benefits from allowing LNG exports” Current proposed and announced export projects total 27 Bcf/day Transportation Sector With natural gas vehicles (NGV’s) being 25% cleaner, fuel costs 50% less and new refueling stationsbeing added across the U.S., the number of U.S. NGV’s is expected to increase significantly Fleet managers at AT&T, UPS, and Waste Management are converting all or parts of their fleets tonatural gas as are transit agencies, municipalities and state governments The three largest U.S. truck manufacturers are now producing dual-fuel CNG trucks. In 2012, Range purchased a total of approximately 150 CNG trucks for its own corporate fleet.27
  28. 28.  Environmental, Health and Safety issues can affect many aspects of our business. Rangefeels a deep responsibility to protect our employees, contractors, the public and theenvironment. It is held as a core value. Examples where Range has been a leader In 2008, Range recommended improved standards for well cementing and casing tothe DEP that are now being widely used. In 2009, Range announced 100% water recycling in the Marcellus. In 2010, Range was the first company to voluntarily disclose hydraulic fracturing fluidcontents. In 2011, Range’s zero vapor protocol and emission reduction and elimination programwas shared with the industry and regulators. Range provides training to its employees to create a culture of safe performance andregulatory compliance. Our Contractor Management protocol requires that work beperformed at its highest standard. Range remains active in incident management and response planning by working withlocal community government and first responders to identify roles and responsibilities fora robust unified management approach to unique situations. Range’s goal is to maintain a safe and secure working environment for our employees andcommunities in which we work.Environment, Health and Safety - A Core Value at Range28
  29. 29. 29Range – Significant Growth Potential for Many Years• 20%-25% line-of-sight production growth formany years• Cash flow growth is expected to outpaceproduction growth• High rate of return, high growth, large scaleassets• Resource potential 7-10 times proved reserves
  30. 30. Contact InformationRange Resources Corporation100 Throckmorton, Suite 1200Fort Worth, Texas 76102Main: 817.870.2601Fax: 817.870.2316Rodney Waller, Senior Vice Presidentrwaller@rangeresources.comDavid Amend, Investor Relations Managerdamend@rangeresources.comLaith Sando, Research Managerlsando@rangeresources.comMichael Freeman, Financial Analystmfreeman@rangeresources.comwww.rangeresources.com30