Rex Energy 8-K This document contains forward-looking statements. All statements other than statements of historical

Corporate Presentation

April 2009

Exhibit 99.1

Forward Looking Statements

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2

This document contains forward-looking statements. All statements other than statements of historical

facts included in this document, including but not limited to, statements regarding our future financial

position, business strategy, budgets, projected costs, savings and plans and objectives of management

for future operations, are forward-looking statements. Forward-looking statements generally can be

identified by the use of forward-looking terminology such as “may,”

“will,”

“expect,”

“intend,”

“estimate,”

“anticipate,”

“believe”

or “continue”

or the negative thereof or variations thereon or similar

terminology. These forward-looking statements are subject to numerous assumptions, risks and

uncertainties. Factors which may cause our actual results, performance or achievements to be materially

different from any future results, performance or achievements expressed or implied by us in those

statements include, among others, (i) the quality of our properties with regard to, among other things,

the existence of reserves in economic quantities, (ii) uncertainties about the estimates of reserves, (iii)

our ability to increase our production and oil and natural gas income through exploration and

development, (iv) our ability to successfully apply horizontal drilling techniques and tertiary recovery

methods, (v) the number of well locations to be drilled and the time frame within which they will be

drilled, (vi) the timing and extent of changes in commodity prices for crude oil and natural gas, (vii)

domestic demand for oil and natural gas, (viii) drilling and operating risks, (ix) the availability of

equipment, such as drilling rigs and transportation pipelines, (x) changes in our drilling plans and related

budgets

and

(xi)

adequacy

of

our

capital

resources

and

liquidity

including,

but

not

limited

to,

access

to

additional borrowing capacity. Because such statements are subject to risks and uncertainties, actual

results

may

differ

materially

from

those

expressed

or

implied

by

the

forward-looking

statements.

You

are cautioned not to place undue reliance on such statements, which speak only as of the date of this

document. Unless otherwise required by law, we undertake no obligation to publicly update or revise

any forward-looking statements, whether as a result of new information, future events or otherwise.

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3

Rex Energy Overview

•

Market Cap

(1)

: $115 million

•

Total Debt

(2)

: $5 million

•

Cash on Hand

(2)

: $4 million

•

Proven Reserve Base

(3)

:

11.0 Mmboe

(65.9 Bcfe)

53% oil

65% proved developed

•

Average Daily Production

(2)

:

2,579 BOE (78% oil)

Lawrence Field

ASP Flood

Project

~87,000 gross

(65,000 net)

Marcellus Shale

“Fairway”

acres

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Hedges & Price Analysis

Year

Volume

% of Current Avg.

Production

Average Floor

Average Ceiling

Crude Oil

Apr -

Dec ‘09

468 MBbls

86%

$63.35

$75.57

2010

588 MBbls

88%

$62.71

$79.31

Natural Gas

Apr -

Dec ‘09

720 MMcf

78%

$7.00

$8.88

2010

960 MMcf

87%

$7.56

$10.48

2011

720 MMcf

72%

$8.00

$14.75

2008 Prices

Received

2008 Avg. NYMEX

Settlement Prices

Diff

% Diff.

Crude Oil

$95.63

$99.64

$ (4.00)

(4) %

Natural Gas

$9.44

$9.04

$ 0.40

4 %

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Proven Reserve Analysis

The company announced a reduction in year-end reserves from continuing

operations as of December 31, 2008 of approximately 22% due predominately

to a 54% reduction in the oil price assumption used in the estimates.

On a commodity price normalized case, using 2007 year-end prices

(1)

, proven

reserves would have risen ~19% to 16.7 MMBOE, producing a 376% reserve

replacement ratio and F&D costs of $12.77/BOE ($2.13/Mcfe).

1. $92.50/Bbl and $6.95/Mcf

Oil (MBbls)

Gas (MMcfe)

BOE (MBOE)

December 31, 2007

11,962

12,716

14,081

Plus Extensions & Discoveries

165

–

165

Plus/ (Less) Revisions of Previous Estimates

(5,550)

1,812

(5,248)

(Less) 2008 Production

(776)

(1,037)

(949)

December 31, 2008

5,994

30,019

10,997

Historical Highlights

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Capital Budget & Liquidity

•

Capital Budget

$49 million exploration & development budget

70% allocated to Marcellus Shale

•

Liquidity

$5

million

drawn

on

line

of

credit

with

$80

million

borrowing

base

(1)

•

Used net proceeds from Permian Basin divestiture to pay down debt

Approximately 85% of current production is hedged through 2010

•

Crude Oil average floor: $62.99

•

Natural Gas average floor: $7.32

$4

million

cash

on

hand

(1)

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1. As of first quarter 2009. Unaudited.

Marcellus Shale Overview

•

Rex Energy has leased approximately 87,000 gross (65,000 net) acres in areas of active

Marcellus Shale exploration in Pennsylvania.

•

Approximately 13% of acreage is held by production, and high percentage of

undeveloped acreage has ~5 years remaining on primary term.

•

Completed five vertical wells to date achieving a 1.8 MMcf/day initial rate on most

recent.

•

Independent evaluation by Schlumberger Data & Consulting Services indicates ~951

Bcfe

of

proved,

probable

&

possible

reserves

(16.4

Bcfe

proved).

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Marcellus Shale Gas Marketing

•

Butler County

Phase I of processing plant nearing completion

•

3 –

5 MMcfd

initial capacity with ability to scale up to 25 MMcfd

Dominion line

•

Tap in place for initial capacity of up to 15 MMcfd

•

Approximately 1 mile from acreage

•

Westmoreland County

Dry Gas/ Treatment Plant Not Required

Dominion/Peoples Line

•

2 Taps in place with up to 18 MMcfd

capacity

Equitrans

line

•

Approximately 4 miles from acreage

•

Installing 2 taps with up to 8 MMcfd

capacity each

Texas Eastern line

•

Approximately 8 miles from acreage

•

Rights of way in place for future capacity needs

•

Clearfield/Centre County

Dry Gas/ Treatment Plant Not Required

Columbia 1711 line

•

Approximately 1 mile from acreage

•

Tap

site

secured.

Tap

being

installed

3

quarter

2009

with

up

to

50

MMcfd

initial capacity

Dominion line

•

Approximately 12 miles from acreage for additional future capacity needs

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rd

2009 Marcellus Drilling

•

Drill 6-8 horizontal wells

2,500 –

3,000 foot laterals

5 –

8 stage completions

•

Union Drilling Fit-for-Purpose Rig

Delivered

•

First well spud in April in Butler

County, PA

•

Move rig to Westmoreland County in

mid to late second quarter 2009

•

Finish in Clearfield County late second

half of 2009

•

Drilling permits in hand for 2009

program

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Assumptions:

•Horizontal Well

•Working Interest: 100%

•Revenue Interest: 84%

•D&C Cost: $4.0 MM

•Lease Costs: $320,000

(2)

•Lift Costs: $3,000/mo

•Type Curve: Hyperbolic

(Barnett Type)

1. Does not represent proven reserves.  Our results may vary significantly.

2. Assumes 160 acres at $2,000 per acre.

12

Conceptual Marcellus Economics

(1)

Illinois Basin Operations

•

Largest oil producer in the Illinois

Basin

•

Drilling success rates of greater

than 99% in numerous shallow

pay zones

•

Tertiary recovery potential with

Alkali-Surfactant-Polymer flooding

•

Inventory of 175 gross (174 net)

PUD & PDNP locations with

multiple non-proved offset

locations

Average Well Depth: 1,500 feet

Average Well Cost: $180,000

Average IP Rate: 15 –

30 Bbls/day

Average Net Reserves per Well:

11,900 BBls

Average F&D Costs: $15.00/Bbl

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Lawrence Field

•

Discovered in 1906, the Lawrence Field is

believed to have original oil in place of

approximately one billion barrels. The field has

the largest cumulative production in the State

of Illinois, totaling over 400 MMBbls.

•

We own and operate approximately 13,500 net

acres of the Lawrence Field.

•

The Cypress formation has yielded an

estimated 200 MMBbls in the Lawrence Field.

The Bridgeport formation is Pennsylvanian in

age and has yielded an estimated 140 MMBbls.

•

Secondary recovery by water flooding was

initiated in the mid-1950s throughout the

Pennsylvanian and Mississippian sections.

•

There have been two successful Surfactant-

Polymer pilot tests in the field to date done by

Marathon in the 1970s and 1980s (one each in

the Cypress and Bridgeport zones).

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Lawrence Field

Lawrence Field ASP Project

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•

We are implementing an Alkali-Surfactant-Polymer (“ASP”) Flood project in the

Cypress and Bridgeport Sandstone reservoirs of the Lawrence Field acreage.

•

ASP technology uses similar mechanisms to mobilize bypassed residual oil as previous

surfactant polymer floods conducted in the 1960s, 1970s and 1980s but at

significantly lower costs.

•

Rex Energy completed 26 core-flood tests with ASP chemicals from cores taken in the

Lawrence

Field

which

achieved

recoveries

of

up

to

21%

and

24%

of

the

original

oil

in

place in the Cypress and Bridgeport Sandstones respectively.

•

During 2008, Rex Energy completed construction of an ASP injection plant in the

Lawrence Field and commenced ASP injection operations in May 2008 on two pilot

3.6 acre tests (Bridgeport and Cypress Sandstones).

•

Each pilot consists of four injector wells and five producing wells in a 5-spot pattern.

•

Based on detailed geological mapping and ASP core studies done in the field,

Netherland

Sewell

&

Associates

has

identified

27

units

with

~

40

MMBbls

in

potential

reserves recoverable through ASP flooding in only the northern and central portion of

the field.

High Interfacial Tension

Oil is trapped by pore

throat restriction

Alkali +

Surfactant =

synergistic

interfacial

tension

reduction

Low Interfacial Tension

Oil passes through pore

throat restriction

The ASP process uses 3 chemicals to recover by-passed oil in the reservoir:

Poor Sweep Efficiency

Improved Sweep

Efficiency

16

The ASP Process

•

Alkai:

Alters rock wettability

Reacts with oil to form

natural surfactants

Adjusts pH and

salinity

Alters rock chemistry,

reducing absorption

•

Suractant:

Reduces oil-water

interfacial tension

•

Polymer:

Thickening agent to

improve mobility

control for improved

sweep efficiency

17

Robins Surfactant-Polymer Pilot

•

In 1982, Marathon began a

25-acre, surfactant-

polymer pilot on the

Robins Lease in the

Lawrence Field

•

The project produced an

estimated 450,000

incremental barrels from

25-acres within the 13,500

acres of the Lawrence Field

•

During the 6 year period of

chemical injection, the

production rose from 7

Bbl/day to 370 Bbl/day

and the oil cut increased

from 1% to ~23%

•

The project recovered an

incremental 21% of the

original oil in place

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Oil

Production

&

Oil

Cut

Plot

of

Robins

102-B

25-Acre

Surfactant-Polymer

Pilot

18

Rex Energy ASP Pilots

•

Bridgeport Sandstone Pilot (3.6 acres)

•

Chemical injection commenced May 1, 2008

•

Analysis indicates up to 80% of the residual oil was

swept through the ASP process

•

Highest recorded oil cut to date achieved by any

well in the pilot was ~15%

•

Oil production rose from ~1 barrel per day to a

peak of ~65 barrels per day

•

Cypress Sandstone Pilot (3.6 acres)

•

Chemical Injection commenced May 1, 2008

•

Analysis indicates reservoir heterogeneity

adversely effected sweep efficiency

•

Highest recorded oil cut to date achieved by any

well in the pilot was ~20%

•

Oil production rose from ~2 barrel per day to a

peak of ~28 barrels per day

•

Sweep efficiency continues to improve when

polymer only phase commenced in December

2008

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Why Invest in Rex Energy?

•

Current enterprise value of ~$115 million values only the proven reserves at

$10.45/BOE ($1.74/Mcfe), excludes any value for:

87,000

gross

(65,000

net)

Marcellus

Shale

“fairway”

acres

Lawrence Field ASP Flood potential

•

Strong Financial Position:

$5 million in debt drawn on line of credit with $80 million borrowing base as of

March 31, 2008

(1)

Strong hedging position with 76% current production hedged through 2010

$4

million

in

cash

on

hand

as

of

March

31,

2008

(1)

•

Significant Growth Opportunities:

Marcellus Shale potential on 87,000 gross (65,000 net) acres in Pennsylvania

Significant upside potential through ASP flooding in the Illinois Basin

Low risk developmental drilling inventory

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1. As of first quarter 2009. Unaudited.