1

April 28, 2014

Range Resources Corporation

Company Presentation

2

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.

2

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

7 to 10 Tcfe resource potential

West Texas

Wolfcamp, Cline Shale, Wolfberry

1 to 2 Tcfe resource potential

Nora Area

Huron Shale, Berea, Big Lime, CBM

3 to 4 Tcfe resource potential

Total Resource Potential

64 to 85 Tcfe without Utica/Point Pleasant Shale

3

4

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

4

*Without quantifying Utica/Point Pleasant Potential

5

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2008 2009 2010 2011 2012 20135

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

Mc

fe/s

ha

re

Mc

fe/s

ha

re

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

$/m

cfe

(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

7

$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

7

Range – #2 Low Cost Producer in 2012 $/M

cfe

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

8

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

8

9

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

9

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

10

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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11

~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)

12

Pennsylvania Stacked Pays – Net Acreage

Upper Devonian

12

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

13

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

14

Gas In Place (GIP) – Upper Devonian 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.

• 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

15

Gas In Place (GIP) – Utica/Point Pleasant

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.

The greatest GIP in the

Utica/Point Pleasant is in the

dry gas window in SW PA

16

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

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.

17

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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18

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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19 19

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

20

Innovative Gas Marketing

20

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.

21 21

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.

22

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

22

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.

23 23

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

24

Additional Upside – Appalachia Stacked Pays

24

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)

25

Additional Upside – Oil Component

Mississippian Chat

Permian

25

~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

26

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

26

1. EIA

2. Goldman Sachs

3. Wall St. Journal, 3/24/14

4. Department of Energy

5. DOE/FE LNG Applications

27 27

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

28

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

29

Appendix

29

30 30

Marcellus and

Appalachia

Section

31

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

32

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

Fee

t

Horizontal Length

5

10

15

20

25

30

2013 2014 2015

Sta

ge

s

Average Number of Stages

0.1

0.2

0.3

0.4

0.5

2013 2014 2015

EU

R (

Mm

bo

e)/

1,0

00

ft.

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

EU

R (

Mm

bo

e)

EUR by Year

Gas NGLs Condensate

35

1

10

100

1,000

10,000

1 6 11 16 21 26 31 36

Bb

ls/d

Mcf/

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

36

Southwest PA – Super-Rich Marcellus 2013 Well Performance

10

100

1,000

1 51 101 151 201 251 301 351Liq

uid

s (

Bb

ls/d

per

1,0

00')

Resid

ue G

as (

Mcf/

d p

er

1,0

00')

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 Projected Development Mode Economics

Southwestern PA – (wet gas case)

EUR –12.3 Bcfe (27 Mbbls condensate, 951 Mbbls

NGLs, and 6.4 Bcf gas)

Drill and Complete Capital $6.1 MM

F&D – $0.60/mcfe

40%

60%

80%

100%

120%

140%

160%

$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 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%

Reserves and economics based on

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

Fee

t

Horizontal Length

5

10

15

20

25

2013 2014 2015

Sta

ge

s

Average Number of Stages

1.0

1.5

2.0

2.5

3.0

3.5

2013 2014 2015

EU

R (

Bc

fe)/

1,0

00

ft.

EUR per 1,000 ft.

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

2013 2014 2015

EU

R (

Bcfe

)

EUR by Year

Gas NGLs Condensate

40

1

10

100

1,000

10,000

1 6 11 16 21 26 31 36

Bb

ls/d

M

cf/

d

Months

Residue Gas OIL NGL (INCLUDES ETHANE)

Southwest PA – Wet Marcellus Well Projection

40

• EUR – 978 Mbbls & 6.4 BCF

(12.3 Bcfe)

• 4,200 foot lateral length

• 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 Projected Development Mode Economics

Southwestern PA – (dry gas)

EUR – 13.4 Bcf

Drill and Complete Capital $6.6 MM

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

Gas Price, $/Mmbtu NYMEX

IRR

Includes gathering, pipeline and processing costs

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

Reserves and economics based on

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

Fee

t

Horizontal Length

5

10

15

20

25

30

2013 2014 2015

Sta

ge

s

Average Number of Stages

1.0

1.2

1.4

1.6

1.8

2.0

2.2

2.4

2.6

2.8

2013 2014 2015

EU

R (

Bcf)

/1,0

00

ft.

EUR per 1,000 ft.

0

2

4

6

8

10

12

14

16

2013 2014 2015

EU

R (

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

• 5,200 foot lateral length

• 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

Mc

fed

/1,0

00

ft.

500 ft Wells 1,000 ft Wells

Year 1 Year 3 Year 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

57 57

Midcontinent

Section

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%

Includes gathering, pipeline and processing costs

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

Bb

ls/d

ay

M

mc

f/d

ay

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 (

$ M

illio

ns

) 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 WeightedAverage (1)

BB Index 7 to 10 YearMaturity Index

E&P Index

Yie

ld t

o W

ors

t

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

BB / Ba2 Peer Average for 2012

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

Mm

cfe

/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

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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

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

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