Rex Energy 8-K Rex Energy Announces 61% Net Increase in Proved Reserves

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

Together We Can Make A Difference

Exhibit 99.2

Forward Looking Statements

Except

for

historical

information,

statements

made

in

this

release,

including

those

relating

to

significant

potential,

future

earnings,

cash

flow,

capital

expenditures,

production

growth

and

planned

number

of

wells

(as

well

as

the

timing

of

rig

operations,

natural

gas

processing

plant

commissioning

and

operations,

fracture

stimulation

activities

and

the

completion

of

wells

and

the

expected

dates

that

wells

are

producing

hydrocarbons

that

are

sold),

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.

These

forward-

looking

statements

are

indicated

by

words

such

as

“expected”,

“expects”,

“anticipates”

and

similar

words.

These

statements

are

based

on

assumptions

and

estimates

that

management

believes

are

reasonable

based

on

currently

available

information;

however,

management's

assumptions

and

the

company's

future

performance

are

subject

to

a

wide

range

of

business

risks

and

uncertainties,

and

there

is

no

assurance

that

these

goals

and

projections

can

or

will

be

met.

Any

number

of

factors

could

cause

actual

results

to

differ

materially

from

those

in

the

forward-looking

statements,

including

(without

limitation)

the

following:

•adverse

economic

conditions

in

the

United

States

and

globally;

•the

difficult

and

adverse

conditions

in

the

domestic

and

global

capital

and

credit

markets;

•domestic

and

global

demand

for

oil

and

natural

gas;

•sustained

or

further

declines

in

the

prices

the

company

receives

for

oil

and

natural

gas;

•the

effects

of

government

regulation,

permitting

and

other

legal

requirements;

•the

geologic

quality

of

the

company’s

properties

with

regard

to,

among

other

things,

the

existence

of

hydrocarbons

in

economic

quantities;

•uncertainties

about

the

estimates

of

the

company’s

oil

and

natural

gas

reserves;

•the

company’s

ability

to

increase

production

and

oil

and

natural

gas

income

through

exploration

and

development;

•the

company’s

ability

to

successfully

apply

horizontal

drilling

techniques

and

tertiary

recovery

methods;

•the

number

of

well

locations

to

be

drilled,

the

cost

to

drill

and

the

time

frame

within

which

they

will

be

drilled;

•the

effects

of

adverse

weather

on

operations;

•drilling

and

operating

risks;

•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

transportation

pipelines;

•changes

in

the

company’s

drilling

plans

and

related

budgets;

•the

adequacy

of

capital

resources

and

liquidity

including

(without

limitation)

access

to

additional

borrowing

capacity;

and

•uncertainties

associated

with

our

legal

proceedings

and

the

outcome.

The

company

undertakes

no

obligation

to

publicly

update

or

revise

any

forward-looking

statements.

Further

information

on

the

company’s

risks

and

uncertainties

is

available

in

the

company's

filings

with

the

Securities

and

Exchange

Commission.

The

company's

internal

estimates

of

reserves

may

be

subject

to

revision

and

may

be

different

from

estimates

by

the

company's

external

reservoir

engineers

at

year

end.

Although

the

company

believes

the

expectations

and

forecasts

reflected

in

these

and

other

forward-looking

statements

are

reasonable,

it

can

give

no

assurance

they

will

prove

to

have

been

correct.

They

can

be

affected

by

inaccurate

assumptions

or

by

known

or

unknown

risks

and

uncertainties.

2

Forward Looking Statements

Forward Looking Statements

Hydrocarbon Volume Estimates

This

presentation

includes

management’s

estimates

of

Marcellus

Shale

potential

recoverable

resources,

per

well

EUR

(estimated

ultimate

recovery

of

resources)

and

upside

potential

of

recoverable

resources.

Except

as

noted,

these

have

been

estimated

internally

by

the

Company

without

review

by

independent

engineers

and

do

not

necessarily

constitute

reserves.

These

estimates

are

included

to

demonstrate

the

potential

for

future

drilling

by

the

Company.

Actual

recovery

of

these

potential

volumes

is

inherently

more

speculative

than

recovery

of

estimated

proved

reserves.

Estimates

of

potential

recoverable

resources,

per

well

EURs

and

upside

potential

for

Company

oil

and

gas

shale

acreage

are

particularly

speculative

due

to

the

limited

experience

in

Marcellus

Shale

horizontal

development,

with

its

limited

production

history.

Ultimate

recoveries

will

be

dependent

upon

numerous

factors

including

actual

encountered

geological

conditions,

the

impact

of

future

oil

and

gas

pricing

and

exploration

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.

In

addition,

potential

recoverable

resources

are

based

on

undesignated

future

well

locations

under

assumed

acreage

spacing

which

may

not

have

been

specifically

included

in

any

definitive

development

plan

and

ultimately

may

not

be

drilled.

Accordingly,

such

estimates

may

differ

significantly

from

the

hydrocarbon

quantities

that

are

ultimately

recovered.

SEC

rules

prohibit

a

publicly-reporting

oil

and

gas

company

from

including

oil

and

gas

resource

estimates

in

their

filings

with

the

SEC,

except

proved,

probable

and

possible

reserves

that

meet

the

SEC’s

definitions

of

such

terms.

Illinois

Basin

estimates

(including

Lawrence

Field)

of

oil

in

place

and

other

resource

volumes,

oil

in

place

and

other

reserve

volumes

indicated

herein

are

not

based

on

SEC

definitions

and

guidelines.

Unless

otherwise

indicated,

estimates

of

non-proved

reserves

and

other

hydrocarbons

included

herein

may

not

meet

specific

definitions

of

reserves

or

resource

categories

within

the

meaning

of

the

SPE/SPEE/WPC

Petroleum

Resource

Management

System.

Hydrocarbon Value Estimates

Hydrocarbon Value Estimates

3

Rex Energy Overview

Rex Energy Overview

4

Significant upside in two high growth shale plays and tertiary oil recovery

•

1.4

–

2.0

Tcfe

in

non-proven

Marcellus

Shale

resource

potential

(1)

•

17.4

–

30.5

Mmboe

in

non-proven

Niobrara

Shale

resource

potential

(1)

•

24.2

–

60.6

Mmbls

in

non-proven

Tertiary

Recovery

oil

resource

potential

(1)

Liquids Rich Production & Proven Reserves

•

Total

production

of

22.8

Mmcfe/d

(3,793

BOE/d)

(2)

o

53%

oil

and

NGLs

•

202

Bcfe

(33.6

Mmbls)

proven

reserves

(3)

o

62%

of

proved

developed

is

attributable

oil

and

NGLs

o

85%

liquids

rich

capture

Strong Balance Sheet & Liquidity

(4)

•

$11.0

million

cash

•

$10.1

million

in

debt

•

$115.0

million

available

on

line

of

credit

•

Borrowing

base

redetermination

in

February,

2011

•

$30.0

million

in

Marcellus

drilling

carries

1. Assumptions based on full development program. Actual results may vary significantly. Not proved. See ���Hydrocarbon Volume Estimates” on page 3 and page 14.

2. Unaudited fourth quarter 2010 results

3. Based on year-end 2010 reserves

4. Unaudited financial results as of 12/31

Areas of Operation

Areas of Operation

Appalachian Region

•

57,000 net acres in Marcellus Shale fairway

o

61% of acreage in liquids rich portion of the play

o

Total

non-proven

resource

potential

of

1.4

–

2.0

Tcfe

(1)

o

$30.0 million in drilling carries

(2)

Rockies Region

•

45,000 net acres in Niobrara Shale fairway

(3)

o

100% of acres in oil window of the

Niobrara in the DJ Basin

o

Total non-proven resource potential

of 17.4 –

30.5 MMBoe

(1)

Illinois Region

•

Tertiary recovery oil projects

o

Total

non-proven

resource

potential

of

24.2

–

60.6

MMBbls

from

ASP

flooding

in

the

Lawrence

Field

(1)

5

1. Assumptions based on full development program. Actual results may vary significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3 and page 14.

2. Unaudited financial results as of 12/31/2010

3. Includes 8,300 net farm in acres

Key Investment Highlights for 2011

Key Investment Highlights for 2011

•

Rex Energy is positioned for growth

o

Strong position in oil and liquids-rich areas

o

Company expects 2011 production growth of 71%-95% over 2010

•

Strong core position in the Appalachian Basin

o

Solid core position in Butler County with 400 potential drill sites

in the Marcellus Shale, with additional potential in the Utica and

Upper Devonian Shale

•

Strong track record  of growth with a historical reserve

CAGR of 75%

•

Rex Energy is equipped to thrive in a low gas price

environment

o

74% of the 2011 capital budget is dedicated to oil and

liquids rich project areas.

o

65%

of

the

Appalachian

capital

budget is

allocated

to

liquids rich Butler County

•

Secured key drilling, fracture stimulation, and tubular

services for the next two years

•

Opportunities for growth within tertiary recovery projects in

the Illinois Basin and encouraging results in the Niobrara

6

Positioned For Growth

Positioned For Growth

•

Poised to achieve 71% -

95% production growth in 2011

•

Expect to see 22% -

40% growth in oil and NGL production in 2011

•

A mid case December exit rate of 45.6 Mmcfe/day in 2011 represents an 83% increase compared to the 2010 exit rate

7

Reserve Growth

Reserve Growth

Proved Reserve & Compound Annual Growth Rate

Year-End 2010

(1)

•

33.6 Mmboe

(201.7Bcfe)

o

42% proved developed

o

37% oil & NGLs

o

85% liquids rich capture

Year-End 2009

(2)

•

20.9 Mmboe

(125.2 Bcfe)

•

$190.5 million PV-10

o

54% proved developed

o

55% oil & NGLs

Year-End 2008

(3)

•

10.9 Mmboe

(65.4 Bcfe)

•

$84.0 million PV-10

o

62% proved developed

o

52% oil

1. Year-end 2010 reserves calculated using $75.96 per Bbl and $4.38 per Mcf.

2. Year-end 2009 reserves calculated using $57.65 per Bbl and $3.87 per Mcf.

3. Year-end 2008 reserves calculated using $41.00 per Bbl and $5.71 per Mcf.

8

2010 Reserves by Asset Region

PDP

PDNP

PUD

Total

(1)

Total Appalachia

27,227

9,022

116,407

152,656

Conventional

6,015

-

-

6,015

Marcellus

21,212

9,188

116,407

146,808

Illinois

48,857

-

-

48,857

Total

76,084

9,022

116,407

201,679

1. Year-end 2010 reported in Mmcfe

Total Proved Reserves

Proved Developed Producing Reserves

9

2011 Capital Budget

2011 Capital Budget

•74%

of the total budget is allocated to oil and liquids rich gas operations.

•65% of the Appalachian budget is dedicated to liquids rich Butler County operations.

10

1. Including the $30M drilling carry, the 2011 budget would be $178.8M.

2011 Capital Budget

2011 Capital Budget

11

Current Hedging Summary

Current Hedging Summary

Current Production Hedged

•

Percentage of production hedged based on December,

2010 exit rate with built in decline

12

1.

~30% of current natural gas production covered in 2011 by put spread with a $3.84 short put price for a $1.04 put spread

2.

~21% of current natural gas production covered in 2011 by put spread with a $4.00 short put price for a $1.75 put spread

(1)

(2)

Marcellus Overview

Marcellus Overview

Butler County (Operated)

•

49,400 gross (34,100 net) acres

•

Joint Venture with Sumitomo in Butler County

o

70% Rex / 30% Sumitomo

o

$14.2 million in Sumitomo drilling carries remaining

•

Butler Midstream Joint Venture

o

60% Stonehenge / 28% Rex / 10% Sumitomo

o

Operation of 40 Mmcf/d

cryogenic plant

o

Pipeline infrastructure

Westmoreland, Centre, and Clearfield Counties

(Non Operated)

•

49,000 gross (19,700 net) acres

•

Joint Venture among Williams, Rex, and Sumitomo

o

50% Williams / 40% Rex / 10% Sumitomo

o

JV includes interest in gathering and transportation

o

$15.8 million in Sumitomo drilling carries remaining

Other Operated Marcellus Acreage

•

17,900 gross (2,700 net) acres in areas of Clearfield,

Centre, Somerset and Fayette counties

13

1. Assumptions based on full development program. Individual well results may vary significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3.

2. Includes approximately 129 Bcfe of Marcellus Shale proved reserves as of December 31, 2010

Marcellus Operated Overview

Marcellus Operated Overview

Butler County, PA

•

2010 Operational Highlights

o

Drilled 15 (10.5 net)  wells in 2010, completed 8 gross

(5.6 net)

o

Placed in service 4 gross (2.8 net) wells

o

Sarsen

plant operational, currently at 30 Mmcf/d

o

49,400 gross (34,100 net) acres

•

2011 Operational Assumptions

o

Drilling the full year with one rig, and second rig by

mid year

o

Drill 24 gross (15 net) wells

o

Fracture and complete at least 24 gross (15 net) wells

o

Construction of the second 40.0 Mmcf/d

cryogenic

plant, proposed commissioning in first quarter 2012

o

Primary leasing strategy will fill in future drilling units,

and other contiguous acreage blocks within the core

operational area

Marcellus Operated Area in PA

14

•

Core acreage position of 30,500 gross (21,400net) acres

o

Allows for minimal rig movement

o

Decreases in drilling time

o

Maximizes unitized acreage

•

Close access to infrastructure and pipelines

•

Terrain composition very accessible

•

Low risk geological area

•

Additional production possibilities in the Utica and

Upper Devonian Shale

•

Maintaining two

rig drilling program allows for

minimal

lease expirations

Why Rex Values its Presence in Butler County

Why Rex Values its Presence in Butler County

Prospective Butler Units

15

•

Inventory of 400 potential drilling locations

•

Favorable commodity price differentials

Marcellus Non-Operated Overview

Marcellus Non-Operated Overview

16

Conceptual Marcellus Economics

Conceptual Marcellus Economics

Butler County (Wet Gas) Assumptions

(1)

•

2.5 MMcf/d

IP Rate

•

4.4 Bcfe

gross EUR

•

$4.7 million drilling and completion costs

•

15% royalties

•

Gas Price Basis Adjustment: $0.26/Mcf

•

NGL

&

condensate

volumes:

1.64

gallons

per

Mcf

(~39

Bbls

per

MMcf)

•

NGL price assumptions:  $0.76/gal (~40% of NYMEX oil price)

•

Gathering transportation & operating expenses: $1.50/Mcf

Westmoreland & Central PA (Dry Gas)

Assumptions

(1)

•

3.5 MMcf/d

IP Rate

•

3.0 Bcf

gross EUR

•

$4.7 million drilling and completion costs

•

15% royalties

•

Gas price basis adjustment: ($.09)/Mcf

•

Gathering transportation & operating expenses: $0.67/Mcf

1. Based on the 2010 reserve report

17

Marcellus Well Cost Comparison

Marcellus Well Cost Comparison

Reserve Well Economics

•Average Well Cost of $4.7 million

•Average

Drilling

and

Completion

cost

-

$1.9

million

•Average

Frac

Cost

-

$2.2

million

•Average

Equipment

cost

-

$0.6

million

1

Results from the 2010 Drilling Program

18

Niobrara Overview

Niobrara Overview

DJ Basin Niobrara Summary

•

Thick “Source Rock”

–

300+ ft. 

•

High total organic content (TOC’s) of 2-10%

•

Strong matrix contribution from high porosity chalks

•

Production likely influenced by faults and fractures

•

Mature over large areal extent

•

Expected well costs of $3.5 -

$4.2 MM

DJ Basin

Rex Energy

Silo State 41-22H

201 BOE/d Test Rate

Rex Energy

BJB #1H

Drilled and Completed,

Recovering Load

Rex Energy

Herrington Farms 1H

450 BOE/d Test Rate

19

1. Assumptions based on full development program. Individual well results may vary significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3.

~65,400 gross (45,000 net) acres

•

3 horizontal wells drilled, fractured and recovering load

Conceptual Niobrara Economics

Conceptual Niobrara Economics

Niobrara Horizontal Well Assumptions

•

400 Bbls/d

IP

•

Gas sales start 18 months after oil sales

•

$4.2 million drilling and completion costs

•

18% royalties

•

Oil price basis adjustment: -$9.00/Bbls

•

Gathering transportation & operating expenses:

$13.00/Bbls

•

Severance & ad valorem taxes: 13%

Silo Field Type Curve

Before Tax IRR

20

Lawrence Field ASP Overview

Lawrence Field ASP Overview

~ASP Project Summary

Illinois Basin

~13,100 gross (13,000 net) acres in Lawrence Field

•

1 billion barrels of original-oil-in-place (OOIP)

•

Field

has

produced

400

MMBbls

since

1906

•

Wateflooded

in the 1950’s

•

Two successful surfactant-polymer flood pilots  completed by Marathon

with 15-20% of OOIP recovered

•

Field currently produces ~1,600 gross (1,250 net) barrels per day under

waterflood

Middaugh

Unit, ASP

Project

21

1. Pore volume recovery assumptions based on full development program. Individual ASP unit results may vary significantly. Not proved. See “Hydrocarbon Volume Estimates” on page 3. 

•

ASP stands for Alkali-Surfactant-Polymer flood

•

Alkali-Surfactant mix reduces interfacial tension allowing remaining oil to flow easier through the formation

•

Polymer improves sweep efficiency by forcing fluid into parts of the field not effectively swept by the waterflood

•

Based on NSAI geological analysis and high grading of the acreage, 27 separate ASP units have been designed to date. 

•

Laboratory analysis on the effect of ASP flooding of cores from the field recovered 23% of OOIP (16% PV

(1)

Recovery)

•

Single well pilot test of ASP flooding in the field recovered 27% of OOIP (20% PV

(1)

Recovery)

•

Injecting chemicals on 15-acre unit with initial response expected in late first quarter 2011 to early second quarter 2011

•

Currently at 25% of pore volume (PV) injected ASP slug, currently injecting polymer push

ASP Conceptual Economics

ASP Conceptual Economics

Typical ASP Flood IRR vs

Oil Price at Various PV Recoveries

22

Total ASP Potential Reserves at Various PV Recoveries

1. Estimated by Netherland, Sewell & Associates, Inc. Does not represent proved reserves. See “Hydrocarbon Volume Estimates” on page 3.

•

Capital for the ASP plant has already been spent

•

90% of future capital will be chemical costs

•

North & Central areas of the field have been analyzed to date (~75% of the field)

o

Identified 18 target continuous sand bodies and broke these down into 27 separate

flood units (15 Bridgeport/12 Cypress)

o

Base case probable reserves in identified floodable sands: 39.4 MMBbls

(1)

in the 

Northern & Central areas of the field at a 13% PV Recovery

•

Operationally

o

Estimated

annual

production

growth

of

71%

-

95%

in

2011

o

74% of 2011 capital budget allocated to oil and liquids rich operating areas

o

Strong growth with a historical reserve CAGR of 75%

o

Encouraging Niobrara results

o

Additional potential in the Utica and Upper Devonian shale

o

4 rig program in 2011

o

Large inventory of drilling locations

•

Financially

o

Conservative balance sheet

o

Total line of credit availability of $115 million

o

Diversified portfolio with both oil and gas

o

Strong hedging position

Why Invest in Rex Energy?

Why Invest in Rex Energy?

23