Rex Energy Investor Presentation May 2015

Rex Energy Corporate Presentation
May 2015

Forward Looking Statements and Presentation of Information
2
Forward-Looking Statements
Statements in this presentation that are not historical facts are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. For example, we make statements about significant potential opportunities for our business; future earnings; resource
potential; cash flow and liquidity; capital expenditures; reserve and production growth; potential drilling locations; plans for our operations, including drilling, fracture stimulation
activities, and the completion of wells; and potential markets for our oil, NGLs, and gas, among other things, that are forward looking and anticipatory in nature. These statements are
based on management’s experience and perception of historical trends, current conditions, and anticipated future developments, as well as other factors believed to be appropriate. We
believe these statements and the assumptions and estimates contained in this presentation are reasonable based on information that is currently available to us. However, management's
assumptions and the company's future performance are subject to a wide range of business risks and uncertainties, both known and unknown, and we cannot assure that the company can
or will meet the goals, expectations, and projections included in this presentation. Any number of factors could cause our actual results to be materially different from those expressed or
implied in our forward looking statements, including (without limitation): economic conditions in the United States and globally; domestic and global demand for oil and natural gas;
volatility in oil, gas, and natural gas liquids pricing; new or changing government regulations, including those relating to environmental matters, permitting, or other aspects of our
operations; the geologic quality of the company’s properties with regard to, among other things, the existence of hydrocarbons in economic quantities; uncertainties inherent in the
estimates of our oil and natural gas reserves; our ability to increase oil and natural gas production and income through exploration and development; drilling and operating risks; the
success of our drilling techniques in both conventional and unconventional reservoirs; the success of the secondary and tertiary recovery methods we utilize or plan to employ in the
future; the number of potential well locations to be drilled, the cost to drill them, and the time frame within which they will be drilled; the ability of contractors to timely and adequately
perform their drilling, construction, well stimulation, completion and production services; the availability of equipment, such as drilling rigs, and infrastructure, such as transportation
pipelines; the effects of adverse weather or other natural disasters on our operations; competition in the oil and gas industry in general, and specifically in our areas of operations;
changes in the company’s drilling plans and related budgets; the success of prospect development and property acquisition; the success of our business and financial strategies, and
hedging strategies; conditions in the domestic and global capital and credit markets and their effect on us; the adequacy and availability of capital resources, credit, and liquidity
including (without limitation) access to additional borrowing capacity; and uncertainties related to the legal and regulatory environment for our industry, and our own legal proceedings
and their outcome.
Further information on the risks and uncertainties that may effect our business is available in the company's filings with the Securities and Exchange Commission. We strongly
encourage you to review those filings. Rex Energy does not assume or undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new
information, future events, or otherwise.
Presentation of Information
The estimates of reserves in this presentation are based on a reserve report of our independent external reserve engineers as of December 31, 2014. We believe the data we prepared and
supplied to our external reservoir engineers in connection with their preparation of the 12/31/14 reserve report, and the assumptions, forecasts, and estimates contained therein, are
reasonable, however, we cannot assure that they will prove to have been correct. Estimates of reserves can be affected by inaccurate assumptions or by known or unknown risks and
uncertainties. Please see slide 3 for additional information about our estimates of reserves.
In this presentation, references to Rex Energy, Rex, REXX, the Company, we, our and us refer to Rex Energy Corporation and its subsidiaries. Unless otherwise noted, all references to
acreage holdings are as of December 31, 2014 and are rounded to the nearest hundred. All financial information excludes discontinued operations unless otherwise noted.
All estimates of internal rate of return (IRR) are before tax.

Forward Looking Statements and Presentation of Information
Hydrocarbon Volumes
The SEC permits publicly-reporting oil and gas companies to disclose “proved reserves” in their filings with the SEC. “Proved reserves” 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. SEC rules also permit the
disclosure of “probable” and possible” reserves. Rex Energy discloses proved reserves but does not disclose probable or possible reserves. We may use certain broader terms such as
“resource potential,” “EUR” (estimated ultimate recovery of resources, defined below) and other descriptions of volumes of potentially recoverable hydrocarbons throughout this
presentation. These broader classifications do not constitute “reserves” as defined by the SEC and we do not attempt to distinguish these classifications from probable or possible
reserves as defined by SEC guidelines. In addition, we are prohibited from disclosing hydrocarbon quantities that do not constitute reserves in documents filed with the SEC.
The company defines EUR as the cumulative oil and gas production expected to be economically recovered from a reservoir or individual well from initial production until the end of its
useful life. Our estimates of EURs and resource potential have been prepared internally by our engineers and management without review by independent engineers. These estimates are
by their nature more speculative than estimates of proved, probable, and possible reserves and accordingly are subject to substantially greater risk of being actually realized. We include
these estimates to demonstrate what we believe to be the potential for future drilling and production by the company. Ultimate recoveries will be dependent upon numerous factors
including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon
our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest
leases. Estimates of resource potential and other figures may change significantly as development of our resource plays provide additional data and therefore actual quantities that may
ultimately be recovered will likely differ materially from these estimates.
Potential Drilling Locations
Our estimates of potential drilling locations are prepared internally by our engineers and management and are based upon a number of assumptions inherent in the estimate process.
Management, with the assistance of engineers and other professionals, as necessary, conducts a topographical analysis of our unproved prospective acreage to identify potential well pad
locations using operationally approved designs and considering several factors, which may include but are not limited to access roads, terrain, well azimuths, and well pad sizes. For our
operations in Pennsylvania, we then calculate the number of horizontal well bores for which the company appears to control sufficient acreage to drill the lateral wells from each
potential well pad location to arrive at an estimated number of net potential drilling locations. For our operations in Ohio, we calculate the number of horizontal well bores that may be
drilled from the potential well pad and multiply this by the company’s net working interest percentage of the proposed unit to arrive at an estimated number of net potential drilling
locations. In both cases, we then divide the unproved prospective acreage by the number of net potential drilling locations to arrive at an average well spacing. Management uses these
estimates to, among other things, evaluate our acreage holdings and to formulate plans for drilling. Any number of factors could cause the number of wells we actually drill to vary
significantly from these estimates, including: the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, lease expirations,
regulatory approvals and other factors.
3

Westmoreland / Clearfield / Centre
Net Acreage ~11,300
Rex Energy Company Overview
Appalachian Basin
Net Acreage(1) ~316,800
Proved Reserves(2) 1,295.1 Bcfe
Warren / Mercer Counties
Net Acreage ~12,100
Butler Operated
Warrior Prospects
Net Acreage ~21,600
Illinois Basin
Net Acreage ~80,800
Proved Reserves(2) 6.9 MMBoe
Market Cap(3) $283 million
Current Borrowing Base Capacity(4) $350 million
2014 Production 154.4 MMcfe/d
1Q'15 Production 196.2 MMcfe/d
2Q'15E Production 199.0 – 205.0 MMcfe/d
2015E Production 193.0 – 203.0 MMcfe/d
2014 Proved Reserves(2) 1,336.8 Bcfe
2014 PV-10 $1,205 million
% Liquids 37%
2015E Capex $135 - $145 million
Liquids-Rich Drilling Locations ~1,520 gross / 1,190 net
Butler Marcellus 319 gross / 223 net
Butler Upper Devonian 486 gross / 340 net
Moraine East 418 gross / 418 net
Warrior Prospects 146 gross / 102 net
Proved Locations 151 gross / 107 net
Focused on developing liquids-rich acreage in the Appalachian and Illinois Basins
 Appalachian Basin: Targeting wet-gas windows in the Pennsylvania Marcellus and Ohio Utica Shales
 Illinois Basin: Strong cash flow; 100% oil production; low decline assets; opportunity for conventional infill drilling
(1) As of December 31, 2014; includes acreage related to recent Appalachian Basin acquisition and does not include certain
peripheral non-core acreage
(2) See note Page 2
(3) As of May 4, 2015
(4) As of March 31, 2015
4

FY2015 Capital Budget Program / Guidance
FY 2015 Operating Capital Budget $ in Millions
Appalachian Basin $124 - $134
Illinois Basin $11
Total 2015 Operating Capital Budget $135 - $145(1)
Budget Allocation
2Q15 Guidance FY 2015 Guidance
Avg. Daily Production 199.0 – 205.0 MMcfe/d 193.0 – 203.0 MMcfe/d
LOE $31.0 - $34.0 million --
Cash G&A(2) $6.5 - $7.5 million --
FY2015 Budget Highlights
 ~ 100% of 2015 budget directed towards liquids-rich assets
 ~ 90% of 2014 budget allocated to liquids-rich development of
Butler Operated Area and Ohio Utica Warrior Prospects
 Drilling program consists of one full-time drilling rig in the
Appalachian Basin
 Drill 29 – 31 gross operated wells in the Appalachian Basin
 Complete 27 – 31 gross operated wells in the Appalachian Basin
(1) Excludes leasing and capitalized interest
(2) Cash G&A guidance does not include G&A expenses related to Keystone Clearwater Solutions
80%
10%
9%
Butler Operated Area Ohio Utica Illinois Basin
5

Upcoming Divestitures & Joint Ventures
Current / In Process Asset Divestitures & JV’s
 Closed on March 30, 2015
 $16.6 million received at closing – initial contract value of $67.6 million with option for JV partner to
participate as 20% working interest partner in additional 17 wells in 2016 with value of $21.4 million
6
Butler Operated Area JV
Keystone Clearwater
Divestiture
 Investment bank engaged to market transaction
 Expect to close transaction by June 30, 2015
 Proceeds estimated to bring in $60 - $80 million
Potential / Possible Asset Divestitures
Appalachia Non-Op
 WPX (current operator) is currently marketing 100% of the assets
 Includes midstream and upstream assets
Ohio Utica Warrior South
 Net average daily production of 3,860 boe/d
 Acreage located in Guernsey, Noble and Belmont counties in Ohio
Illinois Basin
 Engaged Evercore as an advisor to explore monetization
 100% crude oil asset
 Average net production of ~2,000 bbls/d
Moraine East JV  Continue to explore potential long-term partner in Moraine East to develop liquids-rich locations

Capitalization
Simple Capital Structure
Senior Secured Credit Facility due 2019
$350 million borrowing base capacity
Covenant – Senior Secured Borrowings /TTM EBITDAX – 3.0x
$350 million of 8.875% Senior Notes due 2020
$325 million of 6.25% Senior Notes due 2022
$161 million of cumulative perpetual convertible preferred stock
Convertible into 8.9 million shares of common stock ($18.00 / share)
Convertible after 8/20/2019
Common Shares Outstanding as of 3/31/2015
Basic Shares: 54.4 million
Fully Diluted: 63.3 million (assuming full conversion of Series A preferred stock
7

Track Record of Growth
16.1 20.3 39.0
67.1 92.7
154.0
193 - 203
-30.0
20.0
70.0
120.0
170.0
220.0
2009 2010 2011 2012 2013 2014 2015E
MMcfe/d
Average Daily Production
Proved Reserves
125.2 201.7
366.2
618.1
849.8
1,336.8
0.0
200.0
400.0
600.0
800.0
1000.0
1200.0
2009 2010 2011 2012 2013 2014
Bcfe
Adjusted EBITDAX
$22.5 $27.0
$65.3
$88.8
$133.0
$174.5
$0.0
$50.0
$100.0
$150.0
$200.0
2009 2010 2011 2012 2013 2014
$MM
8

New Developments
122.2
128.8
169.7
196.0
80.0
100.0
120.0
140.0
160.0
180.0
200.0
220.0
1Q14A 2Q14A 3Q14A 4Q14A 1Q15A
AverageDailyProduction(MMcfe/d)
196.2
Recent Achievements
Butler Operated Area Joint Venture
 Joint venture agreement with ArcLight to jointly develop 32 pre-
determined wells in the Butler Operated Area
 16 wells in Moraine East Area
 16 wells in Legacy Butler Operated Area
 Reduces 2015 operating capital expenditures by $60 million to $135 -
$145 million
 $16.6 million received at closing
Amended Credit Facility
 New senior secured debt to EBITDAX covenant of 3.0x
 Permanently removes total debt to TTM EBITDAX covenant
 Re-determined borrowing base of $350 million
Moraine East Area
 Finished completion operations on four-well Renick pad in Moraine East
Area; three Marcellus wells, one Upper Devonian Burkett well
 Preliminary analysis indicates reservoir and geologic characteristics are
analogous to legacy Butler Operated Area
 Plan to release initial production and geologic update in 2Q15
Well Cost Reduction – Butler Operated Area
 Reduced cost to drill and complete wells by approximately 5% to $5.7
million per well, assuming 5,000 foot lateral, as compared to previously
reported $6.0 million per well
 Expect additional 3% - 5% of cost reductions to be in place by mid-year
2015
9

Proved Reserves
(1) Based on SEC pricing for the trailing twelve months ended 12/31/14
11

Butler Operated Area Midstream Capacity
Map of Butler Area Midstream
Source: Publicly available press releases or presentations
 90 MMcf/d of current processing
capacity at MarkWest facilities
 MarkWest added 120 MMcf/d of total
processing capacity in 2Q 2014
 Increasing total processing capacity to
315 MMcf/d through construction of
Bluestone III; expected to be
commissioned in 4Q15
Processing
Capacity
 ~305 MMcf/d of current and future
firm transportation from Bluestone
Complex
 ~80 MMcf/d of current and future firm
transportation from other delivery
points
Firm
Transportation
 Sold by MarkWest
C3+
Sales
Existing REXX
Acreage Two outlets began in 2Q 2014 for
ethane sales
 Enterprise Product Partners’ATEX
pipeline – 3,000 bbls/d
 NOVA Chemicals Mariner West
pipeline – 2,000 bbls/d
Ethane
Sales
Currently in Service
Under Construction
MWE Bluestone /
Sarsen Plants
Dominion Line
REXX Operated
Area
Mariner West
Pipeline
EPD ATEX
Pipeline
MWE Ethane
Line
Mariner East
Pipeline
12

Utica Midstream Providers
Warrior
North
Warrior
South
 Acreage dedication to Blue Racer
Midstream
 Processing capacity at Natrium
facility (Blue Racer)
 ~14 MMcf/d of residue gas firm
transportation
 Acreage dedication to MarkWest
Energy
 Processing capacity of ~25 MMcf/d
at Seneca facility
 ~30 MMcf/d of residue gas firm
transportation
REXX Warrior
South Acreage
REXX Warrior
North Acreage
Map of Utica Midstream
MWE Hopedale
Fractionator
MWE Gas &
NGL Line
EPD ATEX Line
Blue Racer East
Ohio Pipeline
MWE Cadiz
Processing Plant
MWE Seneca Processing
Plant
Blue Racer Natrium
Plant
REXX Acreage
Source: Publicly available press releases or presentations
13

Proven & Non-Proven Resource Potential(1)
Over 1,500 gross liquids-rich drilling locations as of December 31, 2014 based on 650 foot spacing in the
Appalachian Basin assets(2)
Area
Gross Identified
Locations(2)
Net Identified
Locations(2) EUR(1)(3)(4) Net Resource
Potential(4)(5) % Liquids(4)(6)
Legacy Butler Operated Area – Marcellus 319 223 ~14.0 Bcfe 2.3 Tcfe ~38%
Legacy Butler Operated Area – Upper
Devonian
486 340 ~14.0 Bcfe 3.6 Tcfe ~38%
Moraine East 418 418 ~14.0 Bcfe 4.7 Tcfe ~38%
Ohio Utica- Warrior North 107 86 ~7.2 Bcfe 0.8 Tcfe ~55%
Ohio Utica – Warrior South 39 16 ~9.6 Bcfe 0.3 Tcfe ~44%
Total Appalachia 1,369 1,083 N/A 11.7 Tcfe ~43%
Proved Locations 151 107 N/A 0.7 Tcfe(7) ~39%
Total 1,520 1,190 N/A 13.4 Tcfe N/A
2.3 1.3
3.6
4.7
0.8 0.3
11.7
Marcellus Upper Devonian Moraine East Warrior North Warrior South Total Unproven
Resource Potential
12/31/2014 Proved
Reserves
(1) See note on Hydrocarbon Volumes on page 3
(2) See Note on Potential Drilling Locations on page 3
(3) Assumes 5,000’ in Appalachian Basin
(4) Assumes 55% ethane recovery
(5) Net resource potential after royalties and non-operated interests
(6) Net liquids after shrink
(7) Represents proved reserves rather than net resource potential
14

0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Natural Gas Oil & Condensate NGLs
2015 2016
Hedge Position(1)
15
(1) Hedging position as of 5/1/2015; percent hedged based on mid-point of FY 2015 production guidance
(2) Includes 12.3 Bcf hedged with an average short put of $2.96 for 2015; Includes 14.6 Bcf hedged with an average short put of $2.80 for 2016
(3) Includes 460,000 Bbls hedged with an average short put of $53.01 for 2015; Includes 120,000 Bbls hedged with an average short put of $50.00 for 2016
(4) Represents only natural gas hedges with ceilings
Avg. Floor:
$3.51
Avg. Floor:
$3.51
Avg. Floor:
$63.93
Avg. Floor:
$61.25
Avg. Floor:
$32.76
Avg. Floor:
$33.18
2015 Basis Hedges & Firm Sales: 95,700 Mcf/d @ ($0.80)
2016 Basis Hedges & Firm Sales: 51,753 Mcf/d @ ($0.85)
(2) (4) (3)

Legacy Butler Operated Area: Marcellus
Legacy Butler Operated Area – Marcellus(1)
Recent Developments
 Placed into sales nine wells during the first quarter of 2015
 Average lateral length of 4,900 feet
 Combination of increased lateral lengths and 25% increase in
sand concentrations used during completions expected to yield
increased IP rates and improved performance to type curves
 Two wells placed into sales in early 2Q15
 Reduced cost to drill and complete wells by approximately 5% to $5.7
million per well, assuming a 5,000 foot lateral, as compared to
previously reported $6.0 million per well
 Attributable to operational efficiencies and improved pricing
from service providers
 Expect to achieve an additional 3% - 5% of cost reductions by
mid-year 2015
Acreage & Inventory
Total Net Acres ~62,600
Average Working Interest ~70%
Gross / Net Identified Potential Drilling Locations(2) 319 / 223
Current Well Spacing (Lateral Feet) 650’
2015 Drilling Plan
Rigs 1 (w/ Upper Devonian & Moraine East)
Wells Drilled 10
Wells Completed 17
Pads in progress
Pads completed
Five-Well Michael
Pad: Stacked
Lateral Pad
(1) All production results are on a per well basis
(2) See note on Potential Drilling Locations on page 3
Bicehouse Well:
• Lateral length: ~3,500’
• Sand Concentration:
~2,300 lbs/ foot
• Avg. 5-day Sales Rate:
4.3 MMcfe/d
Two-Well Bintrum Pad:
~2,300 lbs/ foot
Two-Well Burr Pad:
~2,000 lbs/ foot
10.5 MMcfe/d
Four-Well Powell Pad:
~2,300 lbs/ foot
9.3 MMcfe/d
16

(1) All production results are on a per well basis
(2) Results include wells targeting both Marcellus and Upper Devonian
(3) See note on Potential Drilling Locations on page 3
Legacy Butler Operated Area: Upper Devonian
Legacy Butler Operated Area – Upper Devonian(1)
Recent Developments
 Placed into sales the five-well Ferree pad - second planned
stacked Upper Devonian Burkett/Marcellus pad
 Preliminary analysis indicates no communication
between the Upper Devonian Burkett formation and
Marcellus formation
 Third planned test – Five-well Michael pad, testing multiple
stacked Upper Devonian Burkett/Marcellus laterals
 Hamilton well results on par with Marcellus results
Acreage & Inventory
Average Working Interest ~70%
Gross / Net Identified Potential Drilling Locations(3) 486 / 340
Current Well Spacing (Lateral Feet) 650’
2015 Drilling Plan
Rigs 1 (w/ Marcellus & Moraine East)
Wells Drilled 0
Wells Completed 2
Pads in progress
Pads completed
Perry 1HD
5.3 MMcfe/d
55% Liquids
Burgh 2HD
4.5 MMcfe/d
53% Liquids
Gilliland 11HB
4.2 Mmcfe/d
48% Liquids
Stebbins 2H
5.5 MMcfe/d
48% Liquids
Drushel 6HD
7.3 MMcfe/d
49% Liquids
Baillie Trust Pad(2)
6.0 MMcfe/d
53% Liquids
Ferree 4HB
Stacked Lateral Pad
Five-Well Michael Pad
Stacked Lateral Pad
17
Two-Well Hamilton Pad:
~2,300 lbs/ foot
7.8 MMcfe/d

Moraine East Area
 Finished completing four wells on the Renick pad
 Three Marcellus wells and one Upper
Devonian Burkett well
 Preliminary log and petrophysical data is
encouraging and supports “core of the
core” interpretation
 2015 – 2017 drilling plan will achieve 80% HBP
in Moraine East Area
 Recently announced joint venture
agreement reduces cost to HBP
2015 Drilling Plan
Rigs 1 (w/ Marcellus & Upper Devonian)
Wells Drilled 16 – 18
Wells Completed 8 – 12
Renick Pad
18

Butler Operated Area Joint Venture
1Assumes NYMEX Strip pricing as of March 2, 2015, with gas differential of $0.80 per MMBtu.
2Assumes one PUD booked per producing lateral in Moraine East Area.
Key Business Terms Description
Total Wells 32
Total Consideration $67 million; $16.6 million received at closing
16 Butler Legacy Wells ArcLight = 35% WI
16 Moraine East Wells ArcLight = 35% WI
ArcLight Reversion WI ½ of the original WI
Highlights of JV Structure
Reduces 2015 capital expenditures by $60
million, or 30%, while retaining >25% 2015
production growth
 Strong acreage valuation
 Rex retains 100% of all future locations
 Acreage can be held with less capital
 Geologic risk shared with partner
 Lower cost of capital than equity
 Accretive to future F&D
Residual value of reversionary interest at PV-10
strip pricing is ~$500K / well1
Moraine
East PUD Offset2 Total
Reserves Added 8.8 Bcfe 11.9 Bcfe 20.7 Bcfe
Capital Cost $3.7 MM N/A $3.7 MM
F&D = ~$0.18/mcfe
19

Enhanced Marcellus Performance
Improving Well Design in Butler County
4.0 Bcfe
EUR
Year-End 2012
~9.7 Bcfe EUR
(80% ethane recovery)
~8.9 Bcfe EUR
~15.0 Bcfe EUR(1)
~14.0 Bcfe EUR
~7.0 Bcfe
EUR
Year-End 2010 Year-End 2011 Year-End 2013 Projected 2015
Conventional
Frac
2,070
66%
3,500’
12 / 300’
~1,000#/ft
~$4.7 million
Conventional
Frac
2,235
66%
3,500’
12 / 300’
~1,300 #/ft
~$5.3 million
Reduced
Cluster Spacing
3,142
54%
4,000’
27 / 150’
~1,500 #/ft
~$6.5 million
Reduced
Cluster Spacing
3,175
50%
4,000’
27 / 150’
~1,650 #/ft
~$5.9 million
Completion
Gross Average 30
Day Wellhead Gas IP
(Mcf/d)
First Year Decline
Lateral Length
Stages / Spacing
Frac Sand #/Ft
All-in Costs
5.3 Bcfe
EUR
(1) 15.0 Bcfe EUR reflective of $60/bbl Oil, $3.00/MMBtu gas.
(2) EUR reflects gross volumes
Reduced
Cluster Spacing
3,683
48%
5,000’
33 / 150’
~1,800 #/ft
~$5.7 million
Reduced
Cluster Spacing
4,978
47%
5,000’
33 / 150’
~2,200-2,500 #/ft
~$5.5 million
~11.7 Bcfe EUR
~10.7 Bcfe EUR
Year-End 2014
20

$0.25 $0.23 $0.22
$1.80 $1.64 $1.56
$3.65
$3.55
$3.45
$0.30
$0.28
$0.27
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
MY 2014 YE 2014 Mid-Year Goal
Construction Drilling Completions Connect
$6.0
$5.7
$5.5
Marcellus Total Well Costs
- Normalized to 5,000’ lateral
Potential Efficiency Gains
- Consistent drilling top time performance
- Consistent completions stage performance - above 6 stages
per day, per pad
Completions
- Expect to average 6.0 – 6.5 stages per day vs. current
average of 5.5 stages per day
Drilling
- Expect to average 11.0 – 11.5
drilling days vs. current average of
12.25 days
Current Cost Environment
21

100
1,000
10,000
0 10 20 30 40 50 60
WellheadGasRate(Mcf/d)
Production Month
Wellhead Gas Rates, Adjusted to 5000 ft
Efficiently Increasing Marcellus Performance
(1) Grey dots reflect Marcellus wells, Black dots reflect Upper Devonian (Burkett) wells.
(2) Well rates adjusted linearly (1:1 ratio) to reflect 5,000 ft rate only. Rates not adjusted for increased sand concentrations. Average lateral length and sand per foot for wells presented are 4,247 feet and 1,668 lb/ft, respectively.
>1,700 lb/ft
1,500-1,700 lb/ft
<1,500 lb/ft
15.0 Bcfe Target
11.7 Bcfe Type Curve
0
1000
2000
3000
4000
5000
6000
1200 1300 1400 1500 1600 1700 1800 1900
IPRate(Mcf/d)
Sand Concentration (lbm/ft)
IP Rate vs Sand/ft
22

0
1
2
3
4
5
6
7
8
9
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
0 10 20 30 40 50 60
CumProd(Bcfe)
GrossRate(Mcfe/d)
Production Month
YE2014 2015 Target
Marcellus Economics(1)
55% Ethane Recovery(2)
(1) See note on Hydrocarbon Volumes and disclaimers at beginning of presentation.
(2) Economics reflect 55% ethane recovery.
(3) Basis price for C3+ NGLs is 50% of WTI Oil. Basis price for C2 is $0.24gal in all cases.
(4) Historical price differentials applied to Condensate and C2+ NGL volumes. Gas price differential held at minus $0.80 per MMBtu, flat for life in all cases except strip cases, where the futures differential are applied.
(5) Strip pricing as of 2/9/2015
YE2014 2015 Target
All-in Well Cost $5.7 million $5.5 million
Lateral Length 5,000 feet 5,000 feet
EUR, Bcfe, 80% & 55% C2 11.7 10.7 15.0 14.0
F&D Cost, $/Mcfe $0.49 $0.53 $0.37 $0.39
IRR(3),(4)
$3.00 NYMEX
$60.00 WTI
11% 21%
$3.50 NYMEX
$70.00 WTI
21% 37%
$3.50 NYMEX
$80.00 WTI
24% 43%
Strip Pricing(5) 17% 27%
Avg. 30-day sales rate (MMcfe/d) 3.0 – 5.0 4.0 – 6.0
23

Appalachia Drill-Bit F&D – Project Area
$0.41
$0.43
$0.46
$0.52
$0.55
$0.00
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
REXX Peer 1 Peer 2 Peer 3 Peer 4
Project Area Drill-Bit Capex
($M)
Additions (MMcfe) Drill-Bit F&D
Butler Op. Area Drill-Bit F&D $186,252 455,931 $0.41
Ohio Utica Drill-Bit F&D $114,099 67,248 $1.70
Non-Operated Drill-Bit F&D $12,574 -- N/A
Total AP Drill-Bit F&d $312,925 523,179 $0.60
Peers include: AR, COG, EQT and RRC
24

Wet Gas Upside
25
$3.25
$2.93 $2.93
$1.21
$1.50
$0.25
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
Wellhead Gas (Mcf) ~ 1.7 GPM ~ 2.1 GPM
Gas NGLs Condensate
$3.25
$4.14
$4.68
Assumptions:
$3.25 HH / $60 WTI / $30 NGLs
2.1 GPM Well: Assumes 15 bbls of condensate produced per 3,000 Mcf

Natural Gas – Supply & Demand in Northeast
Source: Asset Risk Management, LLC
Base Consumption
Committed-Greenfield Takeaway
Low Supply
Consumption Growth
Planned Takeaway
High Supply
Appalachian Storage
Conceptual Takeaway
Expected Supply
Committed/Confirmed Takeaway
Potential Takeaway
By Q3 2015, takeaway projects
projected to be sufficient to
support production growth in the
Appalachian Basin
26

Price Exposure & Firm Transport
27

Butler Area Focus Drives Value Creation
Expanding Processing Capacity
 Increasing total processing capacity to 315 MMcf/d through
Bluestone III
 Bluestone III expected to be commissioned in 4Q15
 Ethane takeaway started in 2Q’14
Reducing Drilling Costs
 $6.5 million for 4,000’ lateral at 12/31/12
 $5.9 million for a 4,000’ lateral budgeted in 2014 (down ~10%)
 $5.5 million based on MY’14 operations and realized cost reductions
 $5.7 million for a 5,000’ lateral at YE 2014
 $5.5 million for a 5,000’ lateral for FY 2015
Building Operational Scale
 Contiguous acreage blocks creates a dominant position and enables
attractive lease acquisition cost
 Extending lateral lengths and increasing well density on pads
 Per unit production costs decreasing
Developing Multiple Formations
 Currently over 120 wells producing from 3 formations
 ~1,500 potential liquids-rich locations at 650’ spacing
 Additional dry gas opportunities
Strong Hedge Position
 ~90% of natural gas production hedged above current market prices
 Locked in over 90% of expected natural gas production previously
sold at DSP for FY 2015 at a weighted average price of $0.80 below
the Henry Hub natural gas index
Securing Firm Transportation
 255 MMcf/d of current and future firm transportation
 Added 130 MMcf/d of firm transportation to Midwest and Gulf
 Entered into two LNG supply agreements to transport gas to the Gulf
 Additional gas takeaway opportunities available
Drivers of Butler Area
Economies of Scale
28

Ohio Utica: Warrior Prospects
Warrior North Prospect
Warrior South Prospect
Recent Developments
 Placed into sales the six-well J. Hall pad in Warrior South
 5-day sales rate of ~1.8 Mboe/d; ~64% liquids
 Placed into sales three-well Jenkins pad in Warrior North
Acreage & Inventory
Total Net Acres ~ 21,600
Warrior North Average Working Interest ~ 100%
Warrior South Average Working Interest ~ 63%
Gross / Net Identified Potential Drilling Locations 146 / 102
Current Assumed Wells Spacing (Lateral Feet) 650’
2015 Drilling Plan
Rigs ~1 (w/ Butler Operated Area)
Wells Drilled 3
Wells Completed --
Guernsey
Belmont
NoblePads completed
G. Graham 1H
Lateral Length:
~3,973 feet
Brace 1H
Lateral Length:
~4,170 feet
Brace West 1H, 2H:
Avg. Lateral
Length: ~4,400 feet
Ocel 1H, 2H, 3H
Avg. Lateral
Length: ~4,400 feet
Six-Well Grunder Pad
Avg. Lateral Length:
~4,800 feet
Three-Well Jenkins Pad
~5,350 feet
Five-Well J.
Anderson Pad
Avg. Lateral
Length: ~4,250 feet
Six-Well J. Hall Pad
~4,900 feet
Three-Well
Guernsey/Noble Pad
~3,535 feet
29

0.0
0.2
0.4
0.6
0.8
1.0
0
500
1,000
1,500
2,000
2,500
0 10 20 30 40 50 60
CumProd(MMBOE)
WellheadRate(BOEPD)
Production Month
Inc Sand Production Rate YE14 Production Rate
Inc Sand Cum. Production YE14 Cum. Production
Warrior North Prospect Economics(1)
(1) See note on Hydrocarbon Volumes and disclaimers at beginning of presentation.
(2) Basis price for C3+ NGLs is 50% of WTI Oil. Basis price for C2 is $0.24/gal in all cases.
(3) Historical price differentials applied to Condensate and C2+ NGL volumes. Gas price differential held at minus $0.80 per MMBtu, flat for life in all cases except strip cases, where the futures differential are applied.
30
Assumes 55% ethane recovery
YE14 Type
Curve
Increased Sand
Concentration
EUR 1.2 MMBOE 1.4 MMBOE
F&D Cost $5.67/BOE $5.29/BOE
IRR(2),(3)
$3.25 NYMEX
$65.00 WTI
13% 25%
$3.50 NYMEX
$70.00 WTI
21% 36%
$3.50 NYMEX
$80.00 WTI
33% 57%
Avg. 30-day sales rate
(MBOE/d)
1.2 – 1.4 1.8 – 1.9

Warrior South Prospect Economics(1)
(1) See note on Hydrocarbon Volumes at beginning of presentation.
(2) Basis price for C3+ NGLs is 50% of WTI Oil. Basis price for C2 is $0.24/gal in all cases.
(3) Historical price differentials applied to all volumes, flat for life in all cases except strip cases, where the futures differential are applied.
31
YE14 Type
Curve
Increased Sand
Concentration
EUR 1.6 MMBOE 1.9 MMBOE
F&D Cost $5.00/BOE $4.21/BOE
IRR(2),(3)
$3.25 NYMEX
$65.00 WTI
14% 23%
$3.50 NYMEX
$70.00 WTI
21% 33%
$3.50 NYMEX
$80.00 WTI
30% 44%
Avg. 30-day sales rate
(MBOE/d)
2.0 – 2.7 2.0 – 2.7
Assumes 55% ethane recovery
0.0
0.3
0.5
0.8
1.0
1.3
1.5
0
500
1000
1500
2000
2500
3000
0 10 20 30 40 50 60
Cum.Prod(MMBOE)
WellheadRate(BOEPD)
Production Month
Base Case Upside Case

Illinois Basin – Conventional Oil
Illinois Basin – Lawrence Field / Gibson & Posey Counties
Illinois Basin Overview
Average Working Interest 100%
2015 Drilling Plan
Rigs --
Wells Drilled 0
Wells Re-Completed 10
Lawrence
Gibson
Posey
Lawrence Field
Gibson / Posey
Counties
Recent Developments
 Net production from operated assets was ~1,873
bbls/d
 Premium pricing – NYMEX minus ~ $2.50
 Selling into local markets
 First three re-completions of 2015:
 Average peak rate: 105 bbls/d
 Average 30-day rate: 59 bbls/d
32

Marcellus – Non Operated Overview
Non Operated – Westmoreland County, PA
Non Operated – Clearfield / Centre Counties
Non-Operated Overview
Acreage
Average Working Interest 40%
2015 Drilling Plan(2)
Wells Drilled 0
Wells Completed 0
 Sizable acreage position in Westmoreland, Clearfield and
Centre Counties, PA
 ~ 28,500 gross / ~ 11,300 net
 Combined average production for a recent 5-day period – 49.8
MMcf/d
 7.0 gross MMcf/d firm capacity with interruptible takeaway
into Columbia gas line in Clearfield/Centre Counties
(1) Includes non-operated area acreage only
(2) Well information in gross
34

Butler Operated Area – Stacked Pays
POINT
PLEASANT
UTICA SHALE
TRENTON LIMESTONE
RHINESTREET SHALE
Mixed Organic &
Non-organic Shale
MIDDLESEX SHALE
Mixed Organic &
Non-organic Shale
GENESEE SHALE
Mixed Organic &
Non-organic Shale
BURKETT SHALE - Organic Black Shale
TULLY LIMESTONE
HAMILTON SHALE
Mixed Organic &
Non-organic Shale
MARCELLUS SHALE
Organic Black Shale
ONONDAGA LIMESTONE
UPPER DEVONIAN
SHALES
MARCELLUS
UTICA
Reservoir 4
200’ thick
(4,500’ to 4,800’ deep)
Reservoir 3
100+’ thick
(4,700’ to 5,500’ deep)
Reservoir 2
150’ thick
(4,900’ to 5,700’ deep)
Reservoir 1
285’ thick
(9,000’ to 11,000’ deep)
35

Rex Energy Investor Presentation May 2015

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Rex Energy Investor Presentation May 2015