Range Resources Company Presentation - April 28, 2014

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April 28, 2014
Range Resources Corporation
Company Presentation

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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 and exploration projects, finding costs, operating costs, overhead costs, cash flow, NPV10, EUR and earnings are forward-looking
statements. Our forward looking 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 costs and estimates we believe are reasonable based on information currently available to us; however, our
assumptions and the Company’s future performance are 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 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, and there is no assurance that our projected results, goals and financial projections can or will be met.
This presentation includes certain non-GAAP financial measures. 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 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," or "unproved resource potential,”
"upside" and “EURs per well” 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 being actually 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, unrisked 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 recovery include the scope of Range's drilling program,
which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and
equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of
horizontal laterals, actual drilling results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of
resource potential may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and
expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the
undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors
are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com
or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K by calling the SEC at 1-800-
SEC-0330.
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3
Range Resources Strategy
 Focus on PER SHARE
GROWTH of production
and reserves at top-quartile
or better cost structure
while high grading the
inventory
 Maintain simple, strong
financial position
 Operate safely and be
a good steward of the
environment
Proven track record of performance
Marcellus Shale
41 to 51Tcfe resource potential
Upper Devonian Shale
12 to 18 Tcfe resource potential
Utica/Point Pleasant Shale
Midcontinent
Mississippian, St. Louis, Cana Woodford, Granite Wash
West Texas
Wolfcamp, Cline Shale, Wolfberry
Nora Area
Huron Shale, Berea, Big Lime, CBM
Total Resource Potential
64 to 85 Tcfe without Utica/Point Pleasant Shale
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Range – Significant Growth Model for Many Years
 2014 production growth expected to be 20%-25%
 High rate of return, high growth, large scale assets
 Solid track record of execution, planning, marketing and
logistics
 Low cost structure
 Resource potential 8-10 times proved reserves*
 Strong financial position
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*Without quantifying Utica/Point Pleasant Potential

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0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
2008 2009 2010 2011 2012 2013
5
10
15
20
25
30
35
40
45
50
2008 2009 2010 2011 2012 2013
Range is Focused on Per Share Growth, on a Debt-Adjusted Basis
Production/share – debt adjusted Reserves/share – debt adjusted
 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
Mcfe/share
Mcfe/share
5
2013 Increase of 26% 2013 Increase of 25%

6
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
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.
2008 2009 2010 2011 2012 2013
Reserve
Replacement(1) $1.64 $1.25 $0.83 $0.68 $0.68 $0.66
LOE (2) $0.99 $0.82 $0.72 $0.60 $0.41 $0.37
Prod. taxes $0.39 $0.20 $0.19 $0.14 $0.15(3) $0.13
G&A (2) $0.49 $0.51 $0.55 $0.56 $0.46 $0.42
Interest $0.71 $0.74 $0.73 $0.69 $0.61 $0.51
Trans. &
Gathering
$0.08 $0.32 $0.40 $0.62 $0.70 $0.75
Total $4.30 $3.84 $3.42 $3.29 $3.01 $2.84
$0.00
6

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$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
Lease Operating Expense G&A Expense Interest Expense
PUD Adjustment 3-Year Reserve Replacement
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Range – #2 Low Cost Producer in 2012
$/Mcfe
Source: Bank of America Securities 2012 E&P Full-Cycle Margin & Reserve Digest supplemented with Range peer group.
* Peer group company added
** Three-year reserve replacement cost not meaningful due to negative reserve revisions, or data extents beyond the graph
Note: LOE includes production taxes, gathering, & transportation; Interest includes preferred dividends and capitalized interest; and G&A expense excludes equity-based compensation
**
1st, 2nd, or 3rd in the Bank of America Study for Each of the Last 9 Years
Range Resources

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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 $1.0 billion under commitment amount
 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 Ba1/BB corporate rating during growth
 Solid Hedge Position
– Range typically hedges a significant portion of upcoming 12 months of
production
– For 2014, over 80% of projected production is hedged
– For 2015, over 30% of projected production is hedged
– Hedging in 2016 has started
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Moved 6.4 Tcfe of Resource Potential into Proved
Reserves in the Last Four Years
(1) Proforma 3.5 Tcfe after Barnett sale
(2) Net unproved resource potential.
(3) Added 12 – 15 Tcfe resource potential for tighter spaced drilling in the wet and super-rich Marcellus to YE 2012 resource potential at mid-year 2013
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Tcfe YE 2009 YE 2010 YE 2011 YE 2012 YE 2013
Proved
Reserves
3.1 4.4(1) 5.1 6.5 8.2
Resource
Potential (2)
24 - 32 35 - 52 44 - 60 48 – 68(3) 64 - 85
Proved reserves have increased by 28% per year on a
compounded basis since 2009

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Resource Potential is 8 to 10 Times Proved Reserves
Resource Area
Gas
(Tcf)
Liquids
(Mmbbls)
Net Unproven
Resource
Potential (Tcfe)
Marcellus Shale 27 – 35 2,250 – 2,740 41 – 51
Upper Devonian Shale 8 – 12 600 – 940 12 – 18
Midcontinent, Nora
and Permian
6 – 8 800 – 1,260 11 – 16
TOTAL 41 – 54 3,650 – 4,940 64 – 85
As of 12/31/2013 – Does not include Utica/PP or tighter spacing in dry Marcellus areas; Liquids include Ethane
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~1 Million Net Acres Prospective for Shales in PA
Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013)
(1) Approximately 140,000 acres prospective for Marcellus; ~175,000 acres prospective for wet Utica/Point Pleasant. (2) Extends partially into WV.
Northwest
305,000 net acres(1)
(Legacy acreage is largely
held by shallow production)
Southwest
530,000 net acres(2)
(95% of acreage is HBP or projected to
be drilled under existing lease terms)
Northeast
120,000 net acres
(One rig is projected to
hold all blocked up
acreage being targeted for
development)

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Pennsylvania Stacked Pays – Net Acreage
Upper Devonian
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330,000 230,000 560,000
470,000 320,000 790,000
175,000 400,000 575,000
975,000 950,000 1,925,000
Stacked pays allow for multiple development opportunities at 1,000 foot spacing
between wells and later with 500 foot spacing prospective on most acreage
Marcellus
Utica/Point
Pleasant
Wet
Acreage
Dry
Acreage
Total
Acreage

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Gas In Place (GIP) – Marcellus Shale
Note: Townships where Range holds ~3,000 or more acres (as of 12/31/2013), 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
developed in the Marcellus
• Condensate and NGLs are in
gaseous form in the reservoir

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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

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Gas In Place (GIP) – Utica/Point Pleasant
The greatest GIP in the
Utica/Point Pleasant is in the
dry gas window in SW PA

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Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA
When GIP analysis from the Marcellus, Upper
Devonian and Utica/Point Pleasant are
combined, the largest stacked pay resource is
located in SW PA where Range has
concentrated its acreage position

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Southwest PA – Range’s 530,000 Net Acres
 Approximately 2,300
industry wells (1,700
horizontal & 600 vertical)
have defined the
productive boundaries
of the Marcellus
 Range’s acreage is
highly prospective for
Marcellus, with low
reinvestment risk and
high rates of return
 Up to nine years of
production history from
this area
Note: Townships where Range holds ~3,000 or more acres are shown in yellow (As of 12/31/2013)
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Small Percentage of Acreage Drilled
▪ Prospective acreage 530,000
▪ Assumed spacing ~80 acres
▪ Potential Marcellus Shale locations 6,625
▪ Producing horizontal wells ~540
▪ Drilled wells divided by potential locations ~8%
Southwest PA – Large Upside Potential
~670 Mmcfe/d net being produced from ~8%
of Range’s acreage in SW PA
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Super-Rich Wet Dry
EUR
2.05 Mmboe (12.3 Bcfe)
1,172 Mbbls & 5.3 Bcf
12.3 Bcfe
978 Mbbls & 6.4 Bcf
13.4 Bcf
EUR/1,000 ft lateral
0.39 Mmboe
(2.32 Bcfe equivalent)
2.93 Bcfe 2.58 Bcf
EUR/stage
78.8 Mboe
(473 Mmcfe equivalent)
586 Mmcfe 515 Mmcf
Well Cost $6.8 MM $6.1 MM $6.6 MM
Stages 26 21 26
Lateral Length 5,300 ft 4,200 ft 5,200 ft
IRR – Strip 104% 107% 117%
IRR – $4.00 105% 105% 104%
Southwest PA – Development Mode Economic Summary
With the robust returns from all SW PA areas, Range will be
taking a balanced approach to developing acreage and
growing overall production at 20% to 25% each year

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Innovative Gas Marketing
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 SW PA has better infrastructure
 Range has added ~40 new
customers since 2012 in the
South, Southeast, Mid-Atlantic and
Midwest
 85% to 90% of Range’s 2014
expected volumes are tied to
favorable indices
 Marcellus differentials were
$(0.06), $(0.11) and $0.88 for 3Q13,
4Q13 and 1Q14.

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Projected 2014 Projected 2016
Regional Direction Mmbtu/day
Transport
Cost per
Mmbtu
Mmbtu/day
Transport
Cost per
Mmbtu
Projected Pricing Indices
Firm Transportation
Local PA/OH 380,000 $ 0.21 430,000 $ 0.21
NYMEX, 219, TCO, DTI, M2,
Leidy
Northeast 230,000 $ 0.51 230,000 $ 0.51 NYMEX, NNY, M3
Midwest -- -- 200,000 $ 0.32 NYMEX, CCG, Michcon
Gulf Coast/Southeast 260,000 $ 0.29 335,000 $ 0.26 NYMEX, CGT
Firm Sales 240,000 -- 530,000 -- All of the above
Total Take-Away Capacity 1,110,000 $ 0.25 1,725,000 $ 0.21
Marcellus Gas Marketing Arrangements
We believe these firm arrangements provide adequate capacity to meet our
growth projections through 2016.

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Mariner West
ATEX
Mariner East
Innovative NGL Marketing – Domestically & Globally
Appalachia has significant
existing and growing
petrochemical demand for
NGLs from the Mid-West to
up-state New York and along
the Atlantic coastal industrial
centers. Range has the
option to sell into the local
markets or has the option to
export liquids out of the
Marcus Hook harbor.
Generally prices get an uplift
since the pricing alternative is
transporting liquids from Gulf
Coast.
Existing Pipeline Contractual Agreements (gross):
 Mariner West – 15,000 bbl/d of ethane
 ATEX – 10,000 bbl/d, increasing to 20,000 bbl/d of ethane
 Mariner East – 20,000 bbl/d of ethane
– 20,000 bbl/d of propane
Ethane export to
Canada 2013
Ethane pipeline to
Mont Belvieu markets
2014
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Propane/Ethane can be
tied into NE markets or
be exported in 2015
As NGL production increases, the Marcus
Hook export facilities will allow Range to
move its liquids to domestic and global
markets which gives Range alternative
pricing opportunities.

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Current Capability of Range’s Marcellus Area
Processing Plant
1.8 Bcf/d of
wet inlet gas
1.4 Bcf/d gas
55,000 bbls/d ethane
140,000 bbls/d
condensate and C3+
2.6 Bcfe/d
> 1.0 Bcf/d
> 3.6 Bcfe/d from the
Marcellus
(> 3.0 Bcfe/d net)
Additional dry gas:
Ethane contracts have cleared
a path, allowing Range to
produce over 3 Bcfe per day
net from the Marcellus alone
Inlet gas needed to produce
55,000 bbls ethane per day,
assuming minimum extraction

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Additional Upside – Appalachia Stacked Pays
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As Marcellus drilling holds all depths, industry activity is proving up our
SW PA Utica/Point Pleasant and Upper Devonian acreage
 Significant acreage positions in two areas
SW PA – dry gas (400,000 net acres)
NW PA – wet gas (175,000 net acres)
 Utica/Point Pleasant test in Washington Co.
planned to spud in 2Q2014
 Significant offset wells being drilled to the east
Utica/Point Pleasant
Upper Devonian Shale
 Upper Devonian acreage significantly derisked
 Latest Super-Rich well – 24 hour test rate
10.0 Mmcfe/d (4.0 Mmcf/d gas, 172 bbls
condensate, 826 bbls NGLs)
 Co-development of Upper Devonian &
Marcellus may result in enhanced Marcellus
wells
Stacked Pay Enhances Project Economics
Note: Townships where Range holds ~3,000 or more acres are shown in yellow
(As of 12/31/2012)

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Additional Upside – Oil Component
Mississippian Chat
Permian
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 ~160,000 net acres along the Nemaha Uplift
 Successfully drilled the southern width of the Nemaha Uplift
 Drilled highest oil rate well ever by Range – 24 hr IP of 1,263 boe (1,062
oil) per day
 Successfully drilled 12 mile northern step out well; 30 day production
rate of 330 boe per day with 94% liquids (85% oil, 9% NGLs)
 Assuming 80 acre spacing would result in over 2,000 well locations
 Currently being marketed
 Stacked pay potential: Upper/Middle/Lower Wolfcamp, Cline
 Surrounding industry activity is successfully drilling offset acreage with
multiple targeted horizons
 Drilled ~7,000 foot lateral wells in both the Upper Wolfcamp and Cline
Two Potentially Large Scale, Repeatable Oil Projects are being tested

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New Markets Increasing Demand for Natural Gas
Demand for natural gas could increase up to 20 Bcf per day by 2018(2)
 Power Generation Sector
 Utilities using more gas versus coal, by 2035 natural gas will surpass coal as leading electricity source (1)
 Estimates say 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 (1)
 Manufacturing/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
 IHS chemical estimates $125 billion in announced U.S. petrochemical investments. (3)
 Large number of proposed projects in gas-to-liquids, methanol, ethylene crackers and fertilizers
 Natural Gas Exports
 The outlook has changed from the U.S. being a net importer of natural gas to becoming a net exporter
 To date, six LNG export facilities have been approved(4), representing 10 Bcf/day of additional demand
 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” (4)
 Current proposed and announced export projects total 38.5 Bcf/day (5)
 Transportation Sector
 With natural gas vehicles (NGV’s) being 25% cleaner, fuel costs 50% less and new refueling stations being
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 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
 Range now has 184 CNG vehicles in its own corporate fleet
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1. EIA
2. Goldman Sachs
3. Wall St. Journal, 3/24/14
4. Department of Energy
5. DOE/FE LNG Applications

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 Environmental, Health and Safety issues can affect many aspects of our business. Range
feels 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 to the
DEP that are now being widely used.
− In 2009, Range pioneered water recycling for shale gas development and we were the
first company to achieve 100 percent reuse levels.
− In 2010, Range was the first company to voluntarily disclose fluids used in hydraulic
fracturing on a per well basis and provide that information to the public online.
− In 2012, Range initiated a Zero Vapor Protocol for wet gas and super rich areas in
Marcellus shale gas development.
 Range provides training to its employees to create a culture of safe performance and
regulatory compliance. Our Contractor Management protocol requires that work be
performed at its highest standard.
 Range remains active in incident management and response planning by working with local
community government and first responders to identify roles and responsibilities for a
robust unified management approach to unique situations.
 Range’s goal is to maintain a safe and secure working environment for our employees and
the communities in which we work.
Environment, Health and Safety - A Core Value at Range

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Range – Significant Growth Potential for Many Years
 2014 production growth expected to be 20%-25%
 High rate of return, high growth, large scale assets,
and low reinvestment risk
 Large net acreage position, with stacked pay
potential, in the Appalachian core areas allowing for
durable future growth
 Solid track record of execution, planning, marketing
and logistics
 Resource potential 8-10 times proved reserves
28

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Marcellus and
Appalachia
Section

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Shale Wells Drilled and Permitted
Legend
RANGE
ANADARKO
CHEVRON/CHIEF SW
CABOT
CHESAPEAKE
CHIEF
CONSOL
ECA
EOG
EQT
EXCO
REX
SHELL
TALISMAN
ULTRA
XTO/EXXON/PHILLIPS
OTHERS
Legend
Super-Rich Area
Wet Area
LARGER DOTS – DRILLED
SMALLER DOTS – PERMITS

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Super-Rich
110,000 acres
Southwest PA – Super-Rich Marcellus
Note: Townships where Range holds ~3,000+ acres are shown in
yellow (As of 12/31/2013)
 Acreage provides the
opportunity for condensate
growth
 In Q1 2014, Range drilled our
highest rate Marcellus well to
date - 24 hr 1P of 6,357 boe/d
(38.1 Mmcfe/d) with 65% liquids
 Planned 2014 activity in the
super-rich is expected to use
5,300 foot laterals and RCS
completions with expected
recoveries of 2.05 Mmboe (12.3
Bcfe)
 During 2014, Range plans to turn
to sales 57 super-rich wells
32
• Previously drilled well

33
SW PA Super-Rich Area Marcellus
Projected Development Mode Economics
 Southwestern PA – (high Btu case)
 EUR – 2.05 Mmboe (12.3 Bcfe)
(129 Mbbls condensate, 1,043 Mbbls NGLs, and 5.3 Bcf gas)
 Drill and Complete Capital $6.8 MM
 F&D – $4.00/boe
40%
60%
80%
100%
120%
140%
$3.00 $4.00 $5.00
Gas Price, $/Mmbtu NYMEX
IRR
 Includes gathering, pipeline and processing costs
 Oil price assumed to be $90.00/bbl with no escalation
 NGL price (except for ethane) assumed to be 40% of WTI with
escalation
 Ethane price tied to ethane contracts plus same comparable
escalation as gas price
 Strip dated 12/31/13 with 10 year average $81/bbl and $4.33/mcf
Strip pricing NPV10 = $15.0 MM
NYMEX
Gas Price
2.05
Mmboe
Strip - 104%
$3.00 - 81%
$4.00 - 105%
$5.00 - 132%
Reserves and economics based on
planned future activity of 5,300 foot
lateral length with 26 frac stages,
500 klbs/stage
33

34
Southwest PA – Super-Rich Marcellus
34
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
2013 2014 2015
Feet
Horizontal Length
5
10
15
20
25
30
2013 2014 2015
Stages
Average Number of Stages
0.1
0.2
0.3
0.4
0.5
2013 2014 2015
EUR(Mmboe)/1,000ft.
EUR per 1,000 ft.
0.0
0.3
0.6
0.9
1.2
1.5
1.8
2.1
2.4
2013 2014 2015
EUR(Mmboe)
EUR by Year
Gas NGLs Condensate

35
1
10
100
1,000
10,000
1 6 11 16 21 26 31 36
Bbls/dMcf/d
Months
Residue Gas OIL NGL (INCLUDES ETHANE)
Southwest PA – Super-Rich Marcellus Well Projection
35
• EUR – 1,172 Mbbls & 5.3 BCF
(2.05 Mmboe)
• 5,300 foot lateral length
• 26 frac stages
Estimated Cumulative Recoveries
Condensate
(Mbbls)
Residue
(Mmcf)
NGL w/ Ethane
(Mbbls)
1 Year 42 774 153
2 Years 62 1,260 248
3 Years 74 1,637 322
5 Years 90 2,213 436
10 Years 107 3,140 619
20 Years 119 4,235 834
EUR 129 5,300 1,043

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Southwest PA – Super-Rich Marcellus 2013 Well Performance
10
100
1,000
1 51 101 151 201 251 301 351
Liquids(Bbls/dper1,000')ResidueGas(Mcf/dper1,000')
Days
All production data normalized to 1,000 foot of lateral
2013 Type Curve (1.32 Mmboe) Normalized to 1,000' 2013 Type Curve (1.32 Mmboe) Normalized to 1,000'
2013 Actual Super Rich Well Performance (55 Wells) 2013 Actual Super Rich Well Perfomance (55 Wells)
Residue Gas Liquids
•2013 type curves based on 3,894' lateral length
•55 wells performing approximately 50% above 2013 type curve after one year
2013 Program Year
Super Rich Wells
2013 Program Year
Super Rich Wells
2013 Super Rich
Residue Gas TC
(1.32 Mmboe)
2013 Super Rich Liquids
TC
(1.32 Mmboe)

37
 Over 200 Range wells
placed on production in
wet gas area over the last
four years with varying
lateral lengths and frac
stages
 Planned 2014 activity in
the wet area is expected
to use 4,200 foot laterals
with RCS completions
resulting in anticipated
recoveries of 12.3 Bcfe
 During 2014, Range plans
to turn to sales 55 wet
wells
Southwest PA – Wet Marcellus
Note: Townships where Range holds ~3,000+ acres are shown in
yellow (As of 12/31/2013)
37
Super-Rich
110,000 acres Wet Gas
220,000 acres
Dry Gas
200,000 acres
• Previously drilled well

38
SW PA Wet Marcellus
 Southwestern PA – (wet gas case)
 EUR –12.3 Bcfe (27 Mbbls condensate, 951 Mbbls
NGLs, and 6.4 Bcf gas)
 F&D – $0.60/mcfe
40%
60%
80%
100%
120%
140%
160%
$3.00 $4.00 $5.00
IRR
 Oil price assumed to be $90.00/bbl with no escalation
 NGL price (except for ethane) assumed to be 40% of WTI with
escalation
 Ethane price tied to ethane contracts plus gas price escalation
 Strip dated 12/31/13 with 10 year average $81/bbl and $4.33/mcf
Strip pricing NPV10 = $12.9 MM
NYMEX
Gas Price
12.3
Bcfe
Strip - 107%
$3.00 - 68%
$4.00 - 105%
$5.00 - 149%
planned future activity of 4,200
foot lateral length with 21 frac
stages, 400 klbs/stage

39
Southwest PA – Wet Marcellus
39
2,000
2,500
3,000
3,500
4,000
4,500
5,000
2013 2014 2015
Feet
Horizontal Length
5
10
15
20
25
2013 2014 2015
Stages
1.0
1.5
2.0
2.5
3.0
3.5
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

40
1
10
100
1,000
10,000
1 6 11 16 21 26 31 36
Bbls/dMcf/d
Months
Residue Gas OIL NGL (INCLUDES ETHANE)
Southwest PA – Wet Marcellus Well Projection
40
• EUR – 978 Mbbls & 6.4 BCF
(12.3 Bcfe)
• 21 frac stages
Estimated Cumulative Recoveries
Condensate
(Mbbls)
Residue
(Mmcf)
NGL w/ Ethane
(Mbbls)
1 Year 11 1,082 161
2 Years 14 1,674 249
3 Years 17 2,117 315
5 Years 19 2,775 412
10 Years 23 3,841 571
20 Years 25 5,095 757
EUR 27 6,400 951

41
Represent a 10+ Bcf well Represent a 5-10 Bcf well
Southwest PA – Industry Activity in Dry Gas Acreage
 56% of horizontal dry gas
Marcellus wells drilled by
industry in SW PA have
projected recoveries from
5 to over 20 Bcf per well
 Range’s SW Pennsylvania
dry gas acreage is
predominantly held by
production
 Range’s future wells are
expected to be 5,200 foot
laterals with RCS
completions and
anticipated recoveries of
13.4 Bcf
Note: Townships where Range holds ~3,000 or more acres are shown in yellow (As of 12/31/2013)
200,000 net
acres
41

42
SW PA Dry Marcellus
 Southwestern PA – (dry gas)
 EUR – 13.4 Bcf
 F&D – $0.59/mcf – (13.4 Bcf)
20%
40%
60%
80%
100%
120%
140%
160%
180%
200%
220%
$3.00 $4.00 $5.00
IRR
 Strip dated 12/31/13 with 10 year average $4.33/mcf Strip pricing NPV10 = $12.4 MM
NYMEX
Gas Price
13.4
Bcf
Strip - 117%
$3.00 - 39%
$4.00 - 104%
$5.00 - 201%
42
planned future activity of 5,200 foot
lateral length with 26 frac stages,
300 klbs/stage

43 43
Southwest PA – Dry Marcellus
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
2013 2014 2015
Feet
Horizontal Length
5
10
15
20
25
30
2013 2014 2015
Stages
1.0
1.2
1.4
1.6
1.8
2.0
2.2
2.4
2.6
2.8
2013 2014 2015
EUR(Bcf)/1,000ft.
EUR per 1,000 ft.
0
2
4
6
8
10
12
14
16
2013 2014 2015
EUR(Bcf)
EUR by Year
Gas

44
1
10
100
1,000
10,000
100,000
1 6 11 16 21 26 31 36
Mcf/d
Months
Residue Gas
Southwest PA – Dry Marcellus Well Projection
44
• EUR – 13.4 BCF
• 26 frac stages
Estimated Cumulative
Recoveries
Residue
(Mmcf)
1 Year 2,951
2 Years 4,218
3 Years 5,115
5 Years 6,406
10 Years 8,434
20 Years 10,772
EUR 13,400

45
Marcellus Wet Gas Provides Significant Price Uplift
$4.16 $3.92
$3.20
$1.53
$1.53
$1.95
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
Dry Gas Wet Gas - Ethane Rejection Wet Gas - Ethane Extraction
Gas
(1140 Btu)
14% shrink
Condensate
NGLs (C3+)
Gas
(1055 Btu)
24% shrink
NGLs (C2+)
$7.40
$7.70- $7.80
$2.97 -
$3.07
Gas
(1040 Btu)
$4.16
$/Wellhead Mcf
Assumptions: $4.00 NG, $90.00 WTI, 40% WTI (C3+), 2.27 GPM (ethane rejection), 5.60 GPM (ethane extraction), all processing, shrink, fuel & ethane transport
included. Based on SWPA wet gas quality (1,275 processing plant inlet btu). Wet Gas (Ethane Extraction) based on full utilization of current
ethane/propane agreements. NOTE: Wet Gas (Ethane Rejection) equals 1.3 mcfe post-processing and Wet Gas (Ethane Extraction) equals 1.68 mcfe.
Current Projected - 2015
Condensate

46
Ethane Ship Currently Being Used by Evergas
Photo Courtesy of Evergas
46

47
54%
4%
9%
8%
Weighted Avg.
Composite Barrel (1)
Ethane C2
Propane C3
Iso Butane iC4
Normal Butane NC4
Natural Gasoline C5+
25%
(1) Based on estimated NGL volumes for 1Q 2014 (2) Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus
Marcellus NGL Pricing
47
Realized Marcellus NGL Prices
2013 2014
1Q 2Q 3Q 4Q 1Q
NYMEX – WTI (per bbl) $ 94.25 $ 94.20 $105.87 $97.48 $98.61
Mont Belvieu Weighted
Priced Equivalent (2) $53.37 $50.26 $52.63 $47.78 $37.61
Plant Fees plus
Differential
(16.21) (17.33) (18.63) (11.91) (8.41)
Average price before NGL
hedges
$37.16 $32.93 $34.00 $35.87 $29.20
% of WTI (NGL Pre-hedge
/ Oil NYMEX)
39% 35% 32% 37% 30%
% of Mont Belvieu
Weighted Equivalent 70% 66% 65% 75% 78%

48
Realized Marcellus Condensate Prices
Quarter
Condensate
bbls/d
WTI Oil
Price
Marcellus
Condensate Price
Condensate as
% of WTI
1Q 2012 3,395 $103.13 $83.54 81%
2Q 2012 3,434 $92.27 $77.51 84%
3Q 2012 4,422 $92.58 $79.05 85%
4Q 2012 6,047 $88.17 $76.57 87%
1Q 2013 6,457 $94.25 $82.56 88%
2Q 2013 6,216 $94.20 $80.41 85%
3Q 2013 7,368 $105.87 $86.54 82%
4Q 2013 7,889 $97.48 $79.37 81%
1Q 2014 8,292 $98.61 $81.59 83%
Marcellus Condensate Pricing
 Growing demand from Canada
 Greater use as blending agent with refiners and petrochemical users
Year
Condensate
Price
as % of WTI
2010 63%
2011 79%
2012 84%
2013 84%
48

49
Range Processing Capacity from MarkWest Liberty
Wet Gas - SW
 Currently 425 Mmcf/d firm cryo processing capacity plus unutilized third party capacity; processing capacity
increases to 625 Mmcf/d by 2Q 2014 and 1,025 Mmcf/d subsequently
(1) Unused capacity can be used by Range on an interruptible basis
(2) Mobley, Sherwood and Bluestone
(Mmcf/day) Houston Majorsville Other Total
Current
Range 355 70 425
Others 600 1,210 1,810
Future
Range 400 200 600
Others 200 920 1,120
Total
Range 755 270 1,025
Others 800 2,130 2,930
Total 755 1,070 2,130 3,955
49
(2)(1)(1)

50
50
Processing Capacity Development
Source: MarkWest Energy Partners, March 2014

51
 A 1-2 rig program is
designed to hold all
blocked up acreage
being targeted for
development
 Planned 2014 activity
in area is expected to
use 4,600 foot
laterals and 23 frac
stages
 In 2014, Range plans
to turn 14 wells to
sales in the northeast
Note: Townships where Range holds ~3,000+ acres are shown in yellow (As of 12/31/2013)
Northeast PA
51
Northeast
120,000 net acres

52
Firm Transport & Sales with Firm Transport
(Mmbtu/day)
2014 2016
SW PA
Firm Transport 830,000 1,155,000
Firm Sales 115,000 370,000
NE PA
Firm Transport 40,000 40,000
Firm Sales 125,000 160,000
TOTAL
Firm Transport 870,000 1,195,000
Firm Sales 240,000 530,000
1,110,000 1,725,000
Marcellus Area Pipelines – Take-Away Capacity
Columbia Gas Transmission/Columbia Gulf
Texas Eastern Transmission
Tennessee Gas Pipeline
Dominion Transmission
Transcontinental Gas Pipeline
Areas under development
Marcellus Fairway
52
Range will continue to layer on new firm transportation to meet our expected growth in gas production
(1)
(1) Excludes regional firm gathering to interstate pipelines

53
Marcellus – Planned and Proposed Infrastructure Projects through 2016
53
Incremental capacity: +10.0
Bcfd
Metropolitan NY Area
Williams Rockaway Lateral
+0.6 Bcfd
North & Northeast
Constitution Pipeline
Williams NE Connector
Spectra AIM Project
+1.7 Bcfd
*Data as of February 2014
*Capacities and timing may vary
*May not include all current projects
Mid-Atlantic & Southeast
NiSource (TCO) East Side Expansion
Williams Leidy SE Expansion
Williams Atlantic Sunrise
TETCO Team 2014
+3.1 Bcfd
South & Southwest
NiSource (TCO) West Side Expansion
TETCO OPEN Project
TETCO TEAM 2014
TETCO TEAM South
TETCO Gulf Markets
NiSource (TCO) Leach/Rayne Express
+3.2 Bcfd
West & Northwest
TETCO/DTE/Enbridge NEXUS Pipeline
TETCO Uniontown to Gas City
+1.4 Bcfd

54
 Range has completed two 500 foot spaced pilot projects in the
super-rich and wet areas of the Marcellus Shale in Washington
County PA that have been online for three and a half years
 Results from these projects have been very promising with
EURs for 500 foot spaced wells averaging 80% of EURs for
1,000 foot spaced wells
 Assuming full development of the super-rich and wet areas of
the Marcellus, tighter spacing adds an incremental 12 to 15
Tcfe of resource potential
 Dry gas areas also have tighter spacing potential
54
Tighter Spacing Adds 12 to 15 Tcfe in Super-Rich and Wet Areas

55 55
0
500
1,000
1,500
2,000
2,500
3,000
1 365 729 1093
Mcfed/1,000ft.
500 ft Wells 1,000 ft Wells
Year 1 Year 3Year 2
500 foot spaced wells produced 80%
of 1,000 foot spaced wells over a
three and a half year period
Production includes residue gas, condensate and NGLs
Projects conducted in the Super-Rich and Wet areas of the Marcellus
Results of Marcellus Tighter Spacing Pilot Projects

56
Range Virginia Assets
 Producing ~72
Mmcf/day – very low
decline rate
 Interest in over 3,000
producing wells
 9,000+ additional wells
to drill
 Stacked pay area
 Location is strategic to
expanding markets in
the southeast
 3.2 to 3.6 Tcf resource
potential
56
Mineral Rights
HBP
HBP + Royalty
Note: Acreage shown (As of 12/31/2013)
Virginia
230,000 net acres

58
Oklahoma / Kansas – Mississippian Chat
 Over 4,500 Mississippian wells
have defined the productive
boundaries
 On 80 acre spacing Range has
the opportunity to drill ~2,000
potential horizontal wells
 Mississippian could equate to
almost a billion barrel equivalent
field net for Range
 Highest average cumulative oil
production from vertical wells
are located in Kay County;
Cowley & Sumner counties are
also high
• Represent historic vertical Mississippian wells
Note: Sections where Range has acreage are shown in yellow (As of 12/31/2013), and average cumulative oil production per vertical well shown in maroon text
Range’s ~160,000 net acres
appear prospective based
on vertical well control
*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.
*
58

59
NEMAHA RIDGE (Uplift)
Location is Important
 Our location on the
Nemaha Uplift offers
enhanced Chat
development, as well as
a favorable structural
position
 Chat porosity ranges up
to 30% - 40% while
Mississippi Lime
porosity falls in the 3% -
5% range on average
 Higher structurally,
generally giving way to
better oil cuts
Range has ~160,000 Net Acres on or in Close Proximity to the Nemaha Ridge
Pennsylvania Formations
Chat
West East
59

60
Avg. Cum. Oil Production per Well from Mississippian
Based on industry reporting sources
*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.
*
Highest average cumulative oil
production from vertical wells
are located in Kay County
60

61
0%
20%
40%
60%
80%
100%
120%
140%
$80.00 $90.00 $100.00
61
Mississippian Chat Development Mode Economics
 Based on recent completion designed wells
 EUR – 485 Mboe - 600 Mboe
 Drill & Complete Capital $3.7 MM
− All cases include $200K for SWD
 F&D – $9.86/boe – (485 Mboe)
$8.06/boe – (600 Mboe)
Oil Price, $/bbl NYMEX
IRR
NYMEX
Oil Price 485 Mboe 600 Mboe
Strip - 59% 107%
$ 80.00 - 45% 81%
$ 90.00 - 56% 100%
$100.00 - 69% 121%
 Strip dated 12/31/13 with 10 year average $81.13/bbl and $4.33/mcf
 Gas price assumed to be $4.00/mcf in all scenarios
Strip Pricing NPV10 = $3.7 MM (485 Mboe)
Strip Pricing NPV10 = $6.7 MM (600 Mboe)

62
10
100
1,000
0 100 200 300 400 500 600 700 800
Days
Gas Average Ngl Average Oil Average BOE Average
485 MBOE Gas Type 485 MBOE Ngl Type 485 MBOE Oil Type 485 MBOE Equiv Type
600 MBOE Gas Type 600 MBOE Ngl Type 600 MBOE Oil Type 600 MBOE Equiv Type
62
Mississippian Type Curves By Product – Larger Frac
Note: Fewer number of wells included in data set moving left to right
Larger Stimulation Design
- 6 wells average EUR is 600 Mboe
- 3,800 foot laterals and 19 stages
- 70% of EUR comprised of Crude Oil and NGL with full Cryo Recoveries
- EUR equates to 7-14% recovery of the original oil in place
Bbls/dayMmcf/day

63
Concentrated Position Allows Low Cost Future Development
Rodman Plant – Mustang
Capacity: 70 Mmcf/d; up to 140 Mmcf/d
with offloads to other Mustang Plants
Residue Pipelines: OK-Tex (connected to
OGT, Enogex, CEGT, PEPL and Southern
Star)
Bellmon Plant – Superior
Capacity: 30 Mmcf/d and expanding
Residue Pipeline: Southern Star
 Range has ~160,000
net acres largely
blocked up for
economy of scale
 Gas processing and
crude oil refining are
all adjacent to
acreage
 Oil ~40 gravity
 Capacity is scalable
as production grows
 Firm transport
provided in
connection with
processing
agreements
Conoco Phillips crude oil
refinery
Capacity: 200,000 Bbls/d
63
Note: Acreage shown (As of 12/31/2013)

64 64
Financial and
Reserve Section

65
Strong, Simple Balance Sheet
Year-End
2010
Year-End
2011
Year-End
2012
Year-End
2013
1st Quarter
2014
($ in millions)
Bank borrowings $274 $187 $739 $500 $594
Sr. Sub. Notes 1,686 1,788 2,139 2,641 2,641
Less: Cash (3) (0) (0) (0) (0)
Net debt 1,957 1,975 2,878 3,141 3,235
Common equity 2,224 2,392 2,357 2,414 2,450
Total capitalization $4,181 $4,367 $5,235 $5,555 $5,685
Debt-to-
capitalization(1) 47% 45% 55% 57% 57%
Debt/EBITDAX(1) 2.8x 2.3x 3.2x 2.8x 2.8x
Liquidity(2) $ 971 $ 1,284 $ 927 $1,166 $1,029
(1) Ratios are net of cash balances.
(2) Liquidity equals cash available borrowings under the revolving credit facility, as requested.
65

66
Debt Maturities
$594
$300
$500 $500
$600
$750
0
100
200
300
400
500
600
700
800
Senior Secured Revolving Credit Facility (as of March 31, 2014)
Senior Subordinated Notes
Range maintains an orderly debt maturity ladder
($Millions)
Credit Facility
1Q14
66

67
Range’s Outstanding Bonds
Corporate Rating: Ba1 / BB Outlook: Stable
Range bonds have consistently traded in-line or better than BB rated index
67
Senior Subordinated Notes Amount Current YTW
8.00% due 2019 $ 300 0.94%
6.75% due 2020 $ 500 2.83%
5.75% due 2021 $ 500 3.62%
5.00% due 2022 $ 600 4.85%
5.00% due 2023 $ 750 4.94%
Total $2,650
Source: Bank of America as of 2/14/14
Note: Range’s weighted average maturity is 8 years (excluding notes callable in 2014)
(1) Excludes notes due 2019 given May 2014 first call date
4.19%
4.44%
5.81% 5.61%
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
Range Weighted
Average (1)
BB Index 7 to 10 Year
Maturity Index
E&P Index
YieldtoWorst

68
$0.70
$0.90
$1.10
$1.30
$1.50
2008 2009 2010 2011 2012 2013
$-
$0.20
$0.40
$0.60
$0.80
$1.00
2008 2009 2010 2011 2012 2013
$10,000
$15,000
$20,000
$25,000
$30,000
$35,000
2008 2009 2010 2011 2012 2013
1.0x
1.5x
2.0x
2.5x
3.0x
3.5x
4.0x
4.5x
2008 2009 2010 2011 2012 2013
Resilient Credit Metrics Driven by Low Cost Growth
Debt / EBITDAX Debt / Total Proved ($/mcfe)
Debt / Production ($/boepd) Debt / Proved Developed ($/mcfe)
Covenant
BB / Ba2 Peer Average for 2012

69
Volumes
Hedged
Average
Floor Price
Average
Cap Price
(Mmbtu/day) ( $ / Mmbtu) ( $ / Mmbtu)
2Q 2014 Swaps 200,000 $4.17
2Q 2014 Collars 447,500 $3.84 $4.48
3Q 2014 Swaps 260,000 $4.18
3Q 2014 Collars 447,500 $3.84 $4.48
4Q 2014 Swaps 260,000 $4.18
4Q 2014 Collars 447,500 $3.84 $4.48
2015 Swaps 277,432 $4.21
2015 Collars 145,000 $4.07 $4.56
2016 Swaps 72,500 $4.19
Gas Hedging Status
69
As of 04/22/2014

70
Volumes
Hedged
Average
Floor Price
Average
Cap Price
(bbls/day) ($/bbl) ($/bbl)
2Q 2014 Swaps 8,500 $94.51
2Q 2014 Collars 2,000 $85.55 $100.00
3Q 2014 Swaps 9,500 $94.35
3Q 2014 Collars 2,000 $85.55 $100.00
4Q 2014 Swaps 9,500 $94.35
4Q 2014 Collars 2,000 $85.55 $100.00
2015 Swaps 6,496 $89.70
Oil Hedging Status
70
As of 04/22/2014

71
Volumes
Hedged
Hedged (1)
Price
Propane (C3)
Volumes
Hedged
Hedged (1)
Price
(bbls/day) ($/gal) (bbls/day) ($/gal)
Natural
Gasoline (C5)
2Q 2014 Swaps 1,000 $2.113 2Q 2014 Swaps 12,000 $1.016
3Q 2014 Swaps - - 3Q 2014 Swaps 12,000 $1.018
4Q 2014 Swaps - - 4Q 2014 Swaps 12,000 $1.018
Normal
Butane (NC4) Ethane (C2)
2Q 2014 Swaps 4,000 $1.344 2Q 2014 Swaps - -
3Q 2014 Swaps 4,000 $1.344 3Q 2014 Swaps - -
4Q 2014 Swaps 4,000 $1.344 4Q 2014 Swaps - -
Natural Gas Liquids Hedging Status
(1) NGL hedges have Mont Belvieu as the underlying index.As of 04/22/2014
Conversion Factor:
One barrel = 42 gallons
71

72 72
16%
78%
6%
Budget = $1.52 Billion
Drilling
Acreage & Seismic
Pipelines, Facilities & Other
Budget by Area
Marcellus
Permian
Midcontinent
Appalachia / Nora
87%
8%
2014 Capital Budget

73
Eleven Years of Double-Digit Production Growth
0
200
400
600
800
1,000
1,200
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E
Mmcfe/d
Includes impact of acquisitions and asset sales
20%-25% Growth Projected for 2014
73

74
Outstanding 2013 Reserve Performance
Proved Reserves Walk Forward Bcfe
Balance at December 31, 2012 6,506
▪ Discoveries and extensions 1,733
▪ Purchases -
▪ Revisions – performance
Improved recovery PUD 630
PUD removal (374)
Field performance PDP 111
Total performance revision 367
▪ Revisions - pricing 81
▪ Sales (142)
▪ Production (343)
Balance at December 31, 2013 8,202
74
2013 Performance
 26% year-over-year increase
• Crude oil/condensate and
NGL reserve volumes
increased 48%
 612% reserve replacement
 $0.61 per mcfe all-in finding
and development cost
 $0.57 per mcfe drill bit finding
cost
 51% Proved developed

75
Growth at Low Cost
(1) Includes performance revisions only.
(2) From all sources, including price and performance revisions, excludes sales.
(3) Beginning in 2009, amounts based upon new SEC rules as to pricing and PUD methodology.
(4) Percentages shown are compounded annual growth rates
Top quartile growth at top quartile cost
75
2009(3) 2010 2011 2012 2013
3 Year
Average
5 Year
Average
Reserve growth 18% 42% 14% 29% 26% 23%(4) 25%(4)
Drill bit replacement (1) 540% 840% 850% 773% 612% 725% 718%
All sources replacement (2) 486% 931% 849% 680% 636% 703% 709%
Drill bit only - without acreage (1) $0.69 $0.59 $0.76 $0.67 $0.57 $0.66 $0.65
Drill bit only - with acreage (1) $0.90 $0.70 $0.89 $0.76 $0.63 $0.75 $0.76
All sources -
Excluding price revisions $0.90 $0.73 $0.89 $0.76 $0.63 $0.75 $0.76
Including price revisions $1.00 $0.71 $0.89 $0.86 $0.61 $0.77 $0.78

76 76
 Consumer Savings
 Shale production could save U.S. households up to as much as $113 billion a year per through 2015(1)
 Average US household will save up to $725 each year, savings could potentially rise to as much as
$1,200 a year by 2020 (2)
 Added more than $1,200 last year to the income of the average U.S. family (3)
 Per EIA, natural gas will supply 46% of all new power plants built through 2035, further increasing
savings
 Manufacturing American Products: Low feedstock and energy prices
 Could result in 1 million additional American factory jobs by 2025(4)
 Save U.S. manufacturers as much as $11.6 billion annually(4)
 Other industries: chemical, pharmaceuticals, etc.
 Family-Sustaining High-Paying Jobs
 1,345,513 direct and indirect jobs created by the U.S. Natural Gas Industry (5)
 Currently in PA: 241,926 jobs with an average salary of $84,400 (6)
 From 2005-2012, almost 90% of job growth in Pennsylvania came from oil and gas jobs in the
upstream and midstream (7)
 Natural Gas as a Transportation Fuel: CNG & LNG
 Cleaner-burning – about 25% lower carbon dioxide emissions
 Cheaper – Costs about 50% less than gasoline
 CNG fleet conversions are increasing
Why Natural Gas?
1. U.S. Federal Reserve economists
2. IHS September 2013
3. The Boston Consulting Group
4. PricewaterhouseCoopers 2012 Study
5. U.S. Natural Gas Caucus
6. PA Department of Labor and Industry
(December 2013)
7. Raymond James

77 77
 Water Usage:
− Least water consumptive energy resources per MMBTU at 0.6-5.8 gallons(1)
 Nuclear: 8-14
 Oil: 8-20 gallons
 Coal: 13-32 gallons
 Biodiesel from soy: 14,000-75,000 gallons
 Surface Impact: Access to hundreds of acres from one location
− Total surface disturbance during drilling, including access road, pad and required pipeline
infrastructure is less than 1%
 Air Quality: 2006-2012: Natural gas grew to provide 30% of electricity in the U.S. (2)
− During that time, U.S. has recorded the world’s largest decline in greenhouse-gas
emissions, reducing 450 million tons
− The U.S. has dropped CO2 emissions by 500 megatons – about 2x the entire global
reductions over the past 20 years(3)
− PA air quality has significantly improved since 2008 because of increased use of natural
gas for power generation. Improved air quality translates to $14 billion to $37 billion in
annual public health benefits(4)
Natural Gas – Less Environmental Impact
1. U.S. Federal Reserve economists
2. EIA
3. PricewaterhouseCoopers 2012 Study
4. Pennsylvania DEP

78
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, Financial Analyst
mfreeman@rangeresources.com
www.rangeresources.com
78

Range Resources Company Presentation - April 28, 2014

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Range Resources Company Presentation - April 28, 2014