425
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.