Rex Energy 8-K Rex Energy Announces First Quarter Production Results, Updated Capital

Rex Energy Corporation | 476 Rolling Ridge Drive | State College, PA 16801

P: (814) 278-7267 | F: (814) 278-7286

E: InvestorRelations@RexEnergyCorp.com

www.rexenergy.com

Responsible Development of America’s Energy Resources

Rex Energy

Corporate Presentation

April 2013

Exhibit 99.2

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,

2012.

We

believe

the

data

we

prepared

and

supplied to our external reservoir engineers in connection with their preparation of the 12/31/12 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, 2012 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.

This

presentation

includes

certain

non-GAAP

financial

measures

as

defined

by

the

SEC.

As

required

by

Regulation

G,

we

have

provided

a

reconciliation

of

those

measures

to

the

most

directly comparable GAAP measures on page 39.

2

Forward Looking Statements and Presentation of Information

Estimates Used in This Presentation

3

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.

Potential ASP Units

Our

estimates

of

potential

target

areas,

which

we

sometimes

refer

to

as

“units,”

for

which

we

may

use

an

Alkali-Surfactant-Polymer

(“ASP”)

flood

as

a

method

of

tertiary

recovery

have

been

prepared

internally

by

our

engineers

and

management.

These

estimates

are

based

on

our

evaluation

of

the

sand

bodies

underlying

certain

of

our

properties

in

the

Illinois

Basin.

We

have

identified

certain

characteristics

which

we

believe

are

desirable

for

potential

ASP

projects,

including

sand

bodies

with

no

less

than

60

acres

of

areal

extent

and

net

reservoir

thickness

no

less

than

15

feet.

We

have

subdivided

the

sand

bodies

to

determine

potential

ASP

target

areas,

which

have

been

modeled

such

that

no

individual

target

area

or

unit

would

exceed

500

acres.

We

include

these

estimates

to

demonstrate

what

we

believe

to

be

the

future

potential

for

ASP

tertiary

recovery

for

the

company.

These

estimates

are

highly

speculative

in

nature

and

ultimate

recoveries

will

depend

on

a

number

of

factors,

including

the

ASP

technology

utilized,

the

characteristics

of

the

sand

bodies

and

the

reservoirs,

geological

conditions

encountered,

our

decisions

regarding

capital,

and

the

impact

of

future

oil

prices.

Developing Liquids-Rich Asset Base

4

Focused on developing our liquids-rich acreage in the Appalachian and Illinois Basins

•

•

Illinois Basin: Conventional infill and enhanced oil recovery activity; 100% oil production

Warrior Prospects

Illinois Basin

Butler Operated Area

Warren / Mercer Counties

Westmoreland / Clearfield / Centre

Net Acres

Net Acres

Net Acres

Net Acres

Net Acres

~20,000

~27,000

~48,400

~16,900

~10,700

Appalachian

Basin:

Targeting

wet

gas

windows

in

the

Pennsylvania

Marcellus

and

Ohio

Utica

Shales

Operational Highlights

5

Maximizing Resource Potential

Operational and Technical Experience Being Applied in Core Areas

Established Midstream Solutions

•

Large resource base with ~ 900 potential drilling locations focused in the Appalachian with an   

estimated 5.0 Tcfe of net resource potential (assuming full ethane recovery)

•

Exposure to emerging oil play in the Illinois Basin   

•

Strong dry gas economics at strip pricing   

•

Enhancing recoveries and returns with “Super Frac”

well

design

in

Butler

Operated

Area

and

Warrior

Prospects

•

Indentified conventional infill and enhanced oil recovery opportunities in the Illinois Basin

•

2013 midstream capacity

•

Butler Operated Area –

90.0

MMcf/d

•

Warrior Prospects –

25.0

MMcf/d

•

Partnering with established midstream partners (MarkWest, Blue Racer, BP) in Appalachia to develop

midstream infrastructure and transportation

Financial Highlights

6

Strong Balance Sheet

•

Entered 2013 with ~$284 million of liquidity; Pro forma liquidity $344 million including March 2013

redetermination

Active Hedging Program

•

For 2013, approximately 97% of natural gas hedged with $4.29 floor; 97% of 2013 oil production

hedged with $88.46 floor; 64% of propane hedged at $0.98 per gallon ($41.16 / bbl), 79% of C5+ at

$2.11 per gallon ($88.62 / bbl), 65% of isobutane hedged at $1.66 per gallon ( $69.72 / bbl) and 32% of

butane hedged at $1.58 per gallon ($66.36 / bbl).

•

For 2014, approximately 75% of natural gas hedged with $3.89 floor; 77% of 2013 oil production

hedged with $86.44 floor; 6% of propane hedged at $0.93 per gallon ($39.06 / bbl) and 3% of C5+ at

$2.12 per gallon ($89.04 / bbl).

•

Actively adding hedges for 2015

Growing Proved Reserves Through the Drill Bit

7

Year

Proved Reserves

(Bcfe)

(2)

% Proved Developed

PV-10

(Millions)

Drill-Bit F&D ($/Mcfe)

All-In F&D ($/Mcfe)

2012

618.1

42%

$ 500.5

$ 0.90

(1)

$ 0.95

2011

366.2

47%

$ 539.6

$ 1.24

$ 1.84

2010

201.7

42%

$ 269.4

$ 0.67

$ 2.15

(1) Appalachian Basin F&D of $0.73.

(2) Based on year end SEC pricing.

Proved Reserves Growth (Bcfe)

66.0

125.2

201.7

366.2

618.1

0

100

200

300

400

500

600

700

2008

2009

2010

2011

2012

Oil and NGLs

Natural Gas

Proved Reserve Summary

8

Proved Reserves by Category

Proved Reserves by Commodity

1P PV-10%

618.1 Bcfe

618.1 Bcfe

$500.5 MM

12/31/12 Proved Reserves and PV-10

Note: Year End 2012 SEC Price Assumptions: Oil: $90.92; Nat. Gas: $2.94; NGLs: $32.91.

(1) NYMEX forward curve pricing as of April 12, 2013.

Reserve Category

Oil

MMbbl

NGL

MMbbl

Gas

Bcf

Total

MMBoe

SEC PV-10

$MM

NYMEX PV-10

(1)

$MM

PDP

8.4

10.1

138.7

249.4

$417.7

$505.8

PDNP

0.8

0.1

3.0

8.5

12.0

10.2

Proved Developed

9.2

10.1

141.7

257.9

$429.7

$516.0

PUD

0.2

21.5

230.0

360.1

70.8

236.3

Total Proved

9.4

31.7

371.7

618.0

$500.5

$752.3

PDP

40%

PDNP

1%

PUD

59%

NGL

31%

Gas

60%

Oil

9%

PDNP

2%

PUD

14%

PDP

84%

Liquids-Rich Non-Proven Resource Potential

(1)

9

Assumptions

Butler Operated

Area: Marcellus

Butler Operated

Area: Upper

Devonian

Warrior

Prospects:

Liquids-Rich

Utica

Total

Gross / Net Identified Potential Drilling

Locations

(2)

314 / 220

390 / 273

132 / 84

836 / 577

EUR assuming Full Ethane Recovery

~ 9.7 Bcfe

9.3 Bcfe

6.0 Bcfe

N/A

% Liquids assuming Full Ethane Recovery

40%

40%

52%

~43%

Non-proven Net Resource Potential

assuming Full Ethane Recovery

1.6 Tcfe

2.1 Tcfe

0.8 Tcfe

4.5 Tcfe

We have identified approximately ~900 gross potential proved and

non-proven drilling locations in our liquids-rich

Appalachian Basin properties

Additional

oil

resource

potential

through

our

Illinois

Basin

ASP

development

and

conventional

infill

/

recompletion

program

(4)

(1) See note on Hydrocarbon Volumes on page 3.

(2) See note on Potential Drilling Locations on page 3.

(3) Assumes 4,000’

lateral.      

(4) Net resource potential after royalties and non-operated interests and adjusted to average lateral length.

(3)

2013 Capital Budget Program

10

Budgeted $255-275 million of operating capital expenditures for 2013

~86% of 2013 Budget Directed Towards Liquids-Rich Areas

In Appalachia Basin, 2 operated rigs running with 30 wells planned; in Illinois Basin, 1 rig with 28 wells planned

Expected Production Growth: 34%-40%

(1) Estimated expenditures for 2013 do not include any amounts in the DJ Basin, which are recorded as Assets Held for Sale on Consolidated Balance Sheets.

(2) Gross well information.

(3) Five additional wells awaiting sales.

2013 Drilling & Exploration Budget By Region

Illinois Conventional

Tertiary Recovery

Projects

Butler

Ohio

WPX Non-

Operated

31.6%

39.3%

12.6%

12.2%

4.3%

Activity

Appalachian Basin

Illinois Basin

Drilling & Completion

$228.4

$33.6

Enhanced Oil Recovery

$0.0

$11.8

Midstream

$1.2

$0.0

Total 2013 Capital Budget

$229.6

$45.4

2013 Capital Program Breakdown

(1)

YTD

7

11

6

15

2013E

30

31

33

18

Operated Appalachia Drilling Program

(2)

Year

Wells

Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

0

0

0

0

2013E

(3)

11

14

9

4

Non-Operated Appalachia Drilling Program

(2)

Year

Wells

Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

Consistent Production Growth

11

61% CAGR

(1)

; Q1 2013 production ~ 29% liquids

61% CAGR

(1)

; Q1 2013 production ~ 29% liquids

(1) Based on the CAGR in annual production from 2009 to 2012..

Addition field

compression

MarkWest

Bluestone Plant

1    Sarsen plant starts

in Butler Country

st

Butler Operated Area Midstream Capacity

12

REXX Butler

Operated Acreage

MWE –

Sarsen &

Bluestone Processing

Complex

MWE –

Houston

Processing &

Fractionation Complex

EPD ATEX Express

Pipeline

Mariner East

Pipeline

Mariner West

Pipeline

Currently in Service

Under Construction

Source: Publicly available press releases or presentations

MarkWest Y-Grade

Pipeline

MarkWest Energy -

Keystone  Processing Complex

Sarsen

40 MMcf/d

In Service

Bluestone I

50 MMcf/d

In Service

Bluestone II

120 MMcf/d

2Q14

NGL Pipeline

1Q14

MarkWest Energy –

Houston Processing & Fractionation Complex

Houston I, II & III

355 MMcf/d

In Service

C3+ Fractionation

60,000 Bbls/d

In Service

Interconnect

to TEPPCO pipeline

In Service

Rail Loading

200 Rail cars

In Service

Truck Loading

12 Bays

In Service

De-ethanization

38,000 Bbls/d

3Q13

Mariner West ethane pipeline

50,000 Bbls/d

3Q13

Enterprise

Product

Partners

-

ATEX

Express

Pipeline

ATEX Express Pipeline

190 MBbls/d

1Q2014

Ohio Utica Midstream Providers

13

REXX Warrior

South Acreage

Blue Racer –

Hastings Plant

Blue Racer –

Natrium Plant

EPD ATEX Express

Pipeline

REXX Carroll

County Acreage

Mariner West

Pipeline

Blue Racer East

Ohio  Pipeline

Source: Publicly available press releases or presentations

MWE Seneca

Processing

Complex

MWE Cadiz

Processing

Complex

MarkWest Energy -

Cadiz Processing Complex

Interim Refrigeration

60 MMcf/d

In Service

Cadiz I

125 MMcf/d

2Q13

Cadiz II

200 MMcf/d

2Q14

Initial Truck/Rail Loading

3Q13

NGL Pipeline

Mid-2013

MarkWest Energy -

Seneca Processing Complex

Interim Refrigeration

45 MMcf/d

2Q13

Seneca I

200 MMcf/d

3Q13

Seneca II

200 MMcf/d

4Q13

NGL Pipeline

1Q14

Blue Racer Facilities

Hastings

180 MMcf/d

In Service

Natrium

200 MMcf/d

1Q13

Natrium Fractionation

36,000 Bbls/d

1Q13

Pipeline to ATEX

27,000 Bbls/d

2Q14

Currently in Service

Under Construction

97%

2013 Hedging Summary

1.

Percentage hedged based on mid-point of 1Q guidance with standard decline; hedging position as of 3/26/2013

2.

Includes 60,000 bbls with short put options at $65.00

3.

Includes 2.5 Bcf with short put options at $3.35 and 2.6 Bcf with $5.00 floors

4.

Assumes an NGL basket consisting of 20% C5+, 7% Isobutane, 14% Butane and 57% Propane

14

61% of Total NGL Volumes Hedged

65%

4

32%

4

$1.66

$1.58

~ 32% of all NGL components

hedged at $55.36/Bbl

2

$0.98

64%

4

$2.11

79%

$5.00

$4.51 X

$5.34

$3.87

97%

$93.02

$80.63 X

$102.36

$88.46 X $96.46

$4.29 X $4.51

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Oil (/bbl)

Gas (/mcf)

C5+ (/gal)

Isobutane

Butane

Propane (/gal)

3

Swaps

Collars

Puts

1

Butler Operated Area

15

(1) See note on Hydrocarbon Volumes on page 3.

(2)

“Super-frac”

refers

to

the

company’s

reduced

cluster

spacing

completion

design.

(3) “Super-rich”

refers

to

wells

that

produce

wet

gas

with

BTU

values

of

1,300

or

greater.

(4) Well information in gross.

2013 Butler County Drilling Program Well Counts

Year

Wells Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

4

9

6

13

2013

19

22

21

15

Completed Pads

Pads Awaiting Completion

Voll Pad (3H, 4H)

Stebbins 2H

Drushel

6HD

Meyer 2H

Plesniak Pad (3H,

9H)

Pallack Pad (1H,

3H)

Burgh 2HD

Grubbs 2H

Wack 9H

Butler Operated Area (70% WI)

Perry 1HD

Gilliland 11HB

Upper Devonian Burkett Well

Marcellus Well

Overview

~69,400 gross / ~48,400 net acres in Butler, Beaver

and Lawrence counties

~57

wells producing from the wet gas window of the

Marcellus Shale

Increasing EURs

(1)

through improved “Super-frac

(2)

”

well

completions

Exposure to “Super-rich

(3)

”

gas window in Northwestern

acreage

Stacked play with access to additional producing

horizons

Upper Devonian (Burkett / Rhinestreet): Results to date

show comparable rates and increased liquids content

compared to Marcellus

Utica Shale: Encouraging test results

(4)

Super-Rich Wet Gas Upside

(1)

Assumptions:

$4.00 HH, $90.00 WTI, 50% WTI for NGLS; $80.00 condensate.

1,250 BTU: ~1.6 GPM.

1,300 BTU: ~2.4 GPM.

10 Bbls of condensate produced per 3,000 Mcf.

(1) “Super-Rich”

refers to wells that produce wet gas with BTU volumes of 1,300 or greater.

16

$3.60

$3.60

$4.00

$2.61

$1.76

$0.27

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

Dry Gas

1,250 BTU

1,300 BTU

Gas

NGLs

Condensate

$4.00

$5.36

$6.48

Improving

well

designs

are

resulting

in

increased

EURs

(1)

and

returns

on

capital

Evolution of Butler Marcellus Development

17

Completion

Conventional Frac

Conventional Frac

Super-frac

(4)

Super-frac

(4)

Gross Average 30 Day

Wellhead IP (Mcf/d)

2,070

2,235

3,142

3,142

First Year Decline

(2)

66%

66%

54%

54%

Lateral Length

3,500’

3,500’

4,000’

4,000’

Stages

12

12

27

27

Cost

~ $4.7mm

~ $5.3mm

~ $6.5mm

~ $6.5mm

Year-End 2010

(12/31/10 Reserve Report)

Year-End 2011

(12/31/11 Reserve Report)

Year-End 2012

(12/31/12 Reserve report)

4.0 Bcfe EUR

4.0 Bcfe EUR

~ 7.0 Bcfe EUR

~ 7.0 Bcfe EUR

~ 9.7 Bcfe

EUR

(2,3)

~ 9.7 Bcfe

EUR

(2,3)

5.3 Bcfe EUR

5.3 Bcfe EUR

Pro Forma Projected 2014

Improving Well Design

Improving Well Design

Ethane Uplift and

Transportation 

Efficiencies

Ethane Uplift and

Transportation 

Efficiencies

(1)

(2)

(3)

(4)

Estimated impact to 7.0 Bcfe EUR well after giving effect to 2014 ethane and transportation arrangements.

See note on Hydrocarbon Volumes on page 3.

NSAI year-end reserve reports (Type curve declines).

“Super-frac” refers to the company’s reduced cluster spacing completion design.

Butler County Wet Gas Type Curve

18

Super-frac completion method yields attractive IRRs

in current price environment

~7 Bcfe EUR

(1)

without Ethane

Enhanced IRRs with full Ethane Recovery,

expected in 2014

~9.7 Bcfe EUR

(1,2)

with Ethane

NGL yield improves from 38 barrels per MMcf

(inlet) to 111 barrels per MMcf (inlet)

Extension of MarkWest Y-grade pipeline expected

to be reduce marketing and transportation costs by

$0.15 -

$0.25 per gallon in Q1 2014

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0

10

20

30

40

50

60

Production Month

Current Ethane Recovery

Full Ethane Recovery

Before Tax IRR

(1)

(2)

(3) Assumption used for “Current Ethane Recovery” projections of ~1.6 gallons per Mcf.

(4)

(5)

Butler Area (Operated) Assumptions

Butler County Marcellus Economics

10

15

20

25

30

35

40

$3.00

$3.50

$4.00

$4.50

$5.00

Price ($/Mcf)

IRR Butler Well w/o Ethane

IRR Butler Well w/Ethane @ $0.28/gal

IRR at Current

Strip Prices

(3)

(4,5)

See note on “Hydrocarbon Volumes” on page 3.

Estimated impact of 7.0 Bcfe EUR well after effect of 2014 ethane and transportation agreements.

Assumption used for “Full Ethane Recovery” projections of ~4.7 gallons per Mcf.

Ethane pricing of $0.28 per gallon; C3+ pricing at 57% of NYMEX.

Ohio Utica –

Warrior North Prospect

19

(1) See note on potential drilling locations on page 3.

(2) Assumes full ethane recovery.

~16,100 gross / ~15,900 net acres in Carroll County, OH (100% WI)

First well, Brace #1H, into sales in Q3 2012

1,094 boe/d 24-hour sales rate

Micro-seismic

confirms

“Super

Frac”

completion

going

forward

2 well G. Graham pad into sales on May 1, 2013

Drilled 2 wells on Brace West pad; currently being completed

~94 potential gross drilling locations

(1)

Warrior North Drilling Program

Year

Wells Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

3

2

0

2

2013E

6

4

4

3

CHK Mangun 22-15-5 8H:

1.5 Mboe/d

CHK  Neider 10-14-5 3H:

1.6 Mboe/d –

Peak Rate

CHK  Shaw 20-14-5H:

1.4 Mboe/d

CHK  Burgett #7-15-6-8H:

1.2 Mboe/d

CHK  Buell 10-11-5 8H:

3.0

Mboe/d

–

Located

10

miles south in Harrison

County

REXX Brace 1H

CHK  White 17-13-5 8H:

1.4 Mboe/d

CHK Houyouse 15-13-5 8H:

1.7 Mboe/d

CHK Coniglio 6H:

1.1 Mboe/d

Warrior North Prospect

Completed Wells

2013 Pad Location

Brace #1H Results

(2)

(Boe/d)

Natural

Gas

Condensate

NGLs

Total

%

Liquids

Total

(Ethane

Rejection)

5-day sales rate

306

273

429

1,008

70%

839

30-day sales rate

221

202

308

731

70%

610

90-day sales rate

163

127

226

515

68%

424

REXX  G. Graham 1H,

2H

CHK Walters 30-12-5 8H:

1.1 Mboe/d

Overview

REXX Brace West

Pad

EVEP  Cairns  5H: 1.7

Mboe/d

Ohio Utica –

Warrior South Prospect

~6,700 gross / ~4,100 net acres in Guernsey, Noble and Belmont

Counties, OH (63% WI)

Joint Development Agreement with MFC Drilling and ABARTA

Oil & Gas Co.

Drilled and completed 3 wells; currently shut-in

Expect wells to be placed into sales on June 1, 2013

~38 potential gross drilling locations

(2)

Rig moving to 5 well J. Anderson pad

~5,000 ft average lateral length

20

Warrior South Drilling Program

Year

Wells Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

0

0

0

0

2013E

5

5

8

0

Warrior South Prospect

REXX –

Completed

Three Well Pad

Guernsey#1H

Noble#1H

Guernsey #2H

Antero Miley 5-H

Proposed MWE

Liquids Line

GPOR –

Groh 1-12H: 

Rate of 1.9 Mboe/d;

80% Liquids

GPOR –

Wagner 1-

28H: Test Rate of 4.7

Mboe/d; 50% Liquids

GPOR –

Shugert 1-1H:

Test Rate of 4.9 Mboe/d;

44% Liquids

GPOR –

BK Stephens

1-16H:  Rate of 3.0

Mboe/d; 66% Liquids

Completed Pads

Potential Pad Location

(1) Assumes full ethane recovery.

(2) See note on Potential Drilling Locations on page 3.

GPOR –

Shugert 1-12H:

Test Rate of 7.5 Mboe/d;

43% Liquids

GPOR –

Ryser 1-25H: 

Rate of 2.9 Mboe/d;

73% Liquids

Well

Lateral Length

MBoe/d

(1)

Liquids %

Guernsey 2H

3,640’

3,111

57%

Guernsey 1H

3,587’

2,968

57%

Noble 1H

3,378’

2,938

55%

GPOR –

Stutzman 1-14H:

Test Rate of 4.1 Mboe/d;

23% Liquids

GPOR –

Clay 1-4H: 

Rate of 2.2 Mboe/d;

68% Liquids

Overview

Warrior South Industry Results Comparison

21

> 65% Liquids

Company

Well Name

Lateral

(feet)

BTU

Shrink

%

Gas

(Mcf/d)

Oil

(Bbls/d)

NGL

(Bbls/d)

Boe/d (Full Ethane

Recovery)

% Liquids

Boe/d assuming

3,500’

Lateral*

GPOR

Groh 1-12H

5,414

1,247

18%

2,296

1,186

367

1,935

80%

1,251

PDCE

Onega Commissioners

14-25H

3,950

1,254

20%

~1,891

~841

~345

1,501

79%

1,330

GPOR

Boy Scout 5-33H

6,029

1,259

22%

2,262

902

383

1,662

77%

965

PDCE

Detweiler 42-3H

3,868

1,263

21%

~3,059

~999

~530

2,039

75%

1,845

GPOR

Boy Scout 1-33H

7,974

1,310

25%

5,325

1,560

1,008

3,456

74%

1,517

GPOR

Ryser 1-25H

8,291

1,160

21%

4,661

1,488

649

2,914

73%

1,230

GPOR

Clay 1-14H 

7,372

1,258

27%

4,307

747

761

2,226

68%

1,057

GPOR

BK Stephens 1-16H

5,276

1,207

11%

6,141

1,224

759

3,007

66%

1,994

Average

6,022

1,245

21%

3,743

1,118

600

2,342

74%

1,399

50% -

65% Liquids

REXX

Guernsey 2H

3,640

1,207

20%

8,082

564

1,200

3,111

57%

2,991

REXX

Guernsey 1H

3,587

1,216

20%

7,603

549

1,152

2,968

57%

2,896

REXX

Noble 1H

3,378

1,216

20%

8,004

392

1,212

2,938

55%

3,044

Average

3,535

1,213

20%

7,896

502

1,188

3,006

56%

2,977

< 50% Liquids

GPOR

Wagner 1-28H

8,143

1,214

18%

14,022

432

1,881

4,650

50%

1,999

GPOR

Shugert 1-1H

5,758

1,204

17%

16,600

144

2,002

4,913

44%

2,986

GPOR

Shugert 1-12H

8,197

1,204

10%

25,650

300

2,907

7,482

43%

3,195

GPOR

Stutzman 1-14H

8,634

1,078

11%

18,690

0

945

4,060

23%

1,646

Average

7,683

1,175

14%

18,741

219

1,934

5,276

40%

2,456

Source: Publicly available press releases announcing well test results

*Internal calculation based upon  lateral lengths shown in table

Illinois Basin Overview

22

Rex Energy is one of the largest producers in the

basin, producing approximately 2,179 net Bbls/d of oil

~27,000 net acres

Represents 9% of total proved reserves and 18% of

Q4 2012 production

Rex Energy has identified multiple zones with

conventional recompletion opportunities

Added 849 Bbls/d of incremental oil production in

Q4 2012

Provide attractive rates of return in current price

environment

In process of delineating acreage and multiple

zones

Plan to drill 28 wells and complete first horizontal test

well in 2013

Continue to explore opportunities to increase

production in the basin

Lawrence Field

Gibson and Posey Counties

Overview

Illinois Basin

Net

Acres

(1)

~27,000

Proved

Reserves

(MMBoe)

(2)

9.2

PV-10

($MM)

(2)

$222.2

%

Oil

(2)

100.0%

%

Developed

(2)

99.6%

Q4

2012

Production

(MBoe/d)

(1)

2.2

(1) As of 12/31/12.

(2) NSAI Reserve Report as of 12/31/12; See note on Non-GAAP Financial Measures – PV-10 on page 39.

Marcellus Non-Operated Overview

Sizeable acreage position with ~44,400 gross / ~16,900 net

acres

(1)

in Westmoreland, Clearfield and Centre Counties,

PA

Westmoreland County: ~6 Bcf EUR

(2)

; attractive economics

at

$4.00 / MMcfe

December 2012 average daily production of ~57.6 gross

MMcf/d from 43 producing wells

81.0 gross MMcf/d total takeaway capacity in

Westmoreland, PA

7.0 gross MMcf/d firm capacity with interruptible takeaway

into Columbia gas line in Clearfield/Centre Counties

23

Year

Wells Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

0

0

0

0

2013E

(4)

11

14

9

4

Marcellus Non-Operated

Westmoreland

County Non-

Operated Area

Clearfield-Centre

County Non-

Operated Area

(1) Includes non-operated area acreage only.

(2) See note on Hydrocarbon Volumes on page 3.

(3) Well information in gross.

(4) Five additional wells awaiting sales.

Overview

EUR

Number of Wells

~ 5.8 Bcf –

6.2 Bcf

32

~ 7.0 Bcf

6

> ~ 7.5 Bcf

7

(3)

Marcellus Non-Operated Drilling Program

24

Lawrence Field

Lawrence Field ASP

Implementing ASP flood operations in Lawrence field

acreage in Lawrence County, IL

Middagh Pilot

Oil cuts in the Pilot increased from 1.0% to ~12.0% in total

unit, with individual wells experiencing oil cuts above 20%

Peak production was seen at 100+ Bbls/d

Current proved reserves booking of 13% of pore volume

continues to be confirmed

Perkins-Smith Unit Pilot Expansion

ASP injection commenced in June 2012

Initial project response expected in mid-year 2013

Expected peak response at year-end 2013

Delta Unit Full Scale Commercial Expansion

Core studies and geologic mapping complete

Drilling of additional pattern wells complete

Injection line tie-in complete

On track to begin ASP injection in 4Q 2013

Added 758 net MBO of proved reserves in 2012

Middagh Pilot

15 Acres

Perkins-Smith

58 Acres

Delta Unit

Responsible Development of America’s Energy Resources

Appendix

First Quarter and Full Year 2013 Guidance

First Quarter

2013

Full Year

2013

Average Daily Production

71.5 –

73.5 MMcfe/d

90.5 –

94.5 Mmcfe/d

Lease Operating Expense

$13.0 –

$14.5 million

$58.0 –

$62.0 million

Cash G&A

$5.8 –

$6.8 million

$26.0 –

$29.0 million

Capital Expenditures

N/A

$230.0 -

$250.0 million

26

Reservoir 3

~ 60’

thick

(4,700’

to 5,500’

deep)

Reservoir 4

200’

thick

(4,500’

to 5,800’

deep)

Reservoir 2

150’

thick

(4,900’

to 5,700’

deep)

Reservoir 1

285’

thick

(9,000’

to 11,000’

deep)

27

Butler Operated Area Stacked Pays

Stratigraphic Column

2012

2013

Rhinestreet Shale

Burkett Shale

Marcellus Shale

Utica Shale

•

Frac one legacy vertical well to test gas quality and

liquids potential

•

No planned drilling in 2013 given Marcellus / Burkett

development

•

Drilled 4 locations

•

Completed first test well (Gilliland #11HB)

•

Tests indicate 16% increase in liquids production vs.

Marcellus

•

~ 350 identified locations in Marcellus

•

Drilled 17 wells; completed 19 wells

•

Continued improvement in drilling/completion

techniques

•

Drilling efforts focused in this zone given economics

and ability to also hold shallow acreage

•

18 wells planned to drill; 17 wells planned for

completion

•

Completed first Utica well (Cheesman 1H) that went

into sales in Q1 2012 at 9.2 MMcfe/d

•

Drilled second Utica well (Hufnagel #1H) in July 2012

•

Complete Hufnagel  #1H in 1H 2013

•

Plan to drill 1 location

•

Plan to complete 4 locations

•

Recent Drushel 6-HD produced into sales at a 5-day

rate of 7.3MMcfe/d (assuming full ethane recovery)

•

2 completions will test Super Rich portion of acreage

28

Marcellus “Super Frac”

Marcellus “Super Frac”

Completion Optimization

Completion Optimization

Process

Process

Drushel 3H (150 ft design) “Super Frac”:

•

Job Performed: Apr. 2011; On Prod: 680  Days

•

Lateral Length: 3,000’

; 21 Stages

Behm 1H (150 ft design) “Super Frac”:

•

Job Performed: Jun. 2011; On Prod: 540 Days

•

Lateral Length: 3,900’; 26 Stages

Carson 3H (150 ft design) “Super Frac”:

•

Job Performed: Mar. 2012; On Prod: ~250 days

•

Lateral Length: 3,900’; 26 Stages

Carson 1H (225 ft design) “Super Frac”:

•

Job Performed: Mar. 2012; On Prod: ~250 days

•

Lateral Length: 4,500’; 20 Stages

Pallack 1H & 3H (150 ft design) “Super Frac”:

•

Job Performed: Aug. 2012; On Prod: ~160 days

•

Lateral Length: 3,600’; 24 Stages

Plesniak  3H & 9H (150 ft design) “Super Frac”:

•

Job Performed: Sept. 2012; On Prod: ~80 &135 days

•

Lateral Length: 3,600’; 24 Stages

Voll  3H & 4H (225 ft design) “Super Frac”:

•

Job Performed: Oct.. 2012; On Prod: ~70 days

•

Lateral Length: 3H-3,400’; 15 Stages

•

Lateral Length: 4H-4,000’

; 18 Stages

Meyer 2H (150 ft design) “Super Frac”:

•

Job Performed: Jan. 2013; On Prod: ~15 days

•

Lateral Length: 4,000’; 27 Stages

Lateral Spacing: 450 -

600 feet apart

Type curve validates lower initial first year decline

Lateral Spacing: 950 feet apart

225’

stage spacing versus 150’

stage spacing

Lateral Spacing: 900 feet apart

150’

stage spacing

Restricted choke production test flowback

Lateral Spacing: No interference 150’

stage spacing

Plesniak #3H: No Shut-In : Restricted choke

Plesniak #9H: Extended Shut-in : Restricted Choke

No Interference

150’

stage spacing

Extended Shut-in : Restricted Choke

Lateral Spacing: 650 feet apart

225’

stage spacing versus 150’

stage spacing

Extended Shut-In: Restricted Choke

Preliminary results from varying extended shut-ins and restricted chokes yield a 25-35% increase in early pressure

profile.

Next

6-9

months

of

production

history

will

help

determine

optimal

stage

size

and

lateral

spacing.

rate

Marcellus Non-Operated Overview

•

Sizeable acreage position with 44,400 gross / 16,900

net

acres

in

Westmoreland,

Clearfield

and

Centre

Counties, PA

•

Westmoreland

County:

~6

Bcf

EUR

2

;

attractive

economics

at

$4.00

/

MMcfe

•

Clearfield-Centre Counties: 12,200 gross acre block:

6,500 HBP, 5,700 no expiry for next five years

•

Executed JV with WPX Energy on this position in 2009

•

WPX operates both areas

•

December 2012 Avg. Daily Production of ~57.6 MMcf/d

from 42 producing wells

•

Plan to complete 7 wells currently awaiting completion

•

81.0 gross MMcf/d total takeaway capacity in

Westmoreland, PA

•

7.0 gross MMcf/d firm capacity with interruptible takeaway

into Columbia gas line in Clearfield/Centre Counties

29

Marcellus

Non-Operated

Drilling

Program

3

Year

Wells Drilled

Fracture

Stimulated

Placed in

Service

Awaiting

Completion

YTD

0

0

0

0

2013E

0

7

7

0

Marcellus Non-Operated

Westmoreland

County Non-

Operated Area

Clearfield-Centre

County Non-

Operated Area

1.

Includes non-operated area acreage only

2.

See note on Hydrocarbon Volumes on page 3

3.

Well information in gross

1

Westmoreland County Marcellus Economics

30

Before Tax IRR

Westmoreland County (Non-Operated)

Assumptions

•

Well costs of ~$5.8 million per well

•

Lateral length of 3,500 ft.

•

EUR of ~6.0 Bcf per well

•

As of year end 2012 reserves:

Westmoreland County Dry Gas Type Curve

IRR at Current

Strip Prices

EUR

Number of Wells

~ 5.8 Bcf –

6.2 Bcf

32

~ 7.0 Bcf

6

> ~ 7.5 Bcf

7

Production Month

4.2 Bcf Type Curve

6.0 Bcf Type Curve

IRR -

4.2 Bcf Well

IRR -

6.0 Bcf Well

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

0

10

20

30

40

50

60

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

$3.00

$3.50

$4.00

$4.50

$5.00

Liquids Production Ratios

31

Current Liquids Sales Ratio

Liquids Sales Ratio With Full Ethane Sales

~1.6 Gallons per

Wellhead Mcf

~4.7 Gallons per

Wellhead Mcf

Ethane

10%

Propane

50%

Butane

15%

Iso-

Butane

7%

Natural

Gasoline

18%

Ethane

67%

Propane

18%

Butane

5%

Iso-Butane

3%

Natural

Gasoline

7%

2013 Hedging Summary

(1)

0%

20%

40%

60%

80%

100%

2013 Oil

(/bbl)

2013 Gas

(/mcf)

2013 C5+

($/gal)

2013 Isobutane

($/gal)

2013 Butane

($/gal)

2013 Propane

($/gal)

Puts

Collars

Swaps

49% of Total NGL Volumes Hedged

~ 26% of all NGL components hedged at $55.36/Bbl

68%

78%

64%

52%

26%

51%

$93.02

$4.06

$2.11

$1.66

$1.58

$0.98

$103.00

-

$79.45

$5.34

-

$4.51

$5.00

(1) Percentage hedged based on mid-point of Full Year production guidance; hedging position as of 4/11/2013.

(2) Includes 45,000 bbls with short put options at $65.00.

(3) Includes 1.9 Bcf with short put options at $3.35.

(4) Assumes an NGL basket consisting of 20% C5+, 7% Isobutane, 14% Butane and 57% Propane.

(2)

(3)

(4)

(4)

(4)

(4)

32

2014 Hedging Summary

(1)

0%

20%

40%

60%

80%

2014 Oil

(/bbl)

2014 Gas

(/mcf)

Puts

Collars

Swaps

54%

60%

$103.32

-

85.01

$4.04

$90.00

$4.60

-

$3.87

Small amount of NGLs hedged in

2014 (8,000 Bbls total)

(1) Percentage hedged based on mid-point of Full Year 2013 production guidance  with standard decline through 2014; hedging position as of 4/11/2013.

(2) Includes 360,000 bbls with short put options at $69.00.

(3) Includes 6.6 Bcf with short put options at $3.04; Excludes 1.8 Bcf in $5.00 call options.

(2)

(3)

33

Current Hedging Summary

34

1.

Hedging position as of 3/26/2013

Crude Oil

(1)

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

Swap Contracts

120,000

120,000

120,000

--

--

--

--

Volume Hedged

$ 93.02

$ 93.02

$ 93.02

--

--

--

--

Price

Collar Contracts

Volume Hedged

45,000

60,000

60,000

15,000

15,000

15,000

15,000

Ceiling

$ 104.33

$ 102.50

$ 102.50

$ 97.65

$ 97.65

$ 97.65

$ 97.65

Floor

$ 76.67

$ 80.50

$ 80.50

$ 90.00

$ 90.00

$ 90.00

$ 90.00

Three-Way

Collars

Volume Hedged

15,000

15,000

15,000

90,000

90,000

90,000

90,000

Ceiling

$ 100.00

$ 100.00

$ 100.00

$ 104.27

$ 104.27

$ 104.27

$ 104.27

Floor

$ 85.00

$ 85.00

$ 85.00

$ 80.00

$ 80.00

$ 80.00

$ 80.00

Short Put

$ 65.00

$ 65.00

$ 65.00

$ 65.00

$ 65.00

$ 65.00

$ 65.00

Put Spread

Contracts

Volume Hedged

--

--

--

42,000

42,000

42,000

42,000

Floor

--

--

--

$ 90.00

$ 90.00

$ 90.00

$ 90.00

Short Put

--

--

--

$ 75.00

$ 75.00

$ 75.00

$ 75.00

Current Hedging Summary (Cont’d)

35

Natural Gas Hedges

(1)

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

Swap Contracts

Volume

1,930,000

2,130,000

2,130,000

1,410,000

1,110,000

1,110,000

1,110,000

Price

$ 3.85

$ 3.88

$ 3.88

$ 3.96

$ 3.96

$ 3.96

$ 3.96

Collar Contracts

Volume

840,000

840,000

840,000

450,000

450,000

450,000

450,000

Ceiling

$ 5.68

$ 5.68

$ 5.68

$ 4.43

$ 4.43

$ 4.43

$ 4.43

Floor

$ 4.77

$ 4.77

$ 4.77

$ 3.51

$ 3.51

$ 3.51

$ 3.51

Put Contracts

Volume

660,000

660,000

660,000

--

--

--

--

Floor

$ 5.00

$ 5.00

$ 5.00

--

--

--

--

Call Contracts

Volume

--

--

--

450,000

450,000

450,000

450,000

Ceiling

--

--

--

$ 5.00

$ 5.00

$ 5.00

$ 5.00

Three Way Collars

Volume

630,000

630,000

630,000

1,500,000

1,500,000

1,500,000

1,500,000

Ceiling

$ 4.88

$ 4.88

$ 4.88

$ 4.64

$ 4.64

$ 4.64

$ 4.64

Floor

$ 4.17

$ 4.17

$ 4.17

$ 3.95

$ 3.95

$ 3.95

$ 3.95

Short Put

$ 3.35

$ 3.35

$ 3.35

$ 3.00

$ 3.00

$ 3.00

$ 3.00

1.

Hedging position as of 3/26/2013

2.

Swap contract volumes and average prices include swaption hedges

(2)

Current Hedging Summary (Cont’d)

36

Natural Gas Liquids

(1)(2)

2Q13

3Q13

4Q13

Swap Contracts

Propane

Volume Hedged (Bbls)

33,000

33,000

33,000

Price per Barrel

$ 42.42

$ 42.42

$ 42.42

Price per Gallon

$ 1.01

$ 1.01

$ 1.01

Butane

Volume Hedged (Bbls)

6,000

6,000

6,000

Price per Barrel

$ 66.36

$ 66.36

$ 66.36

Price per Gallon

$ 1.58

$ 1.58

$ 1.58

Isobutane

Volume Hedged (Bbls)

6,000

6,000

6,000

Price per Barrel

$ 69.72

$ 69.72

$ 69.72

Price per Gallon

$ 1.66

$ 1.66

$ 1.66

C5+

Volume Hedged (Bbls)

21,000

21,000

21,000

Price Per Barrel

$ 88.62

$ 88.62

$ 88.62

Price per Gallon

$ 2.11

$ 2.11

$ 2.11

1.

Hedging position as of 3/26/2013

2.

NGL hedges are indexed to Mt. Belvieu indexes for each respective component

37

PV-10 Reconciliation

Standardized Measure of Discounted Future Net Cash Flows

$ 396,123

79,587

24,822

Discounted Future Net Cash Flows (SEC PV-10)

$500,532

Incremental Discounted Future Cash Flows from Strip Pricing in Excess of SEC Pricing

251,748

Discounted Future Net Cash Flows (Strip PV-10)

$752,280

The following table presents a reconciliation of Rex Energy’s PV-10 to its standardized measure of discounted future net cash flows as of December 31,

2012:

(1)

For purposes of this reconciliation, we have used estimates of the effects of future income taxes and future abandonment costs (asset retirement obligations).

($ in thousands)

Discounted

Future

Cash

Flows

from

Abandonments

(1)

Discounted

Future

Cash

Flows from

Income Taxes

(1)

38

Finding & Development Cost Reconciliation

December 31, 2010

December 31, 2011

December 31, 2012

Drill-Bit Capital Deployed

$76.3

$192.8

$176.9

Acreage Acquisitions

70.7

78.7

51.0

Equity Method Investments, Noncontrolling Interests and Other

17.5

30.9

11.0

All-In Capital Deployed

$164.5

$302.4

$238.9

December 31, 2010

December 31, 2011

December 31, 2012

Drill-Bit Capital Deployed

$76.3

$192.8

$176.9

Acreage Acquisitions

70.7

78.7

51.0

Drill-Bit Finding and Development Cost ($/Mcfe)

$0.67

$1.24

$0.90

December 31, 2010

December 31, 2011

December 31, 2012

All-In Capital Deployed

$164.5

$302.4

$238.9

Extensions and Discoveries (Bcfe)

114.0

155.8

196.6

Production (Bcfe)

(7.4)

(14.2)

(24.6)

Acquisitions and Divestitures (Bcfe)

(14.5)

-

0.3)

Revisions to Previous Estimates (Bcfe)

(15.8)

22.9

79.6

Subtotal (Bcfe)

76.3

164.5

251.9

All-In Finding and Development Cost ($/Mcfe)

$2.15

$1.84

$0.95

Non-GAAP Financial Measures

39

“EBITDAX”

means, for any period, the sum of net income for such period plus the following expenses, charges or income to the extent deducted from or added to net income in such period:

interest, income taxes, DD&A, unrealized losses from financial derivatives, the retroactive portion of the Pennsylvania Impact Fee, exploration expenses and other similar non-cash charges,

minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income. EBITDAX, as defined above, is used as a financial measure by our

management team and by other users of its financial statements, such as our commercial bank lenders to analyze such things as:

•

Our operating performance and return on capital in comparison

to those of other companies in our industry, without regard to financial or capital structure;

•

The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or

historical cost basis;

•

Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and

•

The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) (the most directly comparable GAAP financial measure)

in measuring our performance, nor should it be used as an exclusive measure of cash flows, because it does not consider the impact of working capital growth, capital expenditures, debt

principal reductions, and other sources and uses of cash, which are disclosed in our consolidated statements of cash flows.

We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and because this measure is commonly reported and widely used by investors as an

indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we

have disclosed EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX

as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due

to requirements to conserve funds for capital expenditures, debt

service and other commitments.

We believe that EBITDAX assists our lenders and investors in comparing our performance on a consistent basis without regard to certain expenses, which can vary significantly depending

upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs. In addition, because we use capital assets, DD&A

are also necessary elements of our costs. Finally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these

elements have material limitations.

To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to

evaluate our performance.

PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and

operating

expenses,

but

before

deducting

any

estimates

of

future

income

taxes.

The estimated

future

net

revenues

are

discounted

at

an

annual

rate

of

10%

to

determine

their

“present

value.”

PV-10

is

a

financial

measure

routinely

used

by

professional

analysts

and

investors

in

evaluating

oil

and

gas

companies.

We

believe

that

PV-10

is

a

financial

measure

calculated

similarly

by

other companies in the oil and gas industry.  Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we

believe the use of a pre-tax measure is valuable for evaluating the company. PV-10 differs from the standardized measure of discounted future net cash flows relating to proved oil and gas

reserves, or SMOG,  as calculated and presented in accordance with GAAP, and should not be considered as an alternative to the standardized measure as computed under GAAP.  We note

that

SMOG

is

typically

not

calculated

on

an

interim

basis,

as

it

is

not

practicable

to

calculate

taxes

on

other

than

an

annual

basis.

Taxes

is

the

principal

difference

between

PV-10

and

SMOG,

and accordingly we have not reconciled PV-10 measured as of October 31, 2012, the date of our most recent reserve estimates used in this presentation.