Rex Energy 8-K Regulation FD Disclosure

CORPORATE

CORPORATE

PRESENTATION

PRESENTATION

SEPTEMBER 2007

SEPTEMBER 2007

CORPORATION

NASDAQ: REXX

Exhibit 99.1

2

Forward-Looking Statements

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.

3

REX ENERGY CORPORATION KEY STATISTICS

REX ENERGY CORPORATION KEY STATISTICS

Approx. 6%

Debt to Market Cap Ratio

Approx. 6%

Debt to Assets Ratio

Approx. $250 million

Total Assets

Appalachian Basin, Illinois Basin, Permian

Basin

Areas of Operation

394,000 gross (170,000 net)

Total Acreage

77%

% Proved Developed

81%

% Oil

14.5 MMBOE

Proved

Reserves

2

Approx. $250 million

Market Cap

1

30.8 million

Shares Outstanding

Approx. $15 million

Senior Debt

NASDAQ: REXX

Listing

1.

Market Cap as of September 2007, based on stock price of $8.00 and 30,794,702 shares outstanding.

2.

Prepared

by

Netherland,

Sewell

&

Associates,

Inc.

as

of

December

31,

2007.

4

Southwest Region

Southwest Region

•

Average Net Production

(1)

(BOE per day): 245

•

Total Proved Reserves

(2)

(MMBOE): 2.0

•

Pre-Tax PV-10

(2)

(in millions) $17.1

•

Several active drilling projects

•

Waterflood

project in Azalea Field

Illinois Basin

Illinois Basin

•

Average Net Production

(1)

(BOE per day): 2,081

•

Total Proved Reserves

(2)

(MMBOE): 10.8

•

Pre-Tax PV-10

(2)

(in millions) $165.5

•

The leading oil producer in the basin

•

Long-life oil properties

•

New Albany Shale Drilling on over 270,000 gross

acres

•

Tertiary Recovery (ASP) Project

Appalachian Basin Basin

Appalachian Basin Basin

•

Average Net Production

(1)

(BOE per day): 316

•

Total Proved Reserves

(2)

(MMBOE): 1.7

•

Pre-Tax PV-10

(2)

(in millions) $17.7

•

Long-life natural gas properties

•

Several Active Developmental Drilling Projects

•

Marcellus Shale Drilling Potential

1.

As ofJune

30, 2007

2.

Prepared by Netherland

Sewell & Associates as of December 31, 2007

COMPANY OVERVIEW

COMPANY OVERVIEW

5

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

Millions

2004

2005

2006

YTD JUN-

07

0

100

200

300

400

500

600

700

800

2004

2005

2006

YTD JUN-

07

Revenue Growth

Production Growth

EBITDAX Growth

Proved Reserves Growth

1.

Revenue excluding unrealized gains or losses from hedges 

2.

Compound Annual Growth Rate

HISTORICAL HIGHLIGHTS

HISTORICAL HIGHLIGHTS

0

2

4

6

8

10

12

14

16

2004

2005

2006

CAGR²

= 69%

1

CAGR²

= 80%

CAGR²

= 43%

CAGR²

= 88%

$0

$5

$10

$15

$20

$25

$30

$35

$40

Millions

2004

2005

2006

YTD JUN-

07

6

Significant Reserve Base with Stable Production

–

14.5 MMboe of proved reserves, with “long-life”

production, in Illinois Basin, Appalachia and Southwestern region

–

Leading oil producer in Illinois Basin

(provides premium pricing, unique local knowledge, advantaged consolidator position)

Significant Production and Reserve Growth Opportunities from Broad Project Inventory

–

Lawrence Field ASP Flood Project in Illinois

–

New Albany Shale acreage position of over 270,000 gross acres in

southern Indiana

–

Natural gas drilling opportunities, including the Marcellus Shale, in the Appalachian Basin

–

Conventional

oil

drilling

opportunities

in

the

Illinois

Basin,

including

500

proven

undeveloped

and

proven

developed

non-producing locations in Illinois & Indiana

–

Nine active oil and gas exploration and development projects in the Permian Basin

Financial Flexibility to Support Growth

–

6% debt to market capitalization ratio with approximately $15 million in total debt

–

Cash flows able to fund significant portion of planned capital expenditures

–

Closing on new $200 million credit facility with $75 million initial borrowing base

Experienced Management Team with Proven Track Record Creating Value for Investors

–

Management team has built high-quality asset base through acquisitions and development, creating significant value

for investors

–

Technical team of geologists and engineers average over 20 years

of experience

–

17 acquisitions completed to date by the management team at average cost of $6.99 per proved BOE

Management and Board Aligned with Stockholders

–

Directors, officers and their affiliates own over 50% of the shares outstanding

KEY VALUE DRIVERS

KEY VALUE DRIVERS

7

Employ Technological Expertise

–

Utilize and expand the technological expertise that has enabled a drilling success rate of over 95% during the last

three years, improved operations and enhanced field recoveries

Develop Existing Properties

–

The Alkali-Surfactant-Polymer (“ASP”) Flood project in the Lawrence Field, the largest field in the Illinois Basin

–

New Albany Shale resource play with over 270,000 gross acres

–

Marcellus Shale resource play with over 53,000 gross acres in areas of active exploration

–

Diverse inventory of over 500 Proved Undeveloped locations and Proved Developed Non-Producing wells

Pursue Strategic Acquisitions and Joint Ventures

–

Continue to acquire and lease additional natural gas and oil properties in core areas of operation

–

Rex’s strong history of acquisitions, leading position in the Illinois Basin and technical expertise will continue to

attract industry joint venture partners and acquisition opportunities

Focus on Operations

–

Focus future acquisition and leasing activities on properties where Rex Energy has a significant working interest

and can operate the property to control and implement the planned exploration and development activity

Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations

OUR GROWTH STRATEGY

OUR GROWTH STRATEGY

8

The largest oil producer in the Illinois Basin with

gross daily production of approximately 2,800

barrels per day

Wells produce 30 to 50 years

Drilling success rates of greater than 99% in

shallow zones

ASP Flood project in Lawrence Field

–

Largest Field in Illinois Basin

–

Estimated 1 billion barrels of original oil in

place, approximately 40% produced to date

–

Two successful Surfactant-Polymer pilots in

the field to date

Over 270,000 gross acres (89,000 net) in southern

Indiana, being developed for the New Albany

Shale on 320 acre spacing

Several ongoing shallow oil developmental drilling

projects with over 500 PUD, PDNP locations with

multiple non-proved offset locations

ILLINOIS BASIN OPERATIONS

ILLINOIS BASIN OPERATIONS

100%

% Crude Oil:

18 yrs.

Reserve Life:

2,081 Bbls

2

nd

Quarter 2007 Average

Daily Net Production:

10.8 MMBbls

12/31/06 Proved Reserves:

Proved Reserves

9

Implementing an ASP Flood project in the

Cypress and Bridgeport Sandstone

reservoirs of the Lawrence Field acreage

–

Own and operate 21.2 square miles

(approximately 13,500 net acres),

accounting for approximately 85% of the

current total gross production from this

field

–

Estimated original oil in place of 1 billion

barrels with approximately 400 million

barrels of oil produced to date

–

The Cypress (Mississippian) and the

Bridgeport (Pennsylvanian) sandstones

are the major producing horizons in the

field

–

Two successful surfactant-polymer pilot

tests in the field to date (one each in the

Cypress and Bridgeport Zones)

ASP Flood is an Enhanced Oil Recovery

(“EOR”) project

LAWRENCE FIELD ASP PROJECT

LAWRENCE FIELD ASP PROJECT

Typical Field Recovery, % of Original Oil in Place¹

1.

Typical primary and secondary recovery of OOIP from the Bridgeport and Cypress formations as estimated by the US DOE, with tertiary

recovery based on EOR project results in the Lawrence Field.

Remaining

Unrecoverable

Oil (with

current

technologies)

Primary

Recovery

10%-20%

Secondary

Recovery

20%-30%

EOR/Tertiary Recovery

15%-30%

10

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

polymer floods conducted in the 1960s, 70s and 80s but at significantly lower costs

The

process

has

been

applied

in

numerous

fields

around

the

world

resulting

in

significant

incremental recoveries of oil  

Chemicals used in the ASP flood are:

–

An alkali (NaOH or Na2CO3),

–

A surfactant, and

–

A polymer (Polyacrylamide)

ASP technology achieves its incremental recovery by reducing capillary forces that trap oil,

improving aerial and vertical sweep efficiency and reducing mobility ratio

The alkali (.75% to 1.5%) and surfactant (0.15% to 0.25%) combination washes residual oil from the

reservoir

mainly

by

reducing

interfacial

tension

between

the

oil

and

the

water 

The

polymer

(800

to

1,400

parts

per

million)

is

added

to

improve

sweep

displacement

efficiency 

THE ASP (ALKALI-SURFACTANT-POLYMER) PROCESS

THE ASP (ALKALI-SURFACTANT-POLYMER) PROCESS

11

ILLINOIS BASIN SURFACTANT POLYMER FLOODS

ILLINOIS BASIN SURFACTANT POLYMER FLOODS

During the 1960s through the 1980s Marathon, Texaco, Exxon and Shell developed a number of

surfactant-polymer

projects

in

the

Illinois

Basin;

Marathon,

using

their

patented

Maraflood©

process,

developed most of these projects

Most

of

the

projects

demonstrated

technical

success

by

producing

incremental

oil

of

15-25%

of

original

oil in place, however, the chemical cost per incremental barrel of oil ranged from $10-$25 due to the

high quantity of surfactant used at a time when oil prices were low 

In the 1980’s Marathon conducted a 25-acre, micellar polymer project on our Robins lease within the

13,500 acres of the Lawrence Field we own 

0

100

200

300

400

Jan-82

Jan-84

Jan-86

Jan-88

Jan-90

Jan-92

Jan-94

Jan-96

Jan-98

Lawrence Field Robbins  Lease Maraflood©

Surfactant Polymer Flood Project

After many years of

waterflooding, production on

the lease had declined to 7

BOPD and with a 99%

watercut

During the six year period of

the surfactant polymer

injection, the production rose

to 370 BOPD and the oil cut

increased from 1% to 21%

The project produced an

estimated 459,000

incremental barrels, or an

estimated 21% of the original

oil in place

12

Our goal is to duplicate the oil recovery performance of the surfactant polymer floods conducted in the

field

in

the

1980s,

but

at

a

significantly

lower

cost;

This

cost

reduction

will

be

accomplished

by

using

alkali in the formula to lower the concentration of the more costly surfactant

Results of 2000 study by PennTex Illinois, the U.S. Department of Energy and Surtek, Inc.

–

Based on modeling and laboratory tests, oil recovery in the field could be increased significantly by

installing an ASP flood

–

Similar ASP projects successfully demonstrated recovery of an additional 15% to 30% of the

original oil in place

In 2006, we commissioned a study and assessment of our planned ASP pilot tests with Surtek.  Based

on Surtek’s recommendations, the company drilled and cored the central producing well in each of the

two pilot project areas and sent cores to Surtek for ASP chemical system design.

Rex Energy has drilled the remaining pilot wells and plans to begin injection of the chemicals in

December 2007 or January 2008 with initial production response expected in first half of 2008.

Pending results of these pilot projects, a broad ASP flood program will be implemented within the 13,500

net acres beginning in late 2008 or early 2009

LAWRENCE FIELD ASP FLOOD PROJECT

LAWRENCE FIELD ASP FLOOD PROJECT

13

Over 270,000 gross (89,000 net) acres

Over 800 potential gross locations based on 320 acre

spacing

Natural fractures believed to provide effective reservoir

permeability

Gas stored as free gas in fractures and adsorbed gas on

kerogen and clay surfaces

Interest in the potential of the New Albany Shale has

increased recently with application of horizontal well

techniques

Several large oil and gas companies are active in the

New Albany Shale in southern Indiana and northern

Kentucky, including:

–

Noble Energy, Inc.

–

El Paso Corporation

–

Chesapeake Energy Corporation

–

Quicksilver Resources, Inc.

Indiana

Ohio

Kentucky

New Albany Shale

NEW ALBANY SHALE PROJECT SUMMARY

NEW ALBANY SHALE PROJECT SUMMARY

14

1

2

2

3

4

5

3

6

7

Counties with Rex Energy New Albany Shale Acreage

9

3

3

3

NEW ALBANY SHALE ACREAGE & PROJECT AREAS

NEW ALBANY SHALE ACREAGE & PROJECT AREAS

1.

Rex/Aurora Pilot (Knox County)

2.

Rex/Aurora Pilot (Greene County)

3.

El Paso/Pogo Pilot (Davies & Martin Counties)

4.

Diversified Operating Pilot (Pike County)

5.

Rex/El Paso/Aurora Bogard Well (Greene County)

6.

Quicksilver NAS Field Area (Harrison County)

7.

Noble Energy Pilots (Sullivan County)

8.

Pioneer Oil Company (Owen County)

Acreage Summary

Project Map

Rex Energy

20,700

65.7%

Posey,

Gibson, &

Gallatin (IL)

Other Areas

Held by Rex

Production

271,500

Total

El Paso

Exploration &

Production Co.

8,735

10.1%

Greene

Bogard

Aurora Oil & Gas

(Rex Energy

managing drilling

operations)

70,000

29.8%

Washington,

Lawrence,

Jackson &

Orange

Lawrence

Aurora Oil & Gas

(Rex Energy

managing drilling

operations)

113,265

29.1%

Greene,

Sullivan, Clay

& Owen

Wabash

Rex Energy

40,800

26.8%

Knox

Western Knox

Rex Energy

18,000

40.0%

Knox

Eastern Knox

Operator

Gross

Acres

Average

Working

Interest

Counties

Project Name

15

Optimizes drilling geometry and pump placement for water removal

and reduction of back

pressure

Gravity drainage to sump at toe of lateral

Pump installed in open hole sump

REX ENERGY NEW ALBANY SHALE DRILLING TECHNIQUE

REX ENERGY NEW ALBANY SHALE DRILLING TECHNIQUE

6 1/8th”

Open Hole Lateral

Pilot Hole

for Horizontal

Well

Clegg Creek

Camp Run / Morgan Trail

Selmier

Blocher

7”

Casing Set at Top

New Albany Shale

Borden

Pump Set in Open

Hole Sump

Top of New Albany

16

118 gross producing wells in Texas

and New Mexico

Numerous opportunities in each

field due to large number of

productive formations in this prolific

basin

Net production of approximately 1.5

MMcfe per day of natural gas

equivalent

Five producing field acquisitions in

the last 24 months

Nine active developmental,

exploratory drilling and

redevelopment projects including

one waterflood

installation in the

Azalea Field.

SOUTHWEST REGION OPERATIONS

SOUTHWEST REGION OPERATIONS

Bison Project

Pecan Station Project

East Carlsbad Field

Azalea Field

N. Crows Nest Project

Preist-Beavers Project

Allison Field

New Batson Field

Dare I Cook & Hope Fields

58%

% Natural Gas:

21 yrs.

Reserve Life:

1.5 MMcf

2

nd

Quarter 2007 Average Daily

Production:

11.7 Bcfe

12/31/06 Proved Reserves:

Proved Reserves

17

CURRENT SOUTHWEST REGION PROJECT

CURRENT SOUTHWEST REGION PROJECT

New Batson Field

90% working interest in 29

well workover project and

multi-well drilling prospect to

Miocene and Frio formations

Dare I Cook & Hope Fields

87% working interest in

waterflood redevelopment and

polymer project

Pecan Station Project

100% working interest in 3-8

well drilling project to Strawn

formation

Bison Project

100% working interest in 6-8

well reentry and drilling project

to Strawn formation

East Carlsbad Field

33% working interest in

several workover opportunities

and increased density drilling

of the Cisco/Wolfcamp

formations

Allison Field

50% working interest in 15

well recompletion project and

multi-well drilling project to

Canyon, Fusselman

and

Leonard Sands

Azalea Field

95% working interest in

installation of waterflood of

Grayburg

formation

N. Crows Nest Project

100% working interest in 6

well Palo Pinto and Strawn

drilling prospect

Preist-Beavers Project

100% working interest in 10

well Queen Sand drilling

prospect

18

APPALACHIAN OPERATIONS

APPALACHIAN OPERATIONS

544 gross producing natural gas wells

with net average daily production of

approximately 1.9 MMcf

Wells produce 30 to 50 years

Drilling success rates of greater than

98% in shallow zones

Premium pricing of $0.10-$0.65 per

MMbtu

Low costs of operation

The Basin remains largely unexplored

for reserves below 6,000 feet; Shallow

wells (3,000-5,000 feet deep) typically

drilled on 40 acre spacing

Marcellus Shale potential on over

50,000 gross acres

Two active developmental drilling

projects with 150-250 drilling locations

as

of

2

nd

quarter

2007

Westmoreland Field

•

100% WI in 73 producing wells

and infrastructure

•

125-150 additional locations

targeting Upper Devonian

Sands on 2,100 undeveloped

acres

•

100% success rate on 20 wells

drilled since 2004

Fayette Field

•

16% avg. WI in 122 producing wells

•

JV with Range Resources

•

30-100 drilling locations on 12,900

(3,000 net) undeveloped acres

•

Target –

Berea, Fifth, Warren and

Speechley

Bradford Sands

•

96% success rate on 24 wells drilled

in 2006

100%

% Natural Gas:

25 yrs.

Reserve Life:

1.9 MMcf

2nd Quarter 2007 Average Daily Production:

10.2 Bcf

12/31/06 Proved Reserves:

Proved Reserves

19

We currently own 53,000 gross acres in Western

Pennsylvania where active exploration for the

Devonian (Marcellus) Shale is ongoing

The Marcellus Shale is a black, organic rich

shale formation located at depths between 7,000

and 8,500 feet and ranges in thickness from 100

to 150 feet

Range Resources Corporation (NYSE: RRC)

and Atlas Energy Resources, LLC (NYSE: ATN)

have announced successful tests 

87% of acreage held by production with

infrastructure in place allowing us to observe

others success & drilling process refinement

before exploring 

Currently leasing additional acreage

We own ~200 producing wells in northwest

Pennsylvania with Marcellus Shale formation

uphole

and logged

Premium to NYMEX pricing

MARCELLUS SHALE PROJECT SUMMARY

MARCELLUS SHALE PROJECT SUMMARY

Estimated Marcellus Shale Main Fairway

20

BUILT-IN FUTURE GROWTH

BUILT-IN FUTURE GROWTH

51 wells planned to be drilled or

recompleted

in 2007; 10

completed through June 2007

3 MMBOE

30,000 acres

Illinois Shallow Oil

Drilling

143 MMBOE

214,100 acres

Total

Currently evaluating acreage;

Plan to test in 2008

60 Bcf

(10 MMBOE)

39,000 acres

Marcellus (Devonian)

Shale

30-35 wells planned to be drilled

or recompleted

in 2007; eight

completed through June 2007

15 Bcfe

(3 MMBOE)

8,600 acres

Permian Basin Projects

30-35 wells planned for 2007; 13

drilled through June 2007.

17 Bcf

(3 MMBOE)

34,000 acres

Appalachian Basin

Shallow Conventional

Drilling

11 Wells drilled; Currently testing

stimulation; 8-10 additional wells

planned in 2007

240 Bcf

(40 MMBOE)

89,000 acres

New Albany Shale

Pilot wells drilled; injection to

begin Dec-07 or Jan-08

84 MMBOE

13,500 acres

Lawrence Field ASP

Project

Activity

Net Un-Risked

Reserve

(1)

Potential

Net Acreage

Project

1.

Net Un-Risked Reserve Potential does not represent proven reserves

21

EXPECTED 2007 CAPITAL EXPENDITURES

EXPECTED 2007 CAPITAL EXPENDITURES

Permian Projects

19%

ASP Project

15%

Illinois Shallow

Oil Drilling

28%

Acquisitions &

Leasing

5%

($5 million YTD)

New Albany Drilling

15%

Appalachian Shallow

Gas Drilling

18%

$40 -

45 million capital budget

$16 million incurred through June 2007

1

1.

Represents acquisitions & leasing year to date. We do not attempt to budget for future acquisitions.

22

3

rd

Quarter

and

Year-End

2007

OUTLOOK

$40 -

$45

$12 -

$15

Capital Expenditures (in millions)

2,800 –

3,300

2,730 –

2,820

Exit Rate (MBOE/d)

966 –

1,030

243 –

252

Oil Equivalent (MBOE)

1,000 –

1,200

260 –

280

Gas (MMcf)

800 –

830

200 –

205

Oil (Mbls)

Production:

Year-End 2007

3

RD

Quarter

2007

23

SUMMARY OF CURRENT HEDGING

SUMMARY OF CURRENT HEDGING

-

-

-

2010

$9.00

$7.00

600

2009

$9.19

$7.00

840

2008

$13.15

$7.55

420

Remainder of 2007

Avg. Ceiling

Price ($/Mcf)

Avg. Floor Price

($/Mcf)

Gas Hedged

(Mmcf)

$69.70

$61.10

360

2010

$66.55

$62.90

542

2009

$75.03

$63.48

573

2008

$65.12

$59.51

345

Remainder of 2007

Avg. Ceiling

Price ($/Bbls)

Avg. Floor Price

($/Bbls)

Oil Hedged

(Mbls)

24

Significant Reserve Base with Stable Production

–

14.5 MMboe of proved reserves, with “long-life”

production, in Illinois Basin, Appalachia and Southwestern region

–

Leading oil producer in Illinois Basin

(provides premium pricing, unique local knowledge, advantaged consolidator position)

Significant Production and Reserve Growth Opportunities from Broad Project Inventory

–

Lawrence Field ASP Flood Project in Illinois

–

New

Albany

Shale

acreage

position

of

over

270,000

gross

acres

in

southern

Indiana

–

Natural gas drilling opportunities, including the Marcellus Shale, in the Appalachian Basin

–

Conventional

oil

drilling

opportunities

in

the

Illinois

Basin,

including

500

proven

undeveloped

and

proven

developed

non-producing locations in Illinois & Indiana

–

Nine active oil and gas exploration and development projects in the Permian Basin

Financial Flexibility to Support Growth

–

6% debt to market capitalization ratio with approximately $15 million in total debt

–

Cash flows able to fund significant portion of planned capital expenditures

–

Closing on new $200 million credit facility with $75 million initial borrowing base

Experienced Management Team with Proven Track Record Creating Value for Investors

–

Management team has built high-quality asset base through acquisitions and development, creating significant value

for investors

–

Technical

team

of

geologists

and

engineers

average

over

20

years

of

experience

–

17 acquisitions completed to date by the management team at average cost of $6.99 per proved BOE

Management and Board Aligned with Stockholders

–

Directors, officers and their affiliates own over 50% of the shares outstanding

KEY VALUE DRIVERS

KEY VALUE DRIVERS

CORPORATION

NASDAQ: REXX

www.REXENERGY.com

26

APPENDIX: COMBINED STATEMENT OF OPERATIONS

APPENDIX: COMBINED STATEMENT OF OPERATIONS

(unaudited)

(in

thousands)

For the Three Months Ended

For the Six Months Ended

June 30,

June 30,

2007

2006

2007

2006

OPERATING REVENUE

  Oil and Natural Gas Sales

$    13,916 

$      9,812 

$    26,691 

$    18,980 

  Other Revenue

113 

            124 

            213 

            251 

  Realized Loss on Hedges

           (647)

        (1,631)

           (383)

        (3,021)

  Unrealized Loss on Hedges

        (3,298)

           (694)

        (6,734)

           (574)

       TOTAL OPERATING REVENUE

       10,084 

         7,611 

       19,787 

       15,636 

OPERATING EXPENSES

  Production and Lease Operating Expenses

         6,318 

         2,973 

       12,424 

         5,417 

  General and Administrative Expense

         1,632 

            812 

         3,614 

         1,655 

  Accretion Expense on Asset Retirement Obligation

            130 

               67 

            254 

            165 

  Exploration Expense of Oil and Gas Properties

         1,119 

                - 

         1,704 

                - 

  Depreciation, Depletion and Amortization

         3,705 

         1,734 

         7,654 

         3,701 

       TOTAL OPERATING EXPENSES

       12,904 

         5,586 

       25,650 

       10,938 

       INCOME (LOSS) FROM OPERATIONS

        (2,820)

         2,025 

        (5,863)

         4,698 

OTHER INCOME (EXPENSE)

  Interest Income

                (0)

               40 

                 1 

               76 

  Interest Expense

        (2,272)

        (1,199)

        (4,349)

        (1,965)

  Gain on Sale of Oil and Gas Properties

               15 

               91 

            192 

               91 

  Other Income (Expense)

             (41)

             (54)

             (85)

           (167)

       TOTAL OTHER INCOME (EXPENSE)

        (2,298)

        (1,122)

        (4,241)

        (1,965)

NET INCOME BEFORE MINORITY INTEREST

        (5,118)

            903 

      (10,104)

         2,733 

MINORITY INTEREST SHARE OF NET INCOME (LOSS)

        (2,546)

            629 

        (5,274)

         1,551 

      NET INCOME (LOSS)

$     (2,572)

$         274 

$     (4,830)

$      1,182 

27

APPENDIX: OPERATING ACTIVITY

APPENDIX: OPERATING ACTIVITY

(unaudited)

For the Three

For the Six

Months Ended

Months Ended

June 30,

June 30,

2007

2006

2007

2006

Production:

   Oil (Bbls)

197,174

121,210

398,594

234,637

   Natural gas (Mcf)

259,197

274,958

546,182

568,965

      Total (BOE)

a

240,373

167,036

489,624

329,464

Average daily production:

   Oil (Bbls)

2,167

1,350

2,202

1,298

   Natural gas (Mcf)

2,848

3,055

3,018

3,143

      Total (BOE)

a

2,641

1,859

2,705

1,822

Average sales prices:

   Oil (per Bbl)

$60.70 

$66.07

$57.31 

$62.33

   Natural gas (per Mcf)

$7.51 

$6.56 

$7.05 

$7.66

      Total (per BOE)

a

$57.89 

$58.65 

$54.51 

$57.61

Average NYMEX prices

b

   Oil (per Bbl)

$65.03 

$70.70

$61.65

$67.09 

   Natural gas (per Mcf)

$7.56 

$6.82

$7.26

$7.95 

a 

Natural gas is converted at the rate of six Mcf to one BOE and oil is converted at the rate

of one Bbl to one BOE

.

b

Based upon the average of bid week prompt month prices.

28

APPENDIX: COMBINED BALANCE SHEET

APPENDIX: COMBINED BALANCE SHEET

(unaudited

as

noted)

(in

thousands)

June 30,

December 31,

ASSETS

2007

2006

(Unaudited)

(Audited)

Current Assets

Cash and Cash Equivalents

$                      602 

$                       600 

Related Party Receivable

                          133 

                             2 

Accounts Receivable

                       6,500 

                        6,884 

Short-term Derivative Instruments

                          183 

                        1,275 

Inventory, Prepaid Expenses and Other

                       2,601 

                        1,520 

          Total Current Assets

                     10,019 

                      10,281 

Property and Equipment (Successful Efforts Method)

Evaluated Oil and Gas Properties

                   136,485 

                    127,370 

Unevaluated Oil and Gas Properties

                     12,093 

                      14,569 

Other Property and Equipment

                       3,868 

                        4,182 

Wells in Progress

                       3,253 

                        2,844 

Pipelines

                       2,148 

                        1,765 

          Total Property and Equipment

                   157,847 

                    150,730 

Less: Accumulated Depreciation, Depletion and Amortization

                   (24,674)

                    (17,715)

          Net Property and Equipment

                   133,173 

                    133,015 

Other Assets

Other Assets – Net

                       1,146 

                        1,172 

Long-term Derivative Instruments

                            - 

                           143 

          Total Other Assets

                       1,146 

                        1,315 

Total Assets

$               144,338 

$                144,611 

LIABILITIES AND EQUITY

Current Liabilities

Accounts Payable and Accrued Expenses

$                   9,493 

$                    8,336 

Short-term Derivative Instruments

                       3,507 

                        2,978 

Accrued Distributions

                            - 

                           102 

Lines of Credit

                     39,631 

                 ��    37,581 

Current Portion of Long-term Debt

                     24,035 

                        2,867 

Related Party Payable

                            50 

                        1,820 

          Total Current Liabilities

                     76,716 

                      53,684 

Long-term Liabilities

Long-term Debt

                     34,900 

                      44,961 

Other Loans and Notes Payable - Long-term Portion

                          386 

                           481 

Long-term Derivative Instruments

                       6,668 

                        1,698 

Participation Liability

                       2,141 

                        2,141 

Other Deposits and Liabilities

                          429 

                           405 

Asset Retirement Obligation

                       5,985 

                        5,269 

          Total Long-term Liabilities

                     50,509 

                      54,955 

Total Liabilities

$               127,225 

$                108,639 

Minority Interests

                     22,021 

                      36,589 

Owners' Equity

Common Stock

                              1 

                               1 

Additional Paid-in Capital

                       1,460 

                        1,460 

Accumulated Stockholders’ Equity (Deficit)

                        (393)

                         (581)

Partners' and Members' Equity (Deficit)

                     (5,976)

                      (1,497)

          Total Owners' Equity (Deficit)

                     (4,908)

                         (617)

Total Liabilities, Minority Interests and Owners' Equity (Deficit)

$               144,338 

$                144,611 

29

APPENDIX: EBITDAX RECONCILIATION

APPENDIX: EBITDAX RECONCILIATION

(unaudited) (in thousands)

Three Months Ended

June 30,

Six Months Ended,

June 30,

2007

2006

2007

2006

Net Income (Loss) before Minority Interests

$

(5,118   

)  

$

903

  $ 

(10,104

)

$

2,733

Add Back Depletion, Depreciation & Amortization

3,835   

1,801

7,908

3,866 

Add Back Interest Expense

2,272   

1,199

4,349

1,965 

Add Back Exploration & Impairment Expenses

1,119   

—    

1,704   

—  

Less Interest Income

—    

40

1

76 

Add Back Unrealized Losses from Financial

Derivatives

3,298

694

6,734

574

EBITDAX before Minority Interests

$

5,406   

$

4,557

  $ 

10,590

$

9,062 

“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, depreciation, depletion, amortization, unrealized losses from financial derivatives,

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 is not a calculation based on GAAP financial measures and should not be considered as an alternative to

net income (loss) in measuring our performance, nor used as an exclusive measure of cash flow, 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

statements

of

cash

flows.

We

have

reported

EBITDAX

because

it

is

a

financial

measure

used

by

our

existing

commercial

lenders

and

under

our

proposed

senior

credit

facility,

and we believe 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 our

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.

30

Experience

Title

Employee

Over 10 years of experience in finance and accounting

Served as Chief Financial Officer of Rex Operating from March

2004 -

Present, Vice President of Accounting for all Shaner

companies from January 1998 -

March 2004 and an officer in

charge of managing the accounting and financial activities of all

of the Rex Energy affiliated companies since 1996

Holds a Bachelor of Science degree in Accounting from the

University of Pittsburgh

Chief Financial Officer

Thomas C. Stabley

Over 20 years of experience in the oil & gas industry

Served as Chief Operating Officer of Rex Operating from March

2004 -

October 2006, President & Chief Operating Officer from

October 2006-Present, Chief Executive Officer of Douglas Oil &

Gas and its predecessor Douglas Oil & Gas, Inc. from January

1984 -

January 2002

Holds a Bachelor of Science degree in Petroleum and Natural

Gas Engineering from Pennsylvania State University

President, Chief

Operating Officer &

Director

Thomas F. Shields

Served as Chief Executive Officer of Rex Operating from

October 2006 -

Present, President of Rex Operating from March

2004 -October 2006, and Chief Financial Officer for Douglas Oil

& Gas from January 2001 -

January 2003

Served as an Officer in the United States Army for eight years

Earned a Bachelor of Science degree in Finance from

Pennsylvania State University

Chief Executive Officer

& Director

Benjamin W. Hulburt

APPENDIX: MANAGEMENT

APPENDIX: MANAGEMENT

31

Experience

Title

Employee

Over 20 years of experience in geology and exploration focusing

on the Permian Basin

Formerly Senior Geologist for Cimarex Energy Company, Senior

Geologist for Latigo Petroleum, Inc. and Exploration/Exploitation

Manager for Southwest Royalties, Inc.

VP, Geology &

Exploration, Southwest

Region

Mark H. Elliott

Over 20 years of experience in oil & gas operations and

engineering focusing on the Permian Basin

Formerly Senior Operations Engineer for Pogo Producing

Corporation, Senior Operations Engineer for Latigo Petroleum,

Inc. and Engineer for Saga Petroleum

VP, Southwest Region

District Manager

Joe Clement

Over 18 years of experience in oil & gas operations and geology

focusing on natural gas exploration & development projects in

the Appalachian & Illinois Basins

VP, Appalachian Basin

District Manager (New

Albany Shale Project

Manager)

Michael S. Carlson

Over 20 years of experience in oil & gas operations in the Illinois

Basin

Formerly General Manager for ERG Illinois, Inc. and Illinois

Basin Business Unit Manager for Plains Exploration and

Production Company

VP, Illinois Basin District

Manager

Jack S. Shawver

Over 10 years of experience in several roles, including: Senior

Associate for Hodgson Russ LLP, U.S. Army Military Prosecutor

and as Special Assistant United States Attorney for the U.S.

Department of Justice

EVP, Secretary and

General Counsel

Christopher K. Hulburt

APPENDIX: MANAGEMENT

APPENDIX: MANAGEMENT