Company Presentation

June 27, 2016

FILED BY RANGE RESOURCES CORPORATION PURSUANT TO RULE 425

UNDER THE SECURITIES ACT OF 1933 AND DEEMED FILED PURSUANT TO

RULE 14a-12 UNDER THE SECURITIES EXCHANGE ACT OF 1934

REGISTRATION NO. 333-211994

SUBJECT

COMPANY: MEMORIAL RESOURCE DEVELOPMENT CORP.

FILE NO. 001-36490

2

Forward-Looking Statements

This communication contains certain “forward-looking statements” within the meaning of federal securities laws, including within the meaning of the safe harbor provisions of the Private

Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s and MRD’s current beliefs, expectations or intentions regarding future events.  Words

such as “may,” “will,” “could,” “should,” “expect,” ““plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar

expressions are intended to identify such forward-looking statements. The statements in this press release that are not historical statements, including statements regarding the expected

timetable for completing the proposed transaction, benefits and synergies of the proposed transaction, costs and other anticipated financial impacts of the proposed transaction; the

combined company’s plans, objectives, future opportunities for the combined company and products, future financial performance and operating results and any other statements

regarding Range’s and MRD’s future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts, are forward-

looking statements within the meaning of the federal securities laws.  

Furthermore, the statements relating to the proposed transaction are subject to numerous risks and uncertainties, many of which are beyond Range’s or MRD’s control, which could

cause actual results to differ materially from the results expressed or implied by the statements.  These risks and uncertainties include, but are not limited to: failure to obtain the required

votes of Range’s or MRD’s shareholders; the timing to consummate the proposed transaction; satisfaction of the conditions to closing of the proposed transaction may not be satisfied or

that the closing of the proposed transaction otherwise does not occur; the risk that a regulatory approval that may be required for the proposed transaction is not obtained or is obtained

subject to conditions that are not anticipated; the diversion of management time on transaction-related issues; the ultimate timing, outcome and results of integrating the operations of

Range and MRD; the effects of the business combination of Range and MRD, including the combined company’s future financial condition, results of operations, strategy and plans;

potential adverse reactions or changes to business relationships resulting from the announcement or completion of the proposed transaction; expected synergies and other benefits from

the proposed transaction and the ability of Range to realize such synergies and other benefits; expectations regarding regulatory approval of the transaction; results of litigation,

settlements and investigations; and actions by third parties, including governmental agencies; changes in the demand for or price of oil and/or natural gas can be significantly impacted

by weakness in the worldwide economy; consequences of audits and investigations by government agencies and legislative bodies and related publicity and potential adverse

proceedings by such agencies; compliance with environmental laws; changes in government regulations and regulatory requirements, particularly those related to oil and natural gas

exploration; compliance with laws related to income taxes and assumptions regarding the generation of future taxable income; weather-related issues; changes in capital spending by

customers; delays or failures by

customers to make payments owed to us; impairment of oil and natural gas properties; structural changes in the oil and natural gas industry; and

maintaining a highly skilled workforce.   

Range’s and MRD’s respective reports on Form 10-K for the year ended December 31, 2015, Form 10-Q for the quarter ended March 31, 2016, recent Current Reports on Form 8-K, and

other SEC filings discuss some of the important risk factors identified that may affect these factors and Range’s and MRD’s respective business, results of operations and financial

condition.  Range and MRD undertake no obligation to revise or update publicly any forward-looking statements for any reason. Readers are cautioned not to place undue reliance on

these forward-looking statements that speak only as of the date hereof.

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,” “unrisked

resource potential,” "unproved resource potential" or "upside" 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 actually being 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 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 ultimate 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 and completion services and equipment, lease expirations,

transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion 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 on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.

3

Range’s Keys for Success

•

High quality, large scale acreage position containing repeatable

projects with good returns improving further as costs are reduced

•

Low cost structure with ability to continue driving costs down

•

Improving capital efficiency

•

New takeaway capacity projected to improve realizations for natural

gas, NGLs and condensate

•

Shallow base decline rate, 19% in 1

st

year, allows a minimal level of

capex to hold production flat, ~$300 million for 2017

•

Low-cost takeaway capacity with built-in flexibility

•

Strong 2016 hedges and ample liquidity with no near-term debt

maturities

4

Driving Down Unit Costs

2011

2012

2013

2014

2015

2016E

DD&A

$1.69

$1.62

$1.44

$1.30

$1.14

$0.96

(2)

LOE

(1)

$0.60

$0.41

$0.36

$0.35

$0.26

$0.23

Prod. Taxes

$0.14

$0.15

$0.13

$0.10

$0.07

$0.06

G&A

(1)

$0.56

$0.46

$0.42

$0.35

$0.27

$0.24

Interest

$0.69

$0.61

$0.51

$0.40

$0.33

$0.29

Trans. &

Gathering

$0.62

$0.70

$0.75

$0.76

$0.78

Total

$4.30

$3.95

$3.61

$3.26

$2.85

$2.58

$0.00

(1)

Excludes non-cash stock compensation

(2)

1Q 2016 DD&A was $0.96

(3)

Includes additional NGL & natural gas firm transport agreements.  Propane transport costs were previously netted against NGL revenue. 

Incremental natural gas & NGL revenue, including additional ethane production, will more than offset the 2016 increase in transport expense

(4)   Expected improvement in differentials as a result of additional transportation capacity

($0.25)

(4)

$1.05

(3)

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

5

Near-Term Price Enhancements

•

Range will be able to utilize a full year of

Spectra’s Uniontown to Gas City project, which

takes ~200 Mmcf per day of Range gas

production from local Appalachia M2 to

Midwest markets

•

Additional takeaway projects could strengthen

local pricing differentials

•

Range is the only producer with capacity on

the Mariner East project to Marcus Hook

•

20,000 barrels per day of ethane

transportation to fulfill contract with

INEOS

•

20,000 barrels per day of propane

transportation with access to

international propane markets

•

Range initiated a new marketing arrangement

in 3Q15 which improved Marcellus

condensate net realized prices

Natural Gas Differential

Natural Gas Differential

NGL (Natural Gas Liquids) Differential

NGL (Natural Gas Liquids) Differential

Condensate Differential

Condensate Differential

$0.00

Midpoint

Midpoint

Midpoint

$(0.62)

$(0.42)

$(0.70)

$(0.60)

$(0.50)

$(0.40)

$(0.30)

$(0.20)

$(0.10)

2015

2016E

RRC Marcellus NG Differential to NYMEX

18%

24%

0%

5%

10%

15%

20%

25%

30%

2015

2016E

RRC Corporate NGL Price as % of WTI

$(14.93)

$(13.50)

$(15.50)

$(15.00)

$(14.50)

$(14.00)

$(13.50)

$(13.00)

$(12.50)

2015

2016E

RRC Corporate Condensate Differential to WTI

6

Mariner East:  Opening New Lanes

First

Ethane

Shipments

–

Faster

Propane

Loading

Combined

with

VLGC

Ships

A ship waits in the harbor as another ship is being loaded.

•

Range is the only producer with

current capacity on Mariner East

•

Historic first shipments of ethane from

U.S. to Europe

•

Optionality of selling propane

internationally or in local markets

•

Expect uplift in ethane and propane

realizations in 2016 for Range

Ethane loading in progress

7

First VLGC Loading of Range Propane for Export

8

Regional Direction

Projected

Avg. 2016

Projected

Avg. 2017

Mmbtu/day

Transport

Cost

per Mmbtu

Mmbtu/day

Transport

Cost

per Mmbtu

Firm Transportation

Appalachia/Local

390,000

$  0.20

325,000

$  0.21

Gulf Coast

295,000

$  0.30

510,000

$  0.31

Midwest/Canada

285,000

$  0.28

330,000

$  0.30

Northeast

210,000

$  0.59

210,000

$  0.59

Total Gross Takeaway

Capacity

1,180,000

$  0.31

1,375,000

$  0.35

Total Net Takeaway

Capacity

980,000

$  0.31

1,140,000

$  0.35

Estimated Marcellus Differential

to NYMEX

($0.40)

–

($0.45)

($0.25)

–

($0.35)

Appalachia Gas Transportation Arrangements

Transportation Portfolio additions improve Range’s differentials to NYMEX

Does

not

include

current

intermediary

pipeline

capacity

(gathering)

of

>650,000

Mmbtu/day

and

assumes

full

utilization.

Based

on

pipeline operator’s anticipated project start dates.

(1) Based on expected utilization of capacity and forward pricing with differentials as of April 2016

(1)

9

Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA

Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green.  GIP –

Range estimates.

When

GIP

analysis

from

the

Marcellus,

Upper

Devonian

and

Point

Pleasant

are

combined,

the

largest

stacked

pay

resource

is

located

in

SW

PA

where

Range

has

concentrated

its

acreage

position

10

SW/NE Pennsylvania Stacked Pays

Upper Devonian

335,000

180,000

515,000

335,000

290,000

625,000

-

400,000

400,000

670,000                 870,000          1,540,000

Marcellus

Utica/Point

Pleasant

Wet

Acreage

Dry

Acreage

Total

Net

Acreage

(1)

(1)  Excludes Northwest PA -

280,000 net acres, largely HBP

Stacked pays allow for multiple development opportunities

11

Over 180 Existing Pads Facilitate Future Development

•

124 pads with 5 or fewer

wells, 59 pads with 6 to 9

wells

•

Most pads designed to

accommodate ~20 wells

with the flexibility to drill

Marcellus, Utica/Point

Pleasant or Upper

Devonian formations

•

Significant time and cost

savings are realized

minimal permitting

required

reuse of existing

roads, surface

facilities and

gathering system

12

Range Marcellus –

2016 Well Economic Summary

See appendix for complete assumptions and data on each area

SW Super-Rich

SW Wet

SW Dry

NE Dry

EUR

16.0 Bcfe

1,450 Mbbls & 7.3 Bcf

20.6 Bcfe

1,756 Mbbls & 10.1 Bcf

17.6 Bcf

14.1 Bcf

EUR/1,000 ft. lateral

2.4 Bcfe

3.0 Bcfe

2.5 Bcf

2.5 Bcf

EUR/stage

485 Mmcfe

589 Mmcfe

503 Mmcf

504 Mmcf

Well Cost

$5.9 MM

$5.8 MM

$5.2 MM

$2.9 MM

Cost/1,000

ft.

lateral

$881 K

$832 K

$743 K

$518 K

Stages

33

35

35

28

Lateral Length

6,660 ft.

6,970 ft.

7,000 ft.

5,660 ft.

IRR -

$3.00

26%

25%

54%

58%

Industry leading EUR/1,000 ft. and Cost/1,000 ft. in SW Appalachia

13

Appalachian Peers Well Cost Comparison

Average

Well Cost*

Average

Lateral Length

Cost

per

1,000 ft.

($000’s)

(feet)

(per 1,000

feet)

Range

$5,630

6,876

$819 K

Peer A

6,300

7,000

900

Peer B

8,500

9,000

944

Peer C

6,700

7,000

957

Peer D

7,350

7,500

980

Peer E

7,100

7,700

925

Peer Average

$7,195

7,640

$942 K

Peer group includes AR, COG, EQT, RICE, SWN.  Peer data comes from most recent presentations.

*  Costs should include surface facilities.

14

Unhedged Recycle Ratio

Assumed 2017 Natural Gas price*:

~$3.00

Less: 2016 Expected Corp. differential

$0.42

2016 Expected All-in cash unit costs

$1.87

Adjusted Margin

~$0.71

Expected future development

Cost for PUD reserves

$0.40

Unhedged Recycle Ratio

1.8

Recycle Ratio: (Margin divided by F&D)

* Natural gas strip price as of 4/27/16

15

Liquidity and Leverage Outlook (Range pre-merger)

•

At March 31, 2016, Range had $1.7 billion liquidity under bank commitments, which is

currently

limited

to

$1.2

billion

by

senior

subordinated

note

indentures

•

$3 billion borrowing base and $2 billion commitment amount under $4 billion credit

facility unanimously reaffirmed by bank group, next scheduled redetermination by

May 1, 2017

•

No

note

maturities

until

2021

•

Bank

facility

subject

to

renewal

in

2019,

with

annual

redeterminations

•

Bradford County non-operated interest sold 3/28/16 for $110 million of proceeds

•

Signed agreement to sell 9,200 acres in the STACK play for ~$77 million

•

Solid, stable coverage on debt covenants

•

EBITDAX

to

interest

–

minimum

of

2.5x

(1Q

Actual

4.8x)

•

PV9

proved

reserves

value

to

debt

–

minimum

of

1.5x

(1Q

Actual

2.4x)

•

Hedges on 80% of 2016 production at ~$3.24

16

Range’s Keys for Success

–

Assets, Team, Agreements & Strategy

Low cost structure with

ability to continue driving

costs lower

•

High-grading asset sales

lowered operating costs

•

Lower debt balances reduce

interest expense

•

Headcount reduced by 31% YoY

Improving capital

efficiency

•

Longer laterals; 2016 plan

average ~7,000’, 2017 plan est.

to average ~8,000’

•

Improved targeting and

completions

•

Existing pad locations with

facilities and gathering

•

2017 maintenance capex

estimated at ~$300 million

Better realizations from

additional takeaway

capacity and sales

agreements

•

Unique marketing arrangements

coming on line

•

Ability to reach premium markets

and deliver products outside

Marcellus, including international

exports

Low-cost takeaway

capacity with built-in

flexibility

•

First-mover advantage allowed

Range to secure capacity on

low-cost expansion projects

•

Anticipated excess infrastructure

build-out and avoided

contracting for excessive firm

transport

Strong 2016 hedges and

ample liquidity

•

Approximately 80% hedged on

natural gas at ~$3.24 Mmbtu

•

At 3/31/16, only $31 million

drawn on $2 billion credit facility

•

2016 program expected to use

cash flow and asset sales,

preserving liquidity

High quality, large scale

acreage position

containing repeatable

projects with good

returns

•

Optionality and flexibility due to

quality of acreage position,

gathering system, available

locations on existing pads

•

Further improvements expected

17

Range Resources/Memorial Resource

Development Proposed Merger

Announced May 16, 2016

Closing

expected

late

3

rd

Qtr.

/

early

4

th

Qtr.

2016

18

Highlights of Merger

Core acreage positions in two of the most prolific high-

quality natural gas plays in North America

Immediately cash flow accretive and credit enhancing

Combination of two low-cost gas producers with

opportunities to drive costs lower, improve returns and

increase cash flow

Complementary assets positioned near expanding natural

gas and NGL demand centers

19

Transaction Details

Consideration

•

Range Resources (“Range”) merges with Memorial Resource

Development (“MRD”) for 0.375 shares of Range per MRD share;

All-stock transaction

•

Implied value of $15.75 per MRD share, a 17% premium based on

closing prices as of May 13, 2016

Pro Forma

Ownership and

Corporate

Governance

•

MRD shareholders will own ~31% of the combined company

•

MRD will have the right to nominate an independent director to a

seat on Range’s Board

•

Combined company will be led by current Range senior

management team

Key Conditions

and Timing

•

Range shareholder approval and MRD shareholder approval

•

Customary regulatory approvals

•

Closing

expected

late

3

rd

quarter

or

early

4

th

quarter

of

2016

20

Immediately Accretive & Credit Enhancing

Annual Consensus

Metrics

*

Existing RRC

Pro

Forma

RRC

% Change

•

2016E Production

520 Bcfe

670 Bcfe

+29%

•

2016E Production per day

1,420 Mmcfe

1,830 Mmcfe

+29%

•

2016E Cash Flow

$375 Million

$780 Million

+108%

•

2016E Cash Flow per share

$2.24

$3.20

+43%

•

2016E Cash Margin per Mcfe

$0.72

$1.17

+62%

•

YE 2016E Debt to EBITDAX

4.8x

3.5x

+27%

•

YE 2016E Debt to Cap

50%

37%

+26%

* Using 5/13/16 Consensus estimates

Significant Enhancement to both

Cash Flow Per Share and Credit Metrics

21

Marketing and Operational Efficiencies

Marketing

•

MRD’s position gives Range a

presence in the Gulf Coast in advance

of additional transportation availability

out of Appalachia

•

Opportunities to optimize Range’s

transportation portfolio

•

Creates an expanding and improved

Range customer base in or near

multiple demand areas

Operational

•

Modified drilling and targeting

techniques

•

Capital cost reductions through

leveraging service provider

relationships and reducing drilling or

completion times

•

Overhead efficiencies

Marcellus

Terryville

Existing infrastructure connects

the two acreage positions

22

Appendix

23

Sustained Growth with Improving Capital Efficiency

* 2016 production estimated at midpoint of guidance with capital budget of $495 million

$ Capex per incremental mcfe Production

Production (Mmcfepd)

Range has one of the most capital efficient spending programs in the sector

1,500

1,250

1,000

750

500

250

0

2011

2012

2013

2014

2015

2016E*

$30

$25

$20

$15

$10

$5

$-

24

Cost & Efficiency Improvements –

SW

Pennsylvania

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2012

2013

2014

2015

2016 E

Average Lateral Length

'

'

'

'

'

'

'

'

$-

$500

$1,000

$1,500

$2,000

$2,500

2012

2013

2014

2015

2016 E

Well Cost / Lateral Length

$-

$200

$400

$600

$800

$1,000

$1,200

2012

2013

2014

2015

2016 E

Drilling Cost / Lateral Length

(includes vertical)

$-

$200

$400

$600

$800

$1,000

$1,200

$1,400

2012

2013

2014

2015

2016 E

Completion Cost / Lateral Length

25

Source –

Bentek, Jefferies as of April 2016

Monthly

Y/Y

%

Growth

–

Total

US

Dry

Gas

U.S. Natural Gas Production Growth has Slowed Considerably

December 2015 marked the first Y/Y supply decrease since February 2010

December 2015 marked the first Y/Y supply decrease since February 2010

12.0%

10.0%

8.0%

6.0%

4.0%

2.0%

0.0%

-2.0%

26

Track Record of Impressive Reserve Replacement at Low Cost

(1)

Includes performance and price revisions, excludes SEC required PUD removal due to 5-year rule

(2)

From all sources, including price, performance and SEC required PUD removal due to 5-year rule

(3)

Percentages shown are compounded annual growth rate

2011

2012

2013

2014

2015

3-Year

Average

5-Year

Average

Reserve Replacement

All sources –

excluding PUD removals

(1)

849%

680%

745%

793%

436%

638%

669%

All sources

(2)

849%

680%

636%

649%

207%

469%

546%

Finding Costs

Drill bit only –

without acreage

(1)

$0.76

$0.76

$0.47

$0.44

$0.37

$0.43

$0.53

Drill bit only –

with acreage

(1)

$0.89

$0.86

$0.52

$0.51

$0.40

$0.48

$0.60

All sources –

excluding PUD removals

(2)

$0.89

$0.86

$0.52

$0.54

$0.40

$0.50

$0.61

All sources

(2)

$0.89

$0.76

$0.61

$0.67

$0.84

$0.68

$0.75

26

27

$0.00

$0.25

$0.50

$0.75

$1.00

$1.25

$1.50

$1.75

$2.00

$2.25

$2.50

Range

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Adds + perform + price rev into D & C

Adds + all adjustments into total cost

Peers included –

Antero, Cabot, Consol, EQT, Gulfport, Rice & Southwestern

N

e

g

a

t

i

v

e

A

d

d

i

t

i

o

n

s

N

e

g

a

t

i

v

e

A

d

d

i

t

i

o

n

s

N

e

g

a

t

i

v

e

A

d

d

i

t

i

o

n

s

N

e

g

a

t

i

v

e

A

d

d

i

t

i

o

n

s

Appalachia Producer’s 2015 F & D Costs

Core Acreage Has Big Impact on Value of Reserves

28

Range: Low-Cost, Large Scale

Source: Wood Mackenzie –

February 2016

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

5.50

0

20

40

60

80

100

120

140

160

Remaining net risked resource (tcfe)

Range - Southwest Rich

EQT - Southwest Rich

EQT - WV Rich

Southwestern - Rich Gas Core

CONSOL - Southwest Rich

Noble - Southwest Rich

Rice - Greene

Antero - WV Rich

Range - Pittsburgh

Rex - Pittsburgh

Magnum Hunter - WV Rich

CONSOL - Allegheny Mountains

Noble - Allegheny Mountains

Range - Rich Gas Core

Range - Greene

Chevron - Greene

ExxonMobil - Pittsburgh

Antero - WV Dry

EXCO - Pittsburgh

CONSOL - Rich Gas Core

CONSOL - WV Rich

Rice - Southwest Rich

AEP - WV Rich

EQT - WV Dry

Chevron - Rich Gas Core

Southwestern - WV Rich

CONSOL - WV Dry

Chevron - Allegheny Mountains

ExxonMobil - WV Dry

EQT - Allegheny Mountains

Noble - WV Rich

Southwestern - WV Dry

Noble - WV Dry

Chevron - Pittsburgh

Wood Mackenzie 2016 Henry

Hub price forecast

(US$2.60/mcf)

140 tcfe in the Southwest

Marcellus alone…

Range has lowest breakeven price in the SW

Marcellus per Wood Mackenzie

Range has lowest breakeven price in the SW

Marcellus per Wood Mackenzie

29

SW PA Super-Rich Area Marcellus Projected 2016 Well Economics

•

Southwestern

PA

–

(High

Btu

case)

•

110,000 Net Acres

•

EUR

/

1,000

ft.

–

2.40

Bcfe

•

EUR –

16.0 Bcfe

(226 Mbbls condensate, 1,224 Mbbls NGLs & 7.3 Bcf gas)

•

Drill

and

Complete

Capital

–

$5.87

MM                

($881 K per 1,000 ft.)

•

Average

Lateral

Length

–

6,660

ft.

•

F&D –

$0.44/mcfe

NYMEX

Gas Price

ROR

Strip   -

22%

$3.00  -

26%

Estimated

Cumulative Recovery

for 2016 Production Forecast

Condensate

(Mbbls)

Residue

(Mmcf)

NGL w/

Ethane

(Mbbls)

1 Year

48

661

111

2 Years

73

1,142

192

3 Years

92

1,555

261

5 Years

120

2,246

378

10 Years

161

3,517

591

20 Years

195

5,157

867

EUR

226

7,279

1,224

•

Price includes current and expected

differentials less gathering,

transportation and processing costs

•

For flat pricing, oil price assumed to

be $40/bbl for 2016, $50/bbl for 2017

then $65/bbl to life with no

escalation

•

NGL is average price including

ethane with escalation

•

Ethane price tied to ethane contracts

plus same comparable escalation

•

Strip dated 12/31/15 with 10-year

average $52.14/bbl and $3.25/mcf

30

Southwest PA -

Super-Rich Area 2016 Turn in Line Forecast

Improvements Between Years

EUR

(Bcfe)

Well Costs

($ MM)

Lateral

Lengths (ft.)

2015 Type Curve -

TIL

12.9

$5.9

5,367

2016 Type Curve -

TIL

16.0

$5.9

6,660

System designed to maximize project economics

31

Southwest PA –

Super-Rich Marcellus

All comparisons based on Turned in Line (TIL) wells for each year

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

7,000

2014

2015

2016

Horizontal Length (TIL)

5

10

15

20

25

30

35

2014

2015

2016

Average Number of Stages

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2014

2015

2016

EUR per 1,000 ft.

0.0

5.0

10.0

15.0

20.0

2014

2015

2016

EUR by Year

Gas

NGLs

Condensate

32

SW PA Wet Area Marcellus Projected 2016 Well Economics

•

Southwestern PA –

(Wet Gas case)

•

225,000 Net Acres

•

EUR / 1,000 ft. –

2.95 Bcfe

•

EUR –

20.6 Bcfe

(56 Mbbls

condensate, 1,700 Mbbls

NGLs & 10.1 Bcf

gas)

•

Drill and Complete Capital –

$5.8 MM             

($832 K per 1,000 ft.)

•

Lateral Length –

6,970 ft.

•

F&D –

$0.34/mcfe

•

Price includes current and expected

differentials less gathering,

transportation and processing costs

•

For flat pricing, oil price assumed to

be $40/bbl for 2016, $50/bbl for 2017

then $65/bbl to life with no

escalation

•

NGL is average price including

ethane with escalation

•

Ethane price tied to ethane contracts

plus same comparable escalation

•

Strip dated 12/31/15 with 10-year

average $52.14/bbl and $3.25/mcf

NYMEX

Gas Price

ROR

Strip   -

20%

$3.00  -

25%

Estimated

Cumulative Recovery

for 2016 Production Forecast

Condensate

(Mbbls)

Residue

(Mmcf)

NGL w/

Ethane

(Mbbls)

1 Year

20

1,211

204

2 Years

30

2,014

339

3 Years

36

2,665

449

5 Years

44

3,694

622

10 Years

51

5,470

921

20 Years

55

7,654

1,289

EUR

56

10,100

1,700

33

Southwest PA -

Wet Area 2016 Turn in Line Forecast

Improvements Between Years

EUR

(Bcfe)

Well Costs

($ MM)

Lateral

Lengths (ft.)

2015 Type Curve

-

TIL

17.6

$5.9

5,955

2016 Type Curve -

TIL

20.6

$5.8

6,970

System designed to maximize project economics

34

Southwest PA –

Wet Marcellus

34

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2014

2015

2016

Horizontal Length (TIL)

5

10

15

20

25

30

35

40

2014

2015

2016

Average Number of Stages

1.0

1.5

2.0

2.5

3.0

3.5

2014

2015

2016

EUR per 1,000 ft.

0.0

5.0

10.0

15.0

20.0

25.0

2014

2015

2016

EUR by Year

Gas

NGLs

Condensate

All comparisons based on Turned in Line (TIL) wells for each year

35

•

Southwestern PA –

(Dry Gas case)

•

180,000 Net Acres

•

EUR / 1,000 ft. –

2.52 Bcf

•

EUR –

17.6 Bcf

•

Drill and Complete Capital $5.2 MM                   

($743 K per 1,000 ft.)

•

Average Lateral Length –

7,000 ft.

•

F&D –

$0.36/mcf

NYMEX

Gas Price

ROR

Strip   -

41%

$3.00  -

54%

Estimated

Cumulative Recovery

for 2016 Production Forecast

Residue

(Mmcf)

1 Year

3,039

2 Years

4,674

3 Years

5,866

5 Years

7,609

10 Years

10,392

20 Years

13,633

EUR

17,641

•

Price includes current and

expected differentials less

gathering and transportation

costs

•

Strip dated 12/31/15 with 10-year

average $52.14/bbl and $3.25/mcf

SW PA Dry Area Marcellus Projected 2016 Well Economics

Based on Washington County well data

36

SW PA–

Dry  Area 2016 Turn in Line Forecast

Improvements Between Years

EUR

(Bcf)

Well Costs

($ MM)

Lateral

Lengths (ft.)

2015 Type Curve -

TIL

17.1

$6.0

6,798

2016 Type

Curve -

TIL

17.6

$5.2

7,000

System designed to maximize project economics

Based on Washington County well data

37

Southwest PA–

Dry Marcellus

37

Based on Washington County well data

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2014

2015

2016

Horizontal Length (TIL)

5

10

15

20

25

30

35

40

2014

2015

2016

Average Number of Stages

1.0

1.5

2.0

2.5

3.0

2014

2015

2016

EUR per 1,000 ft.

0.0

5.0

10.0

15.0

20.0

2014

2015

2016

EUR by Year

All comparisons based on Turned in Line (TIL) wells for each year

38

Utica Wells –

Wellhead Pressure vs. Cumulative Production

Early Time Production Data (Including Flowback/Test Data)

Normalized Gas Cum (Mcf/1000 ft.)

RRC DMC Properties well one of the best in the Utica

~25 Mmcfd

~30 Mmcfd

~18 Mmcfd

~12 Mmcfd

~20 Mmcfd

*TVD (total vertical depth) With an average pressure gradient of .85 to .95

for these wells, greater TVD equals higher cost and higher pressure

13,200’ TVD*

13,400’ TVD*

11,850’ TVD*

9,206’ TVD*

39

Utica/Point Pleasant Update

•

1

st

well

estimated

to

have

15

Bcf

EUR, or 2.8 Bcf per 1,000 lateral

foot

•

2

nd

well

completed

with

higher

sand concentration and brought

online in Q3 2015 with choke

management at 13 Mmcf per day

•

2

nd

well

EUR

appears

to

be

greater than the first well

•

3

rd

well

appears

to

be

one

of

the

best dry gas Utica wells in the

basin

•

400,000 net acres in SW PA

prospective

Note: Townships where Range holds ~2,000+ or more acres are

shown outlined above (as January 2016)

40

Cost & Efficiency Improvements –

Northern Marcellus

'

'

'

'

'

'

'

'

'

Normalized Production Results of Marcellus Tighter Spacing Projects

•

Tighter spaced wells turned to sales in 2009 and 2010

•

Average lateral length of these wells is 2,861 feet

•

Well performance not reflective of improved targeting and

completion designs

•

500 foot spaced wells produced 77% of 1,000 foot spaced wells

through the life of the current production

•

Tighter spaced wells turned to sales in 2009 and 2010

•

Average lateral length of these wells is 2,861 feet

•

Well performance not reflective of improved targeting and

completion designs

•

500 foot spaced wells produced 77% of 1,000 foot spaced wells

through the life of the current production

41

Targeting/Down Spacing Test Results Encouraging

•

Optimized targeting

shows a ~53% increase in

cumulative production

after 600 days

•

Normalized well costs

were $850,000 less than

original wells

•

No detrimental

production impact seen

on the original wells

Represents New Optimized

Completion Method

42

43

43

Returning to Existing Pads –

SW Wet

Avg EUR/1000 ft.: 3.6+ Bcfe

•

Ability to target our best areas with 3.6+ Bcfe/1,000 ft.

•

New wells have EURs 22% higher than the average wet well

•

Significant cost savings

Drilled

wells -

2015

Future

Locations

Additional 5 wells

Drilled

wells -

2010

44

44

Returning to Existing Pads –

SW Dry

Additional 3 wells

Avg EUR/1000 ft.: 3.0+ Bcfe

•

Ability to target our best areas with 3.0+ Bcfe/1,000 ft.

•

New wells have EURs 20% higher than the average dry well

•

Significant cost savings

Drilled

wells -

2015

Drilled

wells -

2014

Future

Locations

45

Gas In Place (GIP) –

Marcellus Shale

Note: Townships where Range holds ~2,000+ acres (as of January 2016) 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 been

developed in the Marcellus

•

Condensate and NGLs are in

gaseous form in the reservoir

46

Gas In Place (GIP) –

Point Pleasant

Bold, outlined portion represents

the area of the highest pressure

gradients in the Point Pleasant

Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green.  GIP –

Range estimates.

47

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

Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green.  GIP –

Range estimates.

48

Macro Section

49

Significant

Natural

Gas

Demand

Growth

Projected

–

Beginning

in

2016

LONG TERM US NATURAL GAS DEMAND ROADMAP  (BCF/D)

2016

2017

2018

2019

2020

Cumulative

2015-2020

LNG Exports

Sabine Pass

1.2

1.2

0.7

3.1

Freeport

0.5

1.0

1.5

Cove Point

0.8

0.8

Cameron

1.2

0.6

1.8

Corpus Christi

0.8

0.8

1.6

LNG Sub-Total

1.2

1.6

2.6

3.1

0.8

8.9

Mexico/Canada Exports

Mexico Net Exports

0.5

0.3

0.3

0.3

0.4

1.8

1.8

Canada net Exports

0.1

0.1

0.1

0.1

0.1

0.5

Mexico/Canada

Sub-Total

0.6

0.4

0.4

0.4

0.5

2.3

Power Generation

Coal Plant Retirements

0.4

0.3

0.1

0.0

0.3

1.1

Nuclear Retirements

-

-

01.1

0.1

0.2

0.4

Incremental Electricity Demand

0.1

0.1

0.1

2.0

2.0

4.3

Power Generation Sub-Total

0.5

0.4

0.4

0.3

0.7

2.

2.3

Industrial

Methanol

0.3

0

0

0

0

0.4

Ethylene

0

0.4

0.1

-

0.1

0.6

Ammonia

0.5

0.1

0.2

0.1

0.1

1.0

Industrial Sub-Total

0.8

0.4

0.3

0.1

0.2

2.0

Transportation

New Fueling Opportunities

-

-

0.1

0.1

0.1

0.3

Transportation Sub-Total

-

-

0.1

0.1

0.1

0.3

2016

2017

2018

2019

2020

2020

Total

3.1

2.5

3.7

4.0

2.2

15.8

Research report dated 04/08/2016

50

U.S. LNG Exports Expected to be ~8 Bcf/day by 2020 –

per TPH

Research report dated 10/08/2015

51

U.S. Natural Gas Exports to Mexico

Source –

PointLogic, Bloomberg

Mexico exports have recently been larger than

forecast, with the trend expected to continue

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

Jan-07

Jan-08

Jan-09

Jan-10

Jan-11

Jan-12

Jan-13

Jan-14

Jan-15

52

U.S. Domestic Oil Production Appears to Have Peaked

•

7 major regions account for 95% of domestic oil production growth

•

Production

appears

to

have

peaked

in

2

nd

Qtr.

2015

•

Significant reduction in capital spending in the 7 regions would suggest the

trend will continue

•

Associated gas estimated to be 8 Bcf per day from growth in oil production.

Declines in oil production are also impacting associated gas.

April

EIA

data

for

the

7

Major

Growth

Producing

Regions

–

Marcellus,

Eagle

Ford,

Permian,

Haynesville,

Niobrara,

Utica

&

Bakken

3,000

3,500

4,000

4,500

5,000

5,500

6,000

Jan-13

Apr-13

Jul-13

Oct-13

Jan-14

Apr-14

Jul-14

Oct-14

Jan-15

Apr-15

Jul-15

Oct-15

Jan-16

53

Associated Gas Production

Source –

Bentek, Jefferies as of April 2016

Monthly Y/Y % Growth –

Associated US Dry Gas

Gas production from ‘oil plays’  expected to continue

declining in 2016 due to a lack of drilling within these plays

-

10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

54

Source –

Bentek, EIA

Non-Appalachian Gas Basins

Growth by Area

Year over Year % Growth

-

8%

-6%

-4%

-

2%

0%

2%

4%

55

Appalachian Pipeline Flow Data by Region (Mcf/d)

Source –

RS Energy Group, raw data from Ventyx Velocity Suite and Bloomberg, as of 4/19/2016

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

10,000,000

Jan-10

Jan-11

Jan-12

Jan-13

Jan-14

Jan-15

Jan-16

NE PA

SW PA

WV

Utica

56

Source –

Bentek, EIA

Total U.S. Natural Gas Production

Growth by Area

Year over Year % Growth

-

4%

0%

4%

8%

12%

Total Gas

57

•

Utica/Point Pleasant

rig count down 86%

from the peak in 2014

•

Marcellus rig count

down 86% from the

2014 peak

Appalachian Rig Counts Declining

Source –

RigData as of 6/3/2016

0

10

20

30

40

50

60

Utica / Point Pleasant Rig Count

0

30

60

90

120

150

Marcellus Rig Count

58

(1)

Based on estimated NGL volumes in 1Q 2016   

(2)

Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus

Marcellus NGL Pricing

Realized Marcellus NGL Prices

2015

2016

1Q

2Q

3Q

4Q

1Q

NYMEX –

WTI

(per bbl)

$48.62

$57.88

$46.61

$42.22

$33.56

Mont Belvieu Weighted

Priced Equivalent

$18.05

$18.32

$17.16

$17.24

$13.60

Plant Fees plus

Diff.

(7.16)

(10.64)

(11.20)

(8.43)

(5.30)

Marcellus average price

before NGL hedges

$10.89

$7.71

$5.96

$8.81

$8.30

% of WTI (NGL Pre-

hedge / Oil NYMEX)

22%

13%

13%

21%

25%

(2)

51%

27%

3%

9%

10%

Weighted Avg.

Composite Barrel

(1)

Ethane C2

Propane C3

Iso Butane iC4

Normal Butane NC4

Natural Gasoline C5+

59

2015

2016

2017

2018

Appalachia Production Year End Exit Rate

20.6

22.0

24.0

26.5

Appalachia Consumption + Injections

14.4

14.4

14.9

15.4

A

Appalachia Gas Surplus for Export

6.2

7.6

9.1

11.1

Takeaway Projects -

Northeast (cumulative)

1.1

1.8

3.1

7.8

Takeaway Projects -

Southwest (cumulative)

3.3

5.9

15.2

20.4

B

Total Takeaway Projects (cumulative)

4.4

7.7

18.3

28.3

Excess Takeaway (B –

A)

(1.8)

0.1

9.2

17.1

Appalachian Production, Consumption & Takeaway -

2015-2018

Source: Analyst estimates

•

LNG exports starting in early 2016

•

Appears to have sufficient takeaway

capacity by 2017

Freely

Flowing

Overbuilt

Summer

Constrained

10

20

30

40

50

North East Consumption

Regional Storage Injections

Announced Takeaway Additions

North East Production

0

60

Northeast

PA

Operator

Main Line

Market

Start-up*

Capacity –

Bcf/d

Fully

Committed

Approved or

with FERC

2015

Niagara Expansion

Kinder Morgan

TGP

Canada

Q4'15

0.2

Y

Y

Northern Access 2015

NFG

National Fuel

Canada

Q4'15

0.1

Y

Y

Leidy Southeast

Williams

Transco

Mid-Atlantic/SE

Q4'15

0.5

Y

Y

East Side Expansion

Nisource

Columbia

Mid-Atlantic/SE

Q4'15

0.3

Y

Y

2016

SoNo Iroquois Access

Dominion

Iroquois

Canada

Q2'16

0.3

N

N

Algonquin AIM

Spectra

Algonquin

NE

Q4'16

0.4

Y

Y

2017

Northern Access 2016

NFG

National Fuel

Canada

H2'17

0.4

Y

Y

Constitution

Williams

Constitution

NE

H2'17

0.7

Y

Y

Atlantic Bridge

Spectra

Algonquin

NE

H2'17

0.7

N

Y

2018

Atlantic Sunrise

Williams

Transco

Mid-Atlantic/SE

H1'18

1.7

Y

Y

Access Northeast

Spectra

Algonquin

NE

H2'18

1.0

N

Y

Diamond East

Williams

Transco

NE

H2'18

1.0

N

N

PennEast

AGT

NE

H2‘18

1.0

Y

Y

Southwest

Operator

Main Line

Market

Start-up

Capacity –

Bcf/d

Fully

Committed

Approved or

with FERC

2015

REX Zone 3 Full Reversal

Tall Grass

REX

Midwest

Q2'15

1.2

Y

Y

TGP Backhaul / Broad Run

Kinder Morgan

TGP

Gulf Coast

Q4'15

0.6

Y

Y

TETCO OPEN

Spectra

TETCO

Gulf Coast

Q4'15

0.6

Y

Y

Uniontown to Gas City

Spectra

TETCO

Midwest

Q3'15

0.4

Y

Y

2016

Gulf Expansion Ph1

Spectra

TETCO

Gulf Coast

Q4'16

0.3

Y

Y

Clarington West Expansion

Tall Grass

REX

Midwest

Q4'16

1.6

N

N

Zone

3 Capacity Enhancement

Tall Grass

REX

Midwest

Q4'16

0.8

Y

Y

Announced Appalachian Basin Takeaway Projects –

1 of 2

Note:  Data subject to change as projects are approved and built.

Highlighted projects where Range is participating.

* Start-up dates reflect announced operator in-service dates

61

Southwest

Operator

Main Line

Market

Start-up*

Capacity –

Bcf/d

Fully

Committed

Approved or

with FERC

2017

Rover Ph1

ETP

Midwest/Canada/

Gulf Coast

Q2'17

1.9

Y

Y

Rayne/Leach Xpress

Nisource

Columbia

Gulf Coast

Q3'17

1.5

Y

Y

SW Louisiana

Kinder Morgan

TGP

Gulf Coast

Q3'17

0.9

Y

Y

Rover Ph2

ETP

Midwest/Canada/

Gulf Coast

Q3'17

1.3

Y

Y

Adair SW

Spectra

TETCO

Gulf Coast

Q4'17

0.2

Y

Y

Access South

Spectra

TETCO

Gulf Coast

Q4'17

0.3

Y

Y

Gulf Expansion Ph2

Spectra

TETCO

Gulf Coast

Q4'17

0.4

Y

Y

NEXUS

Spectra

Midwest/Canada

Q4'17

1.5

Y

Y

ANR Utica

Transcanada

ANR

Midwest/Canada

Q4'17

0.6

N

N

Cove Point LNG

Dominion

NE

Q4'17

0.7

Y

Y

2018

TGP Backhaul / Broad Run Expansion

Kinder Morgan

TGP

Gulf Coast

Q2’18

0.2

Y

Y

Mountain Valley

NextEra/EQT

Mid-Atlantic/SE

Q4'18

2.0

Y

Y

Western Marcellus

Williams

Transco

Mid-Atlantic/SE

Q4'18

1.5

N

N

Atlantic Coast

Duke/Dominion

Mid-Atlantic/SE

Q4'18

1.5

Y

Y

Total NE Appalachia

to Canada

1.0

Total NE Appalachia

to NE

4.4

Total NE Appalachia

to Mid-Atlantic/SE

2.5

Total NE Appalachia

Additions

7.8

Total SW Appalachia to Mid-Atlantic/SE

5.0

Total SW Appalachia to

Midwest/Canada

8.2

Total SW Appalachia to Gulf Coast

6.5

Total SW Appalachia to NE

0.7

Total SW Appalachia Additions

20.4

Overall Total Additions for Appalachian Basin

28.3

Announced

Appalachian

Basin

Takeaway

Projects

–

2

of

2

Note:  Data subject to change as projects are approved and built.

Highlighted projects where Range is participating.

* Start-up dates reflect announced operator in-service dates

(2015 –

2018)

Existing capacity

added by YE 2014

2.8    SW

.6     NE

3.4 Total   

62

What Does the Future’s Strip Price Indicate for Regional Basis?

TCO Pool

2015

-$0.12

2020

-$0.21

Dom South

2015

-$1.21

2020

-$0.53

TETCO M3

2015

-$0.44

2020

$0.00

Chicago CG

2015

$0.15

2020

$0.04

CG Mainline

2015

-$0.07

2020

-$0.05

Dawn

2015

$0.30

2020

-$0.06

MichCon

2015

$0.19

2020

$0.05

Algonquin

2015

$2.24

2020

$1.05

Transco Z6 (NY)

2015

$1.01

2020

+$1.03

Transco Z4

2015

-$0.01

2020

+$0.03

Source = Bloomberg, Inside-FERC Basis (04/22/16)

Prices $/Mmbtu

North East anticipated

takeaway projects should

improve future basis in the

Appalachian Basin

North East anticipated

takeaway projects should

improve future basis in the

Appalachian Basin

Leidy

2015

-$1.57

2020

-$0.71

Transco Z6 (NNY)

2015

$0.51

2020

$0.31

63

Financial Detail

Appendix

64

Range Maintains an Orderly Debt Maturity Ladder

Senior Secured Revolving Credit Facility

Senior Subordinated Notes

Senior Notes

Interest Rate

1.8%

5.75%

5.0%

5.0%

4.875%

$31

Million Drawn

Borrowing Base -

$3 Billion

$31

$500

$600

$750

$750

0

500

1,000

1,500

2,000

2,500

3,000

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Bond Incurrence Limit

-

$1.5 Billion

Bank Commitment

-

$2 Billion

65

Strong, Simple Balance Sheet

YE  2013

YE  2014

Q1  2015

Q2  2015

Q3  2015

Q4 2015

Q1 2016

($ in millions)

Bank borrowings

(1)

$500

$723

$912

$364

$987

$95

$31

Sr. Notes

(1)

750

750

750

750

Sr. Sub. Notes

(1)

2,641

2,350

2,350

2,350

1,850

1,850

1,850

Less: Cash

(0)

(0)

(0)

(0)

(0)

(0)

(0)

Net debt

3,141

3,073

3,262

3,464

3,587

2,695

2,631

Common equity

2,414

3,456

3,490

3,381

3,085

2,760

2,672

Total capitalization

$5,555

$6,529

$6,752

$6,845

$6,672

$5,455

$5,303

Debt-to capitalization

57%

47%

48%

50%

54%

49%

50%

Debt/EBITDAX

2.8x

2.6x

2.9x

3.3x

3.7x

3.0x

3.3x

Liquidity

(2)

$1,166

$1,172

$980

$1,527

$876

$1,267

(3)

$1,238

(3)

(1)

Excludes unamortized debt issuance costs

(2)

Liquidity based on bank commitment amount, which excludes additional liquidity under total borrowing base

(3)

Liquidity limited based on senior subordinated notes indenture provision

Debt at lowest level in past 3 years

June

2014

•Called high cost 8% notes, reducing annual interest expense by $24 million or $0.06 mcfe

•Redemption funded by an equal sized equity offering aimed at accelerating balance sheet

October

2014

•Renewed bank credit agreement with larger facility size, borrowing base, bank group and enhanced flexibility

•Annual borrowing base redeterminations and a 5-year maturity

•Ability to release collateral during transition to investment grade

March

2015

•Unanimous reaffirmation of $3 billion borrowing base and $2 billion commitments

•Elimination of debt-to-ebitdax covenant; replaced with interest coverage test and a forward-looking asset coverage test

•Announced closure of Oklahoma City office, saving approximately $18 million annually in administrative costs

May

2015

•Opportunistically accessed a strong high yield debt market issuing $750 million 10-year notes at 4.875%

•Issued senior notes continuing to lay foundation for an investment grade balance sheet

•Coupon remains the lowest of any high yield energy issuer of any rating year-to-date

August

2015

•Portion of proceeds from 4.875% senior notes offering used to redeem 6.75% senior subordinated notes due 2020

•Reduction in coupon on $500 million principal redeemed of 1.875% amounts to annual interest savings of ~$9.4 million

2016

•Sold Nora field for $876 million on 12/30/15, paying down revolving credit facility

•Bradford county assets sold 3/28/16 for $110 million

•Signed purchase and sale agreement for central Oklahoma assets for $77 million

Early, Continuous Action Taken to Prepare for Low Prices

66

67

Range Bonds Continue to Trade Well

67

Source: Bloomberg as of 6/13/2016

Since December highs, Range bonds tightened significantly and continue to trade well

relative to a group of high quality peer bonds of similar duration

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

Range Resources 4.875% 15-MAY-25

Antero Resources 5.625% 01-JUN-23

Cimarex

4.375% 01-JUN-24

Concho Resources 5.500% 01-APR-23

Continental Resources 3.800% 01-JUN-24

Newfield Exploration 5.625% 01-JUL-24

69

Period

Volumes Hedged

(Mmbtu/day)

Average Floor Price       

($/Mmbtu)

Gas Hedging

2Q 2016 Swaps

3Q 2016 Swaps

4Q 2016 Swaps

760,000

760,000

760,000

$3.21

$3.22

$3.24

2017 Swaps

2018 Swaps

205,000

50,000

$2.83

$2.88

Oil Hedging

2Q 2016 Swaps

3Q 2016 Swaps

4Q 2016 Swaps

6,000

5,750

5,750

$59.21

$58.73

$58.73

2017 Swaps

1,000

$50.13

Gas and Oil Hedging Status

As of 04/25/2016 –

For quarterly detail of hedges, see RRC website

70

Period

Volumes Hedged

(bbls/day)

Hedged

Price

(1)

($/gal)

Ethane (C2)

2H 2016 Swaps

2017 Swaps

500

1,000

$0.22

$0.25

Propane (C3)

2016 Swaps

5,500

$0.60

Normal Butane

(NC4)

2Q 2016 Swaps

2H 2016 Swaps

3,918

4,000

$0.66

$0.66

Natural Gasoline

(C5)

2Q 2016 Swaps

2H 2016 Swaps

2017 Swaps

3,250

3,500

1,000

$1.14

$1.11

$0.92

Natural Gas Liquids Hedging Status

(1) NGL hedges have Mont Belvieu as the underlying index

Conversion Factor:

One barrel = 42 gallons

As of 04/25/2016 –

For quarterly detail of hedges, see RRC website

71

Contact Information

Range Resources Corporation

100 Throckmorton, Suite 1200

Fort Worth, Texas  76102

Laith

Sando,

Vice

President

–

Investor

Relations

(817) 869-4267

lsando@rangeresources.com

David Amend, Investor Relations Manager

(817) 869-4266

damend@rangeresources.com

Michael Freeman, Senior Financial Analyst

(817) 869-4264

mfreeman@rangeresources.com

www.rangeresources.com

72

Important Additional Information

This

communication

does

not

constitute

an

offer

to

buy

or

sell

or

the

solicitation

of

an

offer

to

buy

or

sell

any

securities

or

a

solicitation

of

any

vote

or

approval.

This

communication

relates

to

a

proposed

business

combination

between

Range

and

MRD.

In

connection

with

the

proposed

transaction,

Range

intends

to

file

with

the

SEC

a

registration

statement

on

Form

S-4

that

will

include

a

joint

proxy

statement

of

Range

and

MRD

that

also

constitutes

a

prospectus

of

Range.

Each

of

Range

and

MRD

also

plan

to

file

other

relevant

documents

with

the

SEC

regarding

the

proposed

transactions.

No

offering

of

securities

shall

be

made

except

by

means

of

a

prospectus

meeting

the

requirements

of

Section

10

of

the

U.S.

Securities

Act

of

1933,

as

amended.

Any

definitive

joint

proxy

statement/prospectus(es)

for

Range

and/or

MRD

(if

and

when

available)

will

be

mailed

to

shareholders

of

Range

and/or

MRD,

as

applicable.

INVESTORS

AND

SECURITY

HOLDERS

OF

RANGE

AND

MRD

ARE

URGED

TO

READ

THE

PROXY

STATEMENT(S),

REGISTRATION

STATEMENT(S),

PROXY

STATEMENT/PROSPECTUS

AND

OTHER

DOCUMENTS

THAT

MAY

BE

FILED

WITH

THE

SEC

CAREFULLY

AND

IN

THEIR

ENTIRETY

IF

AND

WHEN

THEY

BECOME

AVAILABLE

BECAUSE

THEY

WILL

CONTAIN

IMPORTANT

INFORMATION.

Investors and security holders will be able to obtain free copies of these documents (if and when available) and other documents

containing important information about Range and MRD, once such documents are filed with the SEC through the website

maintained

by

the

SEC

at

http://www.sec.gov.

Copies

of

the

documents

filed

with

the

SEC

by

Range

will

be

available

free

of

charge

on Range’s internet website at http://www.rangeresources.com

or by contacting Range’s Investor Relations Department by email

at

lsando@rangeresources.com,

damend@rangeresources.com,

mfreeman@rangeresources.com,

or

by

phone

at

817-869-4267.

Copies of the documents filed with the SEC by MRD will be available free of charge on MRD’s internet website at

http://www.memorialrd.com

or by phone at 713-588-8339.

Range,

MRD

and

certain

of

their

respective

directors

and

executive

officers

may

be

deemed

to

be

participants

in

the

solicitation

of

proxies

in

respect

of

the

proposed

transaction.

Information

about

the

directors

and

executive

officers

of

MRD

is

set

forth

in

MRD’s

proxy

statement

for

its

2016

annual

meeting

of

shareholders,

which

was

filed

with

the

SEC

on

April

1,

2016.

Information

about

the

directors

and

executive

officers

of

Range

is

set

forth

in

its

proxy

statement

for

its

2016

annual

meeting

of

shareholders,

which

was

filed

with

the

SEC

on

April

8,

2016.

These

documents

can

be

obtained

free

of

charge

from

the

sources

indicated

above.

Other

information

regarding

the

participants

in

the

proxy

solicitations

and

a

description

of

their

direct

and

indirect

interests,

by

security

holdings

or

otherwise,

will

be

contained

in

the

joint

proxy

statement/prospectus

and

other

relevant

materials

to

be

filed

with

the

SEC

when

such

materials

become

available.

Investors

should

read

the

joint

proxy

statement/prospectus

carefully

when

it

becomes

available

before

making

any

voting

or

investment

decisions.

You

may

obtain

free

copies

of

these

documents

from

Range

or

MRD

using

the

sources

indicated

above.