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

MM

cfe

/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

$ M

M

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

Av

era

ge D

ail

y P

ro

du

cti

on

(M

Mcfe

/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

Company Overview

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

Wel

lhea

d G

as

Ra

te (

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

IP R

ate

(M

cf/

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

Cu

m P

ro

d (

Bcfe

)

Gro

ss R

ate

(M

cfe

/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

Noble Pads 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

Cu

m P

ro

d (

MM

BO

E)

Well

hea

d R

ate

(B

OE

PD

)

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

Cu

m.

Pro

d (

MM

BO

E)

Well

hea

d R

ate

(B

OE

PD

)

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

Appendix

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

Date post:	16-Jul-2015
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Rex Energy Investor Presentation May 2015

News & Politics