5.21.13 UBS Final Presentation Range Resources
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Transcript of 5.21.13 UBS Final Presentation Range Resources
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May 21, 2013
UBS Global Oil & Gas Conference
Mike MiddlebrookVP Northern Marcellus Shale Division
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Forward-Looking Statements
Statements 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 including
commodity 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 Companys 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 Companys probable and possible reserves in its filings with
the 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 SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. TheSECs 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 Range's 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 Engineer's Petroleum Resource Management System and does not include proved reserves. Areawide unproven, unrisked resource potential has not been fully risked by Range's management. EUR, or estimated ultimate recovery, refers to ourmanagements 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 EngineersPetroleum Resource Management System or the SECs oil and natural gas disclosure rules. Our management estimated these EURs based on our previous
operating 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 Range's interests will differ substantially. Factors affecting ultimate recovery include thescope of Range's 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.
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Range Resources Strategy
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Focus on PER SHAREGROWTH of productionand reserves at top-quartile or better coststructure while high
grading the inventory
Maintain simple, strongfinancial position
Operate safely and be agood steward of theenvironment
Proven track record of performance
Marcellus Shale26 to 34 Tcfe resource potential
Upper Devonian Shale12 to 18 Tcfe resource potential
Utica Shale
MidcontinentMississippian, St. Louis, Cana Woodford, Granite Wash
7 to 11 Tcfe resource potential
West TexasCline Shale, Wolfberry
1.1 to 1.9 Tcfe resource potential
Nora AreaBerea, Big Lime, Huron Shale, CBM
2.6 to 3.2 Tcfe resource potential
Total Resource Potential48 to 68 Tcfe without Utica Shale
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Range 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
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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 $1.75 billion Expect to maintain or improve BB/Ba2 corporate rating during growth
Solid Hedge Position
Range typically hedges a significant portion of upcoming 12 months ofproduction
For 2013, over 70% of production is hedged
For 2014, approximately 50% of production is hedged
Hedging in 2015 has started.
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Resilient Credit Metrics Driven by Low Cost Growth
6
Debt / EBITDAX Debt / Total Proved ($/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
$1.00
2008 2009 2010 2011 2012 2012PF
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
2008 2009 2010 2011 2012 2012PF$0.70
$0.80
$0.90
$1.00
$1.10
$1.20
$1.30
$1.40
$1.50
2008 2009 2010 2011 2012 2012PF
Note: 2012PF calculations include pro forma adjustments for the ~$275mm pending Permian asset sale.
BB / Ba2 Peer Average for 2011
BB / Ba2 Peer Average for 2011
BB / Ba2 Peer Average for 2011
1.0x
1.5x
2.0x
2.5x
3.0x
3.5x
4.0x
4.5x
2008 2009 2010 2011 2012 2012PF
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0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2007 2008 2009 2010 2011 20125
10
15
20
25
30
35
40
2007 2008 2009 2010 2011 2012
Range is Focused on Per Share Growth, on a Debt-Adjusted Basis
Production/share debt adjusted Reserves/share debt adjusted
2012 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 sharesoutstanding
7
Mcfe
Mcfe
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Ten Years of Double-Digit Production Growth
0
100
200
300
400
500
600
700
800
900
1000
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013E
Mmcfe/d
Includes impact of acquisitions and asset sales
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20%-25% Growth Projected for 2013
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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.
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2008 2009 2010 2011 2012
ReserveReplacement(1)
$1.64 $1.25 $0.83 $0.68 $0.67
LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41
Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15(3)
G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46
Interest $0.71 $0.74 $0.73 $0.69 $0.61
Trans. &Gathering
$0.08 $0.32 $0.40 $0.62 $0.70
Total $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
$0.00
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$-
$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&D
10
Source: 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 compensation
Range #1 Low Cost Producer in 2012
2012 Average
1st, 2nd, or 3rd in the Bank of America Study for Each of the Last 9 years
** ** **
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0.01.0
2.03.04.05.06.07.08.09.0
Ranges Reserve Base and Upside are Growing
Size = Resource PotentialPlacement = Proved Reserves
P
rovedReserves(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 2012
ProvedReserves
2.2 2.7 3.1 4.4(2) 5.1 6.5
ResourcePotential (1)
16.2 - 21.9 20.5 - 28.2 24.0 - 31.7 35 - 52 44 - 60 48-68
11
21.928.2 31.7
52.060.0
68.0
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Northeast145,000 net acres
~ 69% HBP
Southwest
540,000 net acres(2)~ 51% HBP
Northwest315,000 net acres(1)
~ 89% HBP
GreaterPittsburgh
~1 Million Net Acres Prospective for Shale in PA
Note: 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 WV
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GreaterPittsburgh
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Southwest PARanges 540,000 Net Acres are Highly Prospective
Approximately 1,650wells likely havedefined the productivelimits of the Marcellus(1,150 horizontal & 500vertical)
Ranges acreageappears highlyprospective forMarcellus
Range tested the
discovery well for theMarcellus in 2004 andfirst production beganin 2005Greene Fayette
Allegheny
BeaverButler
Somerset
Westmoreland
ArmstrongIndiana
Washington
Note: Townships where Range holds ~3,000 or more acres are shown in yellow
Blue dots represent historical Marcellus wells
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Small 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 Ranges acreage in SW PA
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Dry Gas210,000 acres
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Over 200 wells placed onproduction in wet gas areaover the last four years with
varying lateral lengths andfrac stages
As of the end of 2012, Rangehas placed 62 wells onproduction with an averagelateral length of 3,200 feet and
13 frac stages
With planned full ethaneextraction, the average EUR =8.7 Bcfe
712 Mbbls (27 Mbblscondensate and 685 Mbbls
NGLs) and 4.4 Bcf
For 2013, Range plans to drill3,200 feet laterals with 13 fracstages as its typical well.
Economics are based on atypical well.
Southwest PA Wet Marcellus
WV
Houston Plant
Majorsville Plant
Greene
Super-Rich110,000 acres
Wet Gas220,000 acres
Note: Townships where Range holds ~3,000+ acres are shown in yellow Drilled well
SW PA W M ll
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SW PA Wet MarcellusProjected Development Mode Economics
Southwestern PA (wet gas case) with
Pennsylvania State Impact Fee
EUR 712 Mbbls & 4.4 Bcf (8.7 Bcfe) Drill and Complete Capital $4.9MM
F&D $ 0.66/mcfe
0%
20%
40%
60%
80%
100%
120%
$3.00 $4.00 $5.00
Gas Price, $/Mmbtu NYMEX
IRR(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/mcf
Strip pricing NPV10 = $11.1 MM
NYMEX Gas
Price 8.7 Bcfe
Strip(4)(5) - 85%
$3.00 - 56%
$4.00 - 77%
$5.00 - 101%
16
Reserves and economics based onplanned 2013 activity of 3,200 footlateral length with 13 frac stages
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WV
Houston Plant
Majorsville Plant
Greene
Super-Rich
110,000 acresWet Gas
220,000 acres
Dry Gas210,000 acres
Southwest PA Super-Rich Marcellus
Note: 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 Mmboe
754 Mbbls (104 Mbblscondensate and 650Mbbls NGLs) and 3.4 Bcf
2013 activity with planned fullethane extraction and 18stages have projected EUR =1.44 Mmboe
824 Mbbls (109 Mbblscondensate and 715Mbbls NGLs) and 3.7 Bcf
SW PA S Ri h A M ll
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SW PA Super-Rich Area MarcellusProjected Development Mode Economics
Southwestern PA (High BTU case) with
Pennsylvania State Impact Fee
EUR 824 Mbbls & 3.7 Bcf (1.44Mmboe)
Drill and Complete Capital $5.1 MM
F&D $ 4.16/boe
40%
60%
80%
100%
120%
$3.00 $4.00 $5.00
Gas Price, $/Mmbtu NYMEX
IRR(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/mcf
Strip pricing NPV10 = $12.8 MM
NYMEX GasPrice 8.6 Bcfe
Strip(4)(5) - 97%
$3.00 - 71%
$4.00 - 88%
$5.00 - 105%
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Reserves and economics based onplanned 2013 activity of ~3,800 foot
lateral length with 18 frac stages
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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
$8.00
Dry Gas Wet Gas - 43% WTI Wet Gas - 43% WTI Wet Gas - 50% WTI
Gas
(1140 Btu)14% shrink
Condensate
NGLs
(C3+)
Gas
(1055 Btu)24% shrink
Condensate
NGLs
(C2+)
$7.54$7.80- $7.90
$3.07 -$3.17
Gas
(1040 Btu)
$4.16
$/Wellhead Mcf
Assumptions: $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 -$3.52
Gas
(1055 Btu)24% shrink
Condensate
NGLs
(C2+)
Current ethane rejection Projected ethane extraction
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Mariner West
ATEX
Mariner East
Innovative NGL Marketing
Mariner East & West haveaccess to international
markets and premium export
pricing for future contracts
ATEX gives access to largestethane market and storage in
the U.S. and allows foroperational flow
All of the markets are scalable
Existing 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 export
With existing ethane arrangements and minimum
ethane extraction to meet pipeline quality, Rangecan grow wet Marcellus alone to 1.8 Bcf/d
Ethane export toCanada 2013
Ethane/Propane can betied into NE markets or beexported internationally
2013/2015
Ethane pipeline toMont Belvieu markets
2014
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Ethane Ship Currently Being Used by Evergas
Photo Courtesy of Evergas
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Red dots represent a 10+ Bcf well Purple dots represent a 5-10 Bcf well
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Southwest PA Industry Activity in Dry Gas Acreage
GreaterPittsburgh
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
Ranges SW Pennsylvania
dry gas acreage ispredominantly held byproduction
Ranges dry gas acreage
position can providesignificant production
growth
Additional pipeline projectexpansions are planned inthe area
Note: Townships where Range holds ~3,000 or more acres are shown in yellow
Greene Fayette
Beaver
Butler
Somerset
Westmoreland
Armstrong Indiana
Washington
210,000 netacres
SW PA Dry Gas Marcellus
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SW PA Dry Gas MarcellusDevelopment Mode Economics
23
Southwestern PA (dry gas) withPennsylvania State Impact Fee
EUR 7.5 Bcf (Based on 16 wells
completed 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 $5.00
Gas Price, $/Mmbtu NYMEX
I
RR(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/mcf
Strip pricing NPV10 = $7.4 MM
NYMEXGas Price 7.5 BCF
Strip(3) - 57%
$3.00 - 23%
$4.00 - 50%
$5.00 - 88%
Future drilling is expected to havelonger laterals and more stages
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Additional Upside
- Significant acreage positions in two areasSW PA dry gas
NW PA wet gas
First well tested at 1.4 Mmcfe/d
Results indicate well located in wetgas window
Approximately 25 industry wells
planned in 20132013 plans observe & study industryactivity as acreage is largely HBP
- First three wells encouraging
- 100,000 acres prospective- Approximately 50 industry wells
planned in 2013
- 2013 plans observe & study industry activityas acreage is largely HBP
- Ranges first four wells successful- Latest well 24 hour test rate
10.0 Mmcfe/d composed of
4.0 Mmcf/d gas
172 bbls condensate
826 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 2013
Utica/Point Pleasant
Cline Shale
Upper Devonian
Wolfberry
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Oklahoma/Kansas - Horizontal Mississippian
Over 4,500 Mississippianwells have defined theproductive limits
On 80 acre spacing (4,000 foot
laterals) 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 wells
Note: Sections where Range has acreage are shown in yellow, and average cumulative oil production per vertical well shown in maroon text
Ranges ~160,000 netacres appear prospective
based 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 MBO
27 MBO
24 MBO 53 MBO
85 MBO
57 MBO
16 MBO
l l d
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0%
20%
40%
60%
80%
100%
120%
140%
160%
$80.00 $90.00 $100.00
Horizontal 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 NYMEX
IRR(1)(2)(3)
NYMEX 485 Mboe 600 Mboe
Oil 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 scenarios
Strip Pricing NPV10 = $4.8 MM (485 Mboe)
Strip Pricing NPV10 = $7.5 MM (600 Mboe)
26
N M k I i D d f N l G
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New Markets Increasing Demand for Natural Gas
Power Generation Sector Utilities using more gas versus coal due to an increasingly reliable supply, environmental advantages
and cost Per EIA, 2012 natural gas used for power generation in the U.S. increased by 4.3 Bcf/day compared to
2011, 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 additions
through 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. international
petrochemical 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 Expor ts In just a few years, the outlook has changed from the U.S. being a net importer of natural gas to
becoming a net exporter A Department of Energy Study in December 2012 concluded that natural gas exports would be
beneficial for the U.S. under any pricing scenario. Across all these scenarios, the U.S. was projected
to gain net economic benefits from allowing LNG exports Current proposed and announced export projects total 27 Bcf/day
Transpor tation Sector With natural gas vehicles (NGVs) being 25% cleaner, fuel costs 50% less and new refueling stations
being added across the U.S., the number of U.S. NGVs is expected to increase significantly Fleet managers at AT&T, UPS, and Waste Management are converting all or parts of their fleets to
natural 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.
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E i H l h d S f A C V l R
http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=mcmiiiOgHAEF4M&tbnid=WVY-g2EP66_sdM:&ved=0CAUQjRw&url=http://www.alpiq.com/what-we-offer/energy-services/plant-engineering/construction-of-chemical-and-petrochemical-plants/chemical-petrochemical-plants.jsp&ei=MCpCUcuCC8rk2QWHvIDYAg&bvm=bv.43287494,d.dmg&psig=AFQjCNG5ku-lcvLm7KijRf6pVTo8XnsIwg&ust=1363377014505323http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=mcmiiiOgHAEF4M&tbnid=WVY-g2EP66_sdM:&ved=0CAUQjRw&url=http://www.alpiq.com/what-we-offer/energy-services/plant-engineering/construction-of-chemical-and-petrochemical-plants/chemical-petrochemical-plants.jsp&ei=MCpCUcuCC8rk2QWHvIDYAg&bvm=bv.43287494,d.dmg&psig=AFQjCNG5ku-lcvLm7KijRf6pVTo8XnsIwg&ust=1363377014505323http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=Xv88QCJaWYsYbM&tbnid=xJ5Ss4BonDyLeM:&ved=0CAUQjRw&url=http://www.turbosquid.com/3d-models/3d-model-lng-tanker-galea/556572&ei=cylCUbmiCPHW2wWsuYHwDQ&bvm=bv.43287494,d.dmg&psig=AFQjCNGTghuptx5CPirAJ_9M0DKPW3FRJg&ust=1363376882096025http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=Xv88QCJaWYsYbM&tbnid=xJ5Ss4BonDyLeM:&ved=0CAUQjRw&url=http://www.turbosquid.com/3d-models/3d-model-lng-tanker-galea/556572&ei=cylCUbmiCPHW2wWsuYHwDQ&bvm=bv.43287494,d.dmg&psig=AFQjCNGTghuptx5CPirAJ_9M0DKPW3FRJg&ust=1363376882096025http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=Xv88QCJaWYsYbM&tbnid=xJ5Ss4BonDyLeM:&ved=0CAUQjRw&url=http://www.turbosquid.com/3d-models/3d-model-lng-tanker-galea/556572&ei=cylCUbmiCPHW2wWsuYHwDQ&bvm=bv.43287494,d.dmg&psig=AFQjCNGTghuptx5CPirAJ_9M0DKPW3FRJg&ust=1363376882096025http://www.google.com/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&docid=mcmiiiOgHAEF4M&tbnid=WVY-g2EP66_sdM:&ved=0CAUQjRw&url=http://www.alpiq.com/what-we-offer/energy-services/plant-engineering/construction-of-chemical-and-petrochemical-plants/chemical-petrochemical-plants.jsp&ei=MCpCUcuCC8rk2QWHvIDYAg&bvm=bv.43287494,d.dmg&psig=AFQjCNG5ku-lcvLm7KijRf6pVTo8XnsIwg&ust=1363377014505323 -
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Environmental, Health and Safety issues can affect many aspects of our business. Rangefeels a deep responsibility to protect our employees, contractors, the public and the
environment. 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 fluid
contents. In 2011, Ranges zero vapor protocol and emission reduction and elimination program
was 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.
Ranges goal is to maintain a safe and secure working environment for our employees and
communities in which we work.
Environment, Health and Safety - A Core Value at Range
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R Si ifi G h P i l f M Y
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Range Significant Growth Potential for Many Years
20%-25% line-of-sight production growth formany years
Cash flow growth is expected to outpace
production growth
High rate of return, high growth, large scaleassets
Resource potential 7-10 times proved reserves
C t t I f ti
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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
David Amend, Investor Relations Manager
Laith Sando, Research Manager
Michael Freeman, Financial Analyst
www.rangeresources.com
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