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Rex Energy Corporate Presentation
November 2014
Forward Looking Statements and Presentation of Information
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 proved reserves as of June 30, 2014 in this presentation are based solely on the review and calculations of our internal reservoir engineers and have not been prepared
or audited by our independent external reserve engineers. The estimates of proved reserves as of December 31, 2013 in this presentation are based on a reserve report of our independent
external reserve engineers. We believe the data we (i) prepared and reviewed internally in connection with our estimates of proved reserves as of June 30, 2014, and (ii) we prepared and
supplied to our external reservoir engineers in connection with their preparation of the 12/31/2013 reserve report, and, in each case, 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, 2013 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.
2
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
Rex Energy Company Overview
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
Appalachian Basin
Net Acreage(1)
~314,000
Proved Reserves(2)
1,014.4 Bcfe
$376 million
Liquidity(4)
>$480 million
2014E Production
Warren / Mercer Counties
Net Acreage
Market Cap(3)
3Q'14 Production
~12,100
4Q'14E Production
MY 2014 Proved Reserves(2)
Warrior Prospects
Net Acreage
~21,300
Westmoreland / Clearfield / Centre
Net Acreage
~11,000
Butler Operated
Net
Acreage(1)
~269,200
Proved Reserves(2)
(1)
(2)
(3)
(4)
7.2 MMBoe
As of June 30, 2014; includes acreage related to recent Appalachian Basin acquisition and does not include certain peripheral
non-core acreage
See note Page 2
As of November 3, 2014
As of September 30, 2014
179.0 – 185.0 MMcfe/d
1,057.8 Bcfe
$1,041 million
38%
2014E Capex
$350 - $365 million
Net Acreage(1)
Liquids-Rich Drilling Locations
~81,700
169.7 MMcfe/d
% Liquids
2014E Wells Drilled
Illinois Basin
Net Acreage
MY 2014 PV-10
150.0 – 152.0 MMcfe/d
62 – 69
~395,700
~1,266 gross / 964 net
Butler Marcellus
357 gross / 250 net
Butler Upper Devonian
431 gross / 302 net
Moraine East / Butler Acq.
241 gross / 241 net
Warrior Prospects
143 gross / 105 net
Proved Locations
94 gross / 66 net
4
Track Record of Growth
Average Daily Production
MMcfe/d
150.0
100.0
150 – 152
50.0
67.1
0.0
17.2
20.3
2009
2010
92.7
39.0
2011
2012
2013
2014E
Proved Reserves
1000.0
MMcfe
800.0
600.0
1,057.8
849.8
400.0
618.1
200.0
0.0
125.2
201.7
2009
2010
366.2
2011
2012
2013
MY2014
Adjusted EBITDAX
$200.0
$ MM
$150.0
$100.0
$186.3
$134.8
$50.0
$0.0
$22.5
$26.2
2009
2010
$62.9
2011
$87.7
2012
2013
1H2014 (annualized)
5
New Developments
Recent Achievements
200.0
179.0 – 185.0
180.0
Average Daily Production (MMcfe/d)
169.7
Preliminary 2015 Capital Expenditures & Production Growth Plans
 Preliminary 2015 capital expenditure guidance of $325 - $375 million
 FY 2015 production growth guidance – 30% - 40%
160.0
Record Third Quarter Production
 3Q14 production of 169.7 MMcfe/d exceeded high-end of guidance by 3%
 Sequential increase of 32% vs. 2Q14
 Liquids production reached record level of 10.4 Mboe/d
 61% increase vs. 2Q14
 Oil and condensate production of 3.3 Mboe/d; 20% increase vs. 2Q14
140.0
128.8
Warrior North Prospect
 Placed into sales six-well Grunder pad
 5-day sales rate of ~1.2 Mboe/d; ~71% liquids
 30-day sales rate of ~0.9 Mboe/d; ~69% liquids
 Initial results from downspacing are encouraging
 Placed into sales three-well Jenkins pad
 5-day sales rate of ~1.6 Mboe/d; ~72% liquids
 30-day sales rate of ~1.3 Mboe/d; ~72% liquids
122.2
120.0
110.4
100.0
Improved Butler Operated Area Well-Level Economics
 Improved well-level economics in Butler Operated Area due to:
 Increased average lateral length
 Strong well performance
 Reduced cycle times
 Adjustments in expected realized prices
 Rate of returns have increased from ~26% to ~47% in Butler Operated Area
98.7
80.0
3Q13A
4Q13A
1Q14A
2Q14A
3Q14A
4Q13E
Balance Sheet
 Completed an offering of $161 million of convertible perpetual preferred stock
 Net proceeds of $155.0 million; used to fund the Butler Operated Area
acquisition
 Increased borrowing base to $400 million; no outstanding borrowings under
revolving credit facility
 Liquidity of >$480 million
6
Company Overview
Growing Production and Reserves
Production Growth (MMcfe/d)
200
185.0
180
160
140
120
169.7
100
80
60
60.7
62.5
71.1
1Q12
2Q12
3Q12
86.1
73.9
75.3
4Q12
1Q13
98.7
110.4
122.2
128.8
1Q14
2Q14
179.0
40
Actual Production
2Q13
3Q13
Guidance Low Case Production
Proved Reserves Growth (Bcfe)
4Q13
3Q14
4Q14E
Guidance High Case
Third Quarter Production Mix
1200
1000
800
600
400
200
0
2008
2009
2010
2011
Oil and NGLs
2012
2013
MY2014
Natural Gas
8
Proved Reserves
Mid-Year Update(1)



Proved reserves increased by 24% from
YE 2013 (25% increase in proved
developed reserves)
PV-10 Growth ($ MM)(2)
$1,200
$1,000
~7% reduction in Butler Operated Area
D&C costs in 1H’14
$800

$600
Exceeded 3-5% cost reduction
target for FY 2014
Most recent 10 wells in Butler Operated
Area drilled in average of 15 days

~20% fewer days than expected
$400
$200
$0
2008
Proved Reserves by Commodity
2009
2010
2011
2012
2013
6/30/2014
Proved Reserves Growth (Bcfe)
1,058 Bcfe
(1)
(2)
Rex Energy's estimated proved reserves at June 30, 2014 were prepared by its internal reservoir engineers and have not been prepared or audited by its independent reservoir engineers
Based on SEC pricing for the trailing twelve months ended 06/30/14
9
Butler Operated Area Midstream Capacity


MarkWest added 120 MMcf/d of total
processing capacity in 2Q 2014

Increasing total processing capacity to
405 MMcf/d through construction of
Bluestone III & IV; expected to be
commissioned in 4Q15 & 2Q16
Processing
Capacity
Firm
Transportation
90 MMcf/d of current processing
capacity at MarkWest facilities

Map of Butler Area Midstream
MWE Bluestone /
Sarsen Plants
~365 MMcf/d of current and future
firm transportation for residue gas
Dominion Line
MWE Ethane
Line
C3+
Sales

Sold by MarkWest

Propane sold into local market
REXX Operated
Area
EPD ATEX
Pipeline
Mariner West
Pipeline
Mariner East
Pipeline

Ethane
Sales
Two outlets beginning 2Q 2014 for
ethane sales
 Enterprise Product Partners’ ATEX
pipeline
 NOVA Chemicals Mariner West
pipeline
Existing REXX
Acreage
Source: Publicly available press releases or presentations
Currently in Service
Under Construction
10
Utica Midstream Providers
Map of Utica Midstream

Warrior
North
Acreage dedication to Blue Racer
Midstream

Processing capacity at Natrium
facility (Blue Racer)

~14 MMcf/d of residue gas capacity
Blue Racer East
Ohio Pipeline
REXX Warrior
North Acreage
EPD ATEX Line
MWE Cadiz
Processing Plant
MWE Hopedale
Fractionator
REXX Warrior
South Acreage

Warrior
South


Acreage dedication to MarkWest
Energy
MWE Gas &
NGL Line
Processing capacity of 20 MMcf/d at
Seneca facility
~30 MMcf/d of residue gas capacity
Blue Racer Natrium
Plant
MWE Seneca Processing
Plant
REXX Acreage
Source: Publicly available press releases or presentations
11
Firm Transportation
Butler, PA
Texas Gas Transmission – Louisiana Access Project
Receipt Point:
Delivery Points:
Pipelines Accessed:
Lebanon, OH
Lebanon, OH
Gulf South-Bosco – Perryville, LA
DTI, TETCO, REX
Rex Energy Capacity: 100,000 MMBtu/d
Dominion Transmission Inc. – Lebanon West II
Receipt Point:
Delivery Points:
Pipelines Accessed:
TL -400 Bluestone Plants in Butler, PA
Lebanon, OH
DTI, TETCO, REX
Rex Energy Capacity: 130,000 MMBtu/d
Perryville, LA
12
Non-Proven Resource Potential(1)
Over 1,200 pro forma gross liquids-rich drilling locations as of December 31, 2013 based on 750 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)(6)
% Liquids(4)(7)
Legacy Butler Operated Area – Marcellus
357
250
~9.7 Bcfe
1.9 Tcfe
~42%
Legacy Butler Operated Area – Upper
Devonian
431
302
~8.3 Bcfe(5)
1.9 Tcfe
~40%
Ohio Utica- Warrior North
108
89
~7.2 Bcfe
0.8 Tcfe
~45%
Ohio Utica – Warrior South
35
16
~12.0 Bcfe
0.3 Tcfe
~37%
Total Appalachia
931
657
N/A
4.9 Tcfe
~41%
Proved Locations
94
66
N/A
0.8 Tcfe(8)
37%
Total Legacy
1,025
723
N/A
5.7 Tcfe
~40%
Moraine East
241
241
--
--
--
1,266
964
N/A
N/A
N/A
Total
0.3
0.8
1.9
4.9
1.9
Marcellus
(1)
(2)
(3)
(4)
1.1
Upper Devonian
See note on Hydrocarbon Volumes on page 3
See Note on Potential Drilling Locations on page 3
Assumes 4,000’ lateral in Butler and 5,000’ lateral in Ohio
Assumes 80% ethane recovery
Warrior North
(5)
(6)
(7)
(8)
Warrior South
Total Unproven Resource
Potential
6/30/2014 Proved
Reserves
12/31/2013 PUD estimate; Drushel 6HD & Gilliland 11HB EURs assuming 80% ethane recovery averaged 9.75 Bcfe
Net resource potential after royalties and on-operated interests
Net liquids afer shrink
Represents proved reserves rather than net resource potential
13
FY2014 Capital Budget Program / Guidance
FY 2014 Capital Budget
$ in Millions
Appalachian Basin – Drilling & Completion
$300 - $310
Appalachian Basin – Facilities, HSE & Equipment
$10
Illinois Basin – Drilling & Completion
$30 - $35
Illinois Basin – Drilling & Completion
$10
$350 - $365(1)
Total 2014 Capital Budget
Budget Allocation
2.0%
FY2014 Budget Highlights
 ~ 98% of 2014 budget directed towards liquids-rich assets
 ~ 87% of 2014 budget allocated to liquids-rich development of
Butler Operated Area and Ohio Utica Warrior Prospects
 Drilling program consists of three full-time drilling rigs in the
Appalachian Basin
 Drill 51 – 56 gross operated wells in the Appalachian Basin
 Complete 52 – 55 gross operated wells in the Appalachian Basin
 Does not include capital allocated to Butler Operated Area
acquisition
11.0%
33.0%
54.0%
IL Conventional
(1)
Butler
Ohio
WPX Non Operated
4Q14 Guidance
FY2014 Guidance
179.0 – 185.0 MMcfe/d
150.0 – 152.0 MMcfe/d
LOE
$31.0 - $34.0 million
$93.0 - $98.0 million
Cash G&A
$9.0 - $10.0 million
$35.0 - $38.0 million
Avg. Daily Production
Excludes leasing, capitalized interest and Keystone Clearwater
14
Detailed Hedge Position(1)
Natural Gas(2)
Swaps
Oil & Condensate(3)
2014
2015
Volume (MMBtu/d)
30,543
19,726
% Hedged
27%
Price ($/MMBtu)
$4.12
NGLS
2014
2015
Volume (Bbls/d)
978
82
20%
% Hedged
28%
$4.14
Price ($/Bbl)
$97.72
Natural Gas
2014
2015
Volume (Bbls/d)
2,837
707
3%
% Hedged
61%
17%
$95.76
Price ($/Bbl)
$56.70
$44.52
Oil & Condensate
2014
2015
2014
2015
Volume (MMBtu/d)
48,913
35,342
Volume (Bbls/d)
1,598
575
% Hedged
43%
35%
% Hedged
46%
19%
Ceiling Price ($/MMBtu)
$4.67
$4.61
Ceiling Price ($/Bbl)
$102.57
$100.44
Floor Price ($/MMBtu)
$4.12
$4.16
Floor Price ($/Bbl)
$89.38
$90.18
Collars
Dominion South Point
2014 NGL Breakout
Basis
Differential
Hedges
2014
2015
Volume (MMBtu/d)
16,304
3,288
% Hedged
14%
3%
Price ($/MMBtu)
($0.37)
($0.56)
Propane
Butane
IsoButane
C5+
Volume (Bbls/d)
1,859
163
163
652
% Hedged
68%
25%
50%
70%
Price ($/Bbls)
$45.36
$55.86
$56.28
$89.46
Avg. Floor: $92.54
Oil &
Condensate
Avg. Floor: $90.88
21%
Avg. Floor: $4.12
Natural Gas
Avg. Floor: $4.15
Avg. Floor: $44.52
0%
10%
17%
20%
2014
30%
69%
55%
Avg. Floor: $56.70
NGLs
75%
61%
2015
40%
50%
60%
70%
80%
(1) Hedging position as of 11/3/2014; percent hedged based on mid-point of FY production guidance (2)Includes 24.1 Bcf hedged with an average short put of $3.57 (3) Includes 432,000 Bbls hedged with an average short put of $78.32
15
Expanded Butler Operated Area
Butler Extension Area
Shell Acreage Acquisition
Net Acreage
Net Revenue Interest
~207,000
Net Acreage
~90,600
83%
Wells PIS
4
Butler Liquids-Rich
Net Acreage
~50,000
Moraine East:
~24,000 net acres
Western Lawrence Utica
Net Acreage
~66,100
Rex Legacy Acreage
Net Acreage
~62,600
16
Legacy Butler Operated Area: Marcellus
Legacy Butler Operated Area – Marcellus(1)
Recent Developments
 Placed into sales the Reno 1H at an average 5-day sales rate of 10.6
MMcfe/d
 Highest rate on a per lateral foot basis of any well drilled in
the Butler Operated Area
Three-Well Shipley
Pad: ~ 8.2 MMcfe/d
46% Liquids
Five-Well Michael
Pad: Stacked
Lateral Pad
Lynn N&S 3H, 5H
6.9 MMcfe/d
47% Liquids
 Placed into sales the five-well Ferree pad
 Second test of stacked Upper Devonian Burkett/Marcellus
laterals
 5-day sales rate per well of 8.3 MMcfe/d
 Five-well Michael pad
 Third test of stacked Upper Devonian/Burkett/Marcellus
laterals
Acreage & Inventory
Total Net Acres
~62,600
Average Working Interest
Reno 1H
5-day sales rate:
10.6 MMcfe/d
Baillie Trust Pad(2)
6.0 MMcfe/d
53% Liquids
(1)
(2)
(3)
Kennedy 1H, 2H
6.5 MMcfe/d
43% Liquids
Ferree 1H, 2H, 5H,
6H: Stacked Lateral
Pad
~70%
Gross / Net Identified Potential Drilling Locations(3)
Current Well Spacing (Lateral Feet)
357 / 250
750’
2014 Drilling Plan
Rigs
2 (w/ Upper Devonian)
Pads in progress
Wells Drilled
39 – 42
Pads completed
Wells Completed
34 – 37
Wells Placed into Sales
34 – 37
Wells Awaiting Completion
15 – 16
All production results are on a per well basis
Results include wells targeting both Marcellus and Upper Devonian
See note on Potential Drilling Locations on page 3
17
Legacy Butler Operated Area: Upper Devonian
Legacy Butler Operated Area – Upper Devonian(1)
Perry 1HD
5.3 MMcfe/d
55% Liquids
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
Burgh 2HD
4.5 MMcfe/d
53% Liquids
Gilliland 11HB
4.2 Mmcfe/d
48% Liquids
Five-Well Michael Pad
Stacked Lateral Pad
Stebbins 2H
5.5 MMcfe/d
48% Liquids
 Third planned test – Five-well Michael pad, testing multiple
stacked Upper Devonian Burkett/Marcellus laterals
 Continuing to analyze results of Baillie Trust pad
 No interference noted to date
Acreage & Inventory
Total Net Acres
~62,600
Average Working Interest
~70%
Gross / Net Identified Potential Drilling Locations(3)
Current Well Spacing (Lateral Feet)
Baillie Trust Pad(2)
6.0 MMcfe/d
53% Liquids
Drushel 6HD
7.3 MMcfe/d
49% Liquids
Ferree 4HB
Stacked Lateral Pad
750’
2014 Drilling Plan
Rigs
(1)
(2)
(3)
431 / 302
2 (w/ Upper Devonian)
1–3
Pads in progress
Wells Drilled
Pads completed
Wells Completed
1
Wells Placed into Sales
1
All production results are on a per well basis
Results include wells targeting both Marcellus and Upper Devonian
See note on Potential Drilling Locations on page 3
Wells Awaiting Completion
1–2
18
Liquids-Rich Moraine East
~50,000 net acres (~24,000 inside development area) targeting wet-gas Marcellus and Upper Devonian contiguous to
existing position
 Complementary fit with the legacy Butler acreage position

Attractive, liquids-rich Marcellus and Upper Devonian inventory

Geologic review suggests area is comparable to the existing
Butler operations

Initial Development
Area
Expect similar economics as Butler Operated Area

Opportunity to significantly increase inventory / lateral lengths
through infill leasing due to the existing contiguous acreage
position

Near-term development plan:

Pipeline to MarkWest’s processing facility (potential 3rd
party)

Potential to add joint-venture partner
Acreage & Inventory
Bricker
Pad

Future bolt-on leasing expected to add
~160 additional liquids-rich locations
Total Net Acres
~50,000
Average Royalty
~17%
Initial Gross Locations (750’ spacing)
241
Marcellus
134
Upper Devonian
107
Targeted Acre Infill Leasing
10,000
19
Marcellus Economics(1)
7,000
60.0%
6.0
80% Ethane Recovery(2)
IRR @ Strip
Pricing(4)
6,000
50.0%
5.0
Production Rate (Mcfe/d)
4.0
IRR (%)
5,000
40.0%
IRR @ Strip
Pricing(4)
4,000
3.0
30.0%
IRR @ Strip
Pricing(4)
3,000
2.0
20.0%
$3.50
$4.00
2,000
$4.50
$5.00
Henry Hub ($/MMBtu)
Year-End 2013 IRR
Mid-Year 2014 IRR
Updated 2014 IRR
1.0
1,000
YE 2013 Well Costs
MY 2014 Well Costs
YE 2014 Well Costs
~ 9.7 Bcfe
~ 9.7 Bcfe
~ 11.7 Bcfe
~$5.9 million
~$5.5 million
~$6.0 million
4,000 feet
4,000 feet
5,000 feet
C3+ ($/bbl)
$55.00
$55.00
$55.00
Ethane ($/gallon)
$0.30
$0.30
$0.30
Nat. Gas Differential
($0.50)
($0.50)
($1.00)
EUR
-
0
5
10
15
20
25
30
35
40
45
50
55
60
Production Month
~ 9.7 Bcfe EUR - YE 2013
(2)
(3)
(1)
(2)
(3)
(4)
~ 9.7 Bcfe EUR - MY 2014
~11.7 Bcfe EUR - 2014
Cum. Production - YE 2013
Cum. Production - MY 2014
Cum. Production - 2014
See note on Hydrocarbon Volumes on page 2
~ 8.9 Bcfe EUR @ 55% ethane recovery
~10.7 Bcfe EUR @ 55% ethane recovery
Strip pricing as of 9/30/2014
(2)
Drill & Complete
Lateral Length
20
Wet Gas Upside
$4.00
21
Butler Price Realization Comparisons
$5.00
~$4.75 / Mcfe
~ $4.50 - $4.75 / Mcfe
$4.50
~ $50 / bbl
$4.00
~ $56 / bbl
Value Per Mcfe
$3.50
$3.00
~ $4.00 NYMEX
$2.50
$2.00
~ $3.30/ Mcf
~ $3.80 / Mcf
$1.50
~ ($0.70)
Basis
Differential
$1.00
$0.50
$0.00
2013 Average
FY 2014
Gas
NGL
Ethane
Basis Hedges
22
Natural Gas – Supply & Demand in Northeast
By Q3 2015, takeaway projects
projected to be sufficient to
support production growth in the
Appalachian Basin
Base Consumption
Consumption Growth
Appalachian Storage
Committed/Confirmed Takeaway
Committed-Greenfield Takeaway
Planned Takeaway
Conceptual Takeaway
Potential Takeaway
Low Supply
High Supply
Expected Supply
Source: Asset Risk Management, LLC
23
Efficiently Increasing Marcellus EUR
Improving Well Design in Butler County
Ethane
Uplift(1)
Ethane
Uplift(2)
~9.7 Bcfe EUR
(80% ethane recovery)
~11.7 Bcfe EUR
(80% ethane recovery)
~8.9 Bcfe EUR
(55% ethane recovery)
~10.7 Bcfe EUR
(55% ethane recovery)
4.0 Bcfe EUR
5.3 Bcfe EUR
~7.0 Bcfe EUR
Year-End 2010
(12/31/10 Reserve
Report)
Year-End 2011
(12/31/11 Reserve
Report)
Year-End 2012
(12/31/12 Reserve
Report)
Year-End 2013
(12/31/13 Reserve
Report)
Projected Year-End
2014
Conventional Frac
Conventional Frac
Super-Frac(3)
Super-Frac(3)
Super-Frac(3)
2,070
2,235
3,142
3,175
3,683
66%
66%
54%
50%
48%
3,500’
3,500’
4,000’
4,000’
5,000’
Stages / Spacing
12 / 300’
12 / 300’
27 / 150’
27 / 150’
33 / 150’
Frac Sand #/Ft
~1,000#/ft
~1,300 #/ft
~1,500 #/ft
~1,800 #/ft
~2,000 – 2,200 #/ft
~$4.7 million
~$5.3 million
~$6.5 million
~$5.9 million
~$6.0 million
Completion
Gross Average 30
Day Wellhead IP
First Year Decline
Lateral Length
All-in Costs
(1)
(2)
(3)
Estimated impact to 7.0 Bcfe EUR well after giving effect to 2013 ethane and transportation agreements
Estimated impact after giving effect to 2013 ethane and transportation agreements
“Super-Frac” refers to Rex’s reduced cluster spacing completion design
As of 6/30/2014, all-in
cost is ~$5.5 million
24
Operational Efficiencies – Butler Op. Area
Butler Operated Area – Average Lateral Length
14
12
Number of Wells
2013
2013 Avg. Lateral Length: ~ 4,000 ft.
2014 Avg. Lateral Length: ~ 5,100 ft.
11
9
8
10
2014
13
9
6
8
6
4
1
1
0
0
2
0
1
0
< 3,000'
3,000' - 4,000'
4,000' - 5,000'
5,000' - 6,000'
6,000' - 7,000'
> 7,000'
Butler Operated Area – Wells Per Pad
5
5
3.9 wells per pad
4
4
Pads
3
3
2.5 wells per pad
2
2
1
1
1
1
0
0
1-well pad
2-well pad
2013
2014
2013 Avg. Wells Per Pad
3-well pad
4-6+ well pad
2014 Avg. Wells Per Pad
25
Butler Area Focus Drives Value Creation
Expanding Processing Capacity
 Increasing total processing capacity to 405 MMcf/d through
Bluestone III & Bluestone IV
 Bluestone III & Bluestone IV expected to be commissioned in 4Q15
and 2Q16
 Ethane takeaway started in 2Q’14
Securing Firm Transportation
 235 MMcf/d of current and future firm transportation
 Added 130 MMcf/d of firm transportation to Midwest and Gulf
 Additional gas takeaway opportunities available
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
 $6.0 million for a 5,000’ lateral
Drivers of Butler Area
Economies of Scale
Accelerating Development
 More than doubled the 2013 wells drilled with 40-45 wells being
drilled in 2014
 Running 2 full time rigs in 2014
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 ~95 wells producing from 3 formations
 ~1,200 pro forma potential liquids-rich locations at 750’ spacing
 Additional dry gas opportunities
26
Ohio Utica: Warrior Prospects
Warrior North Prospect
Brace 1H
Lateral Length:
~4,170 feet
Recent Developments
Brace West 1H, 2H:
Avg. Lateral
Length: ~4,400 feet
G. Graham 1H
Lateral Length:
~3,973 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
Avg. Lateral Length:
~5,350 feet
Warrior South Prospect
Acreage & Inventory
Total Net Acres
~ 21,300
Warrior North Average Working Interest
~ 100%
Warrior South Average Working Interest
~ 63%
Gross / Net Identified Potential Drilling Locations
Guernsey
Five-Well J.
Anderson Pad
Avg. Lateral
Length: ~4,250 feet
 Placed into sales the six-well Grunder pad in Warrior North
 5-day sales rate of ~1.2 Mboe/d; ~72% liquids
 Initial results from 600 and 500 foot downspacing are
encouraging
 Placed into sales three-well Jenkins pad in Warrior North
 5-day sales rate of ~1.6 Mboe/d; ~72% liquids
 Drilling six-well J. Hall pad in Warrior South
 Avg. lateral length of ~ 5,400 feet
 Testing 650 foot downspacing
Six-Well J. Hall Pad
Avg. Lateral Length:
~5,400 feet
Current Assumed Wells Spacing (Lateral Feet)
Pads in progress
Noble
Pads completed
Three-Well
Guernsey/Noble Pad
Avg. Lateral Length:
~3,535 feet
750’
2014 Drilling Plan
Rigs
Belmont
143 / 105
1
Wells Drilled
12
Wells Completed
18
Wells Placed into Sales
Wells Awaiting Completion
12 – 18
--
27
Warrior North Prospect Economics(1)
Assumes 55% ethane recovery
55%
1,400
Jenkins wells performing above green line
0.6
50%
45%
1,200
40%
IRR @ Strip
Pricing(2)
1,000
0.4
800
0.3
600
0.2
Cumulative Production (MMboe)
Production Rate (Boe/d)
0.5
35%
30%
IRR @ Strip
Pricing(2)
25%
20%
$3.50
$4.00
$4.50
$5.00
400
~ 1.2 MMboe EUR - YE Reserve Case
0.1
YE 2013 Well Costs
200
Drill & Complete
0
0.0
0
10
20
30
40
50
60
Production Month
1.2 MMboe EUR - YE Reserve Case
(1)
(2)
~ 1.2 MMboe EUR at Improved Condensate Yield
~$7.8 million
Lateral Length
5,000 feet
Oil Price ($/bbl)
$95.00
C3+ ($/bbl)
$55.00
Ethane ($/gallon)
$0.30
Nat. Gas Differential
($0.50)
Cum. Production
See note on Hydrocarbon Volumes on page 2
Strip pricing as of 9/30/2014
28
Warrior South Prospect Economics(1)
Assumes 55% ethane recovery
80%
2,500
1.1
70%
1.0
60%
Production Rate (Boe/d)
0.7
1,500
0.6
0.5
1,000
0.4
Cumulative Production (MMboe)
0.8
IRR (%)
0.9
2,000
IRR @ Strip
Pricing
50%
IRR @ Strip
Pricing
40%
30%
IRR @ Strip
Pricing
20%
$3.50
$4.00
$4.50
$5.00
Henry Hub Natural Gas Prices
IRR at ~ 1.7 MMboe EUR - YE Reserve Case
0.3
IRR at ~ 2.0 MMboe EUR - YE Reserve Case
~ 2.0 MMboe EUR at Improved Condensate Yield
500
0.2
YE 2013 Well Costs
Drill & Complete
0.1
0
0.0
0
10
20
30
40
50
60
Production Month
~ 2.0 MMboe EUR - YE Reserve Case
(1)
Cum. Production
~$8.5 million
Lateral Length
5,000 feet
Oil Price ($/bbl)
$95.00
C3+ ($/bbl)
$55.00
Ethane ($/gallon)
$0.30
Nat. Gas Differential
($0.50)
See note on Hydrocarbon Volumes on page 2
29
Illinois Basin – Conventional Oil
Illinois Basin – Lawrence Field / Gibson & Posey Counties
Recent Developments
 Gross production per day across whole field: ~ 2,800
bbls/d
 Premium pricing – NYMEX minus ~ $2.50
 Selling into local markets
 Additional upside from ASP Project
Lawrence
Illinois Basin Overview
Lawrence Field
Total Net Acres
~81,700
Average Working Interest
100%
2014 Drilling Plan
Rigs
Gibson
Wells Drilled
Wells Completed(1)
Wells Placed into Sales
Gibson / Posey
Counties
Wells Awaiting Completion
~1
9 – 11
29 – 31
9 - 11
--
Posey
(1)
Includes 20 re-fracs
30
Marcellus – Non Operated Overview
Non Operated – Westmoreland County, PA
Non-Operated Overview
 Sizable acreage position in Westmoreland, Clearfield and
Centre Counties, PA
 ~ 28,300 gross / ~ 11,000 net
 Combined average production for a recent 5-day period – 61.0
MMcf/d
 7.0 gross MMcf/d firm capacity with interruptible takeaway
into Columbia gas line in Clearfield/Centre Counties
Acreage(2)
Non Operated – Clearfield / Centre Counties
Total Net Acres
~11,000
Average Working Interest
40%
2014 Drilling Plan(3)
(1)
(2)
(3)
Wells Drilled
1
Wells Completed
6
Wells Placed into Sales
6
Wells Awaiting Completion
--
Includes non-operated area acreage only
As of June 30, 2014
Well information in gross
31
Appendix
Western Lawrence Utica
~66,100 net acres in Western Lawrence Utica targeting the dry-gas Utica, with existing production and strong offset
performance
Kephart
Drilled

Large inventory of attractive dry-gas Utica acreage

Position allows efficient development
– Long laterals; ability to hold up to 4 units with
one pad
Twentier
Drilled
Patterson
Drilled /
Producing
Hufnagel
Drilled / Producing

Surrounded by industry activity (Chesapeake to the
South and Hilcorp to the North)

Existing takeaway provides ability to get gas to
sales quickly, including up to ~50 MMcf/d on TGP
and ~30 MMcf/d on NFG

No processing constraints

Potential to add joint venture partner
Acreage & Inventory
Value Proposition



Test resource potential in 2015
Dry gas optionality based on pricing
Emerging resource play in dry gas Utica
Total Net Acres
~66,100
Average Royalty
~17%
Initial Gross Locations (750’ spacing)
197
33
Liquidity and Capitalization
6/30/2014
9/30/2014
Cash & Cash Equivalents
$
5,951
$
87,622
Net Debt
$
546,954
$
590,194
Credit Facility Available
$
173,000
$
400,000
Simple Capital Structure
Senior Secured Credit Facility due 2019
$400 million borrowing base – completely undrawn
Restrictive Covenant – Debt/TTM EBITDAX – 4.25x
$350 million of 8.875% Senior Notes due 2020
Total Liquidity(1)
178,951
487,622
$325 million of 6.25% Senior Notes due 2022
Net Debt / TTM EBITDAX
3.2x
Strong Liquidity Position
Third Quarter 2014 Liquidity of over $480 million
3.4x
$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 9/30/2014
Basic Shares: 53.2 million
$87.6 million of
cash
(1) Excluding letters of credit
$400 million undrawn
borrowing base
Fully Diluted: 58.0 million (assuming full conversion of Series A preferred
stock
34
Butler Operated Area – Stacked Pays
RHINESTREET SHALE
Mixed Organic &
Non-organic Shale
Reservoir 4
200’ thick
(4,500’ to 4,800’ deep)
UPPER DEVONIAN
SHALES
MIDDLESEX SHALE
Mixed Organic &
Non-organic Shale
GENESEE SHALE
Mixed Organic &
Non-organic Shale
BURKETT SHALE - Organic Black Shale
TULLY LIMESTONE
Reservoir 3
100+’ thick
(4,700’ to 5,500’ deep)
HAMILTON SHALE
Mixed Organic &
Non-organic Shale
MARCELLUS
MARCELLUS SHALE
Organic Black Shale
Reservoir 2
150’ thick
(4,900’ to 5,700’ deep)
ONONDAGA LIMESTONE
UTICA SHALE
Reservoir 1
285’ thick
(9,000’ to 11,000’ deep)
UTICA
POINT
PLEASANT
TRENTON LIMESTONE
35
Baillie Trust Pad – Stacked Laterals
750’ spacing
100’
50’
175’
600’ spacing
600’ spacing
Stacked Laterals
 Tested both Marcellus and Upper Devonian Burkett through use of stacked laterals
 Utilizing microseismic testing to demonstrate expected lack of communication between formations
 Providing cost efficiencies
Testing Spacing
 Tested 600-foot spacing vs. 750-foot spacing on most recent Marcellus units
 Current inventory of 431 Upper Devonian Burkett locations assumes 750-foot spacing
 Current indications suggest downspacing is successful; Rex to continue monitoring production/pressure profiles
Landing Zone
 Tested different landing zones in two of the four Marcellus wells
36