Georesources (GEOI) 8-K Regulation FD Disclosure

GeoResources, Inc

Corporate Profile

IPAA 2009 OGIS San Francisco

September  2009

Exhibit 99.1

2

Forward-Looking Statements

Information herein contains forward-looking statements that involve significant

risks and uncertainties, including our need to replace production and acquire or

develop additional oil and gas reserves, intense competition in the oil and gas

industry, our dependence on our management, volatile oil and gas

prices, costs

associated with hedging activities and uncertainties of our oil and gas estimates

of proved reserves and reserve potential, which may be substantial. In addition,

all statements or estimates made by the Company, other than statements of

historical fact, related to matters that may or will occur in the future are forward-

looking statements. 

Readers are encouraged to read our December 31, 2008 Annual Report on

Form 10-K/A and any and all our other documents filed with the SEC regarding

information about GeoResources

for meaningful cautionary language in respect

of the forward-looking statements herein.  Interested persons are able to obtain

free copies of filings containing information about GeoResources, without

charge,

at

the

SEC’s

Internet

site

(http://www.sec.gov).

There

is

no

duty

to

update the statements herein. 

3

Key Investment Highlights

Value Creation

Experienced Management and Technical Staff

Prior Track Record of Growth, Profits and Liquidity

Strategically Located, Geographically Diverse Asset Base

Strong Growth with High Level of Operating Control

Active Hedging Program

Significant Identified Upside Potential

Developing Additional Prospects

Strong Financial Position

4

Balanced Growth Strategy

Asset

Rationalization

and

Exploitation

•

Selectively divest assets to upgrade portfolio.

•

Focus on fields and projects with development and exploitation

potential.

•

Re-engineering and development programs extend field life, increase

proved reserves, lower unit operating costs and enhance economics.

Cost Control

•

Target low operating and G&A costs.

•

Minimize drilling and development costs.

•

Promoting partners reduces costs and generates operating fees. 

•

Generate exploration projects.  Increase direct participation, with

growth.

•

Solicit partners on a promoted basis.

Exploration

•

Acquire operated properties with producing reserves and

development and exploration potential.

•

Solicit partners on a promoted basis.

Acquisitions

(1)

Includes

GEOI’s

share

of

partnerships’

reserves.

(2)

Proved reserves presented throughout this profile are estimated as of 7/1/2009 and  based on NYMEX strip pricing at 7/15/09.

(3)

January –

April 2009 average, pro forma for May 2009 acquisitions.

(4)

Acreage information estimated as of  7/1/09.  Maps herein exclude minor value properties.

5

Company Overview

Company Highlights

Direct

Direct+

Ownership

Partnership

(1)

Proved Reserves (Bcfe)

(2)

127.7

141.4

Oil

53%

49%

Proved Producing

62%

62%

Proved Developed

75%

75%

PV 10% (millions)

$375.1

$406.4

Production (Mmcfepd)

(3)

29.6

35.6

Operated

82%

82%

Gross Acreage

(4)

483,324

483,324

Net Acreage

(4)

224,377

234,427

6

Management History

2004-

2007

Southern Bay Energy, LLC

Areas of Operation:

Gulf Coast, Permian Basin

2000-2007

Chandler Energy, LLC

Areas of Operation:

Williston Basin, Rockies

1988-2000

Chandler Company

Areas of Operation:

Rockies, Williston Basin

1992-1996

Hampton Resources

Corporation

Areas of Operation:

Gulf Coast

1997-2001

Texoil Inc.

Areas of Operation:

Gulf Coast, Permian Basin

2001-2004

AROC Inc.

Areas of Operation:

Gulf Coast, Permian Basin,

Mid-Continent

•

Track record of profits and liquidity.

•

Long-term repeat investors.

•

Extensive industry and financial

relationships.

•

Significant operations and financial

experience.

•

Cohesive management and technical

staff.

•

Team has been together for up to

20 years through multiple entities.

•

Prior track record includes:

7

Net Asset Value

Net Asset Value

(1)

At June 30, 2009, excludes derivative financial instruments.

(2)

Williston Basin Bakken acreage and Eagle Ford and Georgetown rights below Austin Chalk, at cost.

(3)

At June 30, 2009.

($ in millions)

Total w/Partnerships

PV-10

% of Total

PV-10

% of Total

Proved Reserves:

Proved Developed Producing

$226.2

60.3%

248.6

61.4%

Proved Developed Non-Producing

66.1

17.6%

68.1

16.8%

Proved Undeveloped

82.8

22.1%

89.7

21.8%

Total Proved PV-10 Value

$375.1

100.0%

406.4

100.0%

Plus:  Working Capital

(1)

11.6

11.6

Acreage and Other

(2)

10.0

10.0

Less:  LTD

(3)

(98.0)

(98.0)

Total

298.7

330.0

Shares

Outstanding

(Thousands)

16,241

16,241

Net Asset Value Per Share

$18.39

$20.32

Stock price (9/18/09)

$11.04

Direct Ownership

8

(1)

Proved

reserves,

as

shown

throughout

this

profile,

are

estimated

as

of

7/1/09

and

based

on

NYMEX

strip

pricing

at

7/15/09.

The

NYMEX

oil

strip

used

for

the

estimates

ranged

from

$62.15

per

Bbl

for

2009

to

$87.73

per

Bbl

for

years

2017

and

beyond.

The

NYMEX

gas

strip

ranged

from

$3.28

per

Mcf

for

2009

to

$7.58

per Mcf

for years 2017 and beyond.

(2)

Partnership reserves do not include potential reversionary interests.

(3)

Represents non-proved reserve potential associated with existing fields or prospects that are scheduled and reasonably expected to be drilled with the Company’s

anticipated cash flows and current budget. Does not include certain projects which may result in additional prospects or drilling locations. Cautionary Note: The

Company

is

using

the

term

“non-proved

potential”

in

this

profile

to

provide

interested

parties

with

estimates

of

reserve

potential

associated

with

certain

projects.

See further information following in this profile. Such estimates are prepared by the Company, in accordance with reasonable industry practices. However, such

estimates

are

inherently

imprecise

and

subject

to

material

revisions.

As

of

June

2009,

the

SEC

did

not

permit

the

disclosure

of

any

non-proved

reserve

estimates in SEC filings. Accordingly, interested parties are urged to read the Company’s Annual Report on Form 10-K/A and its other SEC filings.     

Proved and Potential Reserves

Oil

Gas

Total

Corporate

Interests

MMBO

BCF

BCFE

BCFE %

PV 10 ($MM)

PDP

6.9

37.9

79.3

62.1%

$226.2

PDNP

1.9

5.6

17.0

13.3%

66.1

PUD

2.6

15.9

31.4

24.6%

82.8

Total

11.4

59.4

127.7

100.0%

$375.1

Oil

Gas

Total

Corporate

and

Partnership

Interests

(2)

MMBO

BCF

BCFE

BCFE %

PV-10 ($MM)

Proved

PDP

6.9

46.1

87.7

62.0%

$248.6

PDNP

1.9

6.8

18.3

13.0%

68.1

PUD

2.6

19.6

35.4

25.0%

89.7

Total Proved

11.4

72.5

141.4

100.0%

$406.4

Non-Proved

(see

following

slides)

(3)

7.9

14.3

61.7

Total

19.1

87.4

202.4

9

Partnership Operations

SBE Partners LP

Catena Oil & Gas, LLC

General Partner

OKLA Energy Partners LP

2% GP Interest

30% GP Interest

Catena Oil & Gas, LLC.

Wholly owned subsidiary.

GE Capital = Sole Limited Partner.

30% interest in SBE partners acquired with

recent acquisition.

2% General Partner interest in Okla Energy 

with 34% reversionary interest.

14 Bcfe excluding reversionary interests.

Partnerships generate fees, net income and

cash distributions estimated for 2009 as

follows:

Management fees -

$1.1 million.

Partnership net income -

$2.6 million.

Partnership distributions -

$4.4 million.

10

Proved

Reserves

(Bcfe)

(2)

Production

(MMcfe)

(3)

Reserves and production –

Direct interests

(1)

Proved

Reserves

–

127.7

Bcfe

(2)

(1)

Excludes partnership interests.

(2)

2006 –

2008 proved reserves based on SEC prices.  Reserves as of 7/1/09 based on 7/15/09 NYMEX strip prices.

(3)

51% oil, based on proved developed only.

Gas

47%

Oil

53%

11

Production Growth –

Direct Interests

Gas

Oil

Summary of acquisitions and divestitures:

–

April 2007: Reverse merger and Chandler

acquisition.

–

October

2007: $100.0 million acquisition primarily

in Louisiana

and Texas.

–

January 2008: $6.6 million sale –

Michigan.

–

February 2008: $7.9 million acquisition –

Williston

Basin.

–

February 2008: $1.8 million sale –

Louisiana.

–

May 2008: $11.8 million sale –

seven fields,

Louisiana and Texas.

–

May 2008: Participation in the $61.7 million

formation of OKLA Energy Partners LP.

–

September 2008: $3.6 million acquisition –

Oklahoma.

–

2008 acquisitions and divestitures, high-graded

portfolio and expanded drilling inventory.

–

January 2009: $1.6 million sale –

Louisiana.

–

May 2009: $10.4 million acquisition –

Williston

Basin.

–

May 2009: $48.4 million acquisition –

Giddings

Field, Texas.

–

2009 acquisitions expand in core areas, high-

graded portfolio and expands drilling inventory.

(1)

Excludes partnership interests.  Based on PDP volumes and includes acquisitions closed in May.

12

•

Bakken

Shale trend of Williston Basin

–

Acquisition

made

through

existing

joint

venture

-

net

cash

$10.4

million.

•

Acquired

a

15%

interest

in

62,000

net

acres

plus

interests

in

59

wells.

•

Adds 486 MBoe

of proved reserves and numerous drilling locations.

•

Adds 180 Boepd.

•

Purchase price = $12.00/Boe and $491/acre.

•

Giddings Field, Texas

–

Purchased from affiliated partnership –

net cash $48.4 million.

•

Increased working interest from 7% to 36%.

•

69 producing wells plus undeveloped Austin Chalk acreage.

•

Directly acquired 25 Bcfe

of proved reserves (88% natural gas and 73% developed).

•

Daily production 10.6 MMcf

and 85 Bbls

liquids.

•

Increased partnership share to 30% (equals to 13 Bcfe

of proved reserves and 5.0

MMcfepd).

•

Purchase price = $1.27/Mcfe

•

Significant Eagle Ford  and Georgetown potential.

Recent Acquisitions

Financial Summary

13

Selected Balance Sheet Data

(1)

The above table does not include the balance sheet effects of hedge accounting for derivative financial instruments which is required for financial statements

presented in accordance with generally accepted accounting principles. See the Company’s SEC filings for further information.

(in millions)

30-Jun-09

Dec. 31, 2008

Dec. 31, 2007

Cash

7.7

$                

14.0

$             

24.4

$             

Other Working Capital –

Net

(1)

4.0

$                

(8.7)

$              

(10.5)

$            

Total

Working

Capital

(1)

11.7

$             

5.3

$                

13.9

$             

Oil & Gas Assets (Successful Efforts)

241.9

$           

181.6

$           

181.4

$           

Equity in Partnerships

3.4

$                

3.3

$                

1.8

$                

Long-Term Debt

98.0

$             

40.0

$             

96.0

$             

Common Stock and Additional Paid in Capital

113.3

$           

112.7

$           

79.8

$             

Retained Earnings

25.0

$             

21.0

$             

7.5

$                

Common Stock Outstanding

16.2

Financial Summary

14

Operating  Data

(1)

EBITDAX is defined as earnings before interest, income taxes, depreciation, depletion and amortization, impairments and exploration expense.  EBITDAX should

not be considered as an alternative to net income or cash flow as indications of performance or liquidity. See the Company’s SEC filings for further information.

($ in millions, except per share data and unit metrics)

YTD 06/30/09

2nd Qtr 2009

2008

2007

Key Data:

Avg. realized oil price ($/Bbl)

56.87

$           

59.28

$            

82.42

$           

67.20

$           

Avg. realized natural gas price ($/mcf)

3.95

$              

3.89

$               

8.12

$              

6.19

$              

Oil production (MBbls)

389

212

743

392

Natural gas production (MMcf)

1,752

1,087

2,962

1,648

Total revenue

33.8

$              

19.3

$               

94.6

$              

40.1

$              

Net income before tax

6.6

$                 

5.7

$                  

21.3

$              

8.0

$                 

Net income

4.0

$                 

3.5

$                  

13.5

$              

3.1

$                 

Net income per share (basic)

0.24

$              

0.22

$               

0.87

$              

0.25

$              

EBITDAX

(1)

18.2

$              

12.0

$               

53.0

$              

17.5

$              

EBITDAX per share (basic)

(1)

1.12

$              

0.73

$               

3.40

$              

1.42

$              

15

(1)

EBITDAX is defined as earnings before interest, income taxes, depreciation, depletion and amortization, impairments and exploration expense.  EBITDAX should not

be considered as an alternative to net income or cash flow as indications of performance or liquidity. See the Company’s SEC filings for further information.

EBITDAX

(1)

Total Leverage

($ in millions)

•

Clear track record of EBITDAX growth.

•

Conservative use of leverage to maintain strong balance sheet.

–

As of June 30, 2009, the Company’s total debt to Last Twelve Months

(“LTM”)  EBITDAX is 2.3x.

–

$135 million Borrowing Base, Libor plus 2.25 –

3.00%.

Strong Financial Position

16

Hedging Strategy

Oil Hedges

•

GEOI uses commodity price risk management in order to execute its

business plan throughout commodity price cycles.

•

2009 –

2010 natural gas hedges include hedge volumes intended to cover

GEOI’s share of partnership production.  Hedged volumes shown below are

about 68% of combined production volumes. 

0%

20%

40%

60%

80%

100%

2009

2010

2011

$76.00

$74.37

$74.71

$43.85

$43.85

0%

20%

40%

60%

80%

100%

2009

2010

2011

$5.08

$5.12

$7.00 - $10.75

$7.00 - $9.90

$7.00 - $9.20

Natural Gas Hedges

Swap

Fixed Contract

Swap

Collar

Regional Overview

18

Southern Region

TX

NM

LA

Loco Hills

Maljamar

Harris

M.A.K.

Warwink

Wheeler

Chittim Ranch

Giddings*

*SBE Partners LP properties

Odem

Driscoll

Oak Hill

Golden

Meadow

Quarantine

Bay

Eloi Bay

St. Martinville

Frisco

OK

OKLA Energy Partners

LP properties

•

Accounts for 73% of reserves and approximately

83% of total production.

–

High-impact exploration potential.

–

Development and recompletion potential.

•

Continuous successful Austin Chalk drilling

program.

–

Significant working interests plus partnership interests.

–

Thirteen wells drilled with 100% success rate.

–

69 producing wells.

–

6-8 wells expected to be drilled in 2009 and in 2010.

–

Recent additional acreage acquisitions.

–

May deploy additional rig with cost reductions.

–

Yegua, Eagle Ford Shale and Georgetown potential.

•

Two 3D seismic projects in progress.

19

ALBERTA

MANITOBA

SASKATCHEWAN

MT

SD

ND

Newporte

Sherman/Wayne

Landa

Starbuck

Comertown

Fairview/Mondak

Sioux Pass

Four Mile Creek

Patent Gate

Flat Top

Note: Highlighted area represents the Williston Basin.  

Bakken JV

•

Accounts for 27% of reserves and approximately 17%

of total production.

•

North Dakota shallow:

–

Starbuck waterflood initial installation early 2008, phase

two finished in early 2009.

•

Initial response realized.

–

SW Starbuck waterflood installation completed early

2009.

–

N.E. Landa expected to be unitized for waterflood.

–

Horizontal infill locations.

•

North Dakota Bakken:

–

Recent acquisitions in approximately 66,000 net acres.

–

Joint venture with 10-17% working interest in

approximately 105,000 net acres.

–

Current  three rig program, expected to increase to four

rigs by 1st quarter 2010.

–

24 joint venture operated wells drilled.

–

Acquired and/or participates in over 120 non-operated

wells.

–

Joint venture expects to drill or participate in 

approximately 60 wells in the next 18 months.

Northern Region

20

•

Planned

projects

are

diversified

across

GeoResources’

core

areas.

•

Budget to remain within cash flow.

•

Estimated $35 million in next 12 months.

•

Budget allocation favors low-risk, high cash flow projects.

•

Budget revisions will reflect  commodity prices and include recent acquisitions.

–

Flexibility between gas and oil projects.

–

Flexibility between development exploration.

Southern Region Capital Expenditures

Northern Region Capital Expenditures

$50 million total

$61 million total

Planned Exploration &

Development Projects (2009 –

2011)

21

Selected Upside Projects

Reserve Potential

Gas

24.8%

Oil

75.2%

Reserve Potential

(2)

Does not include Pearsall Shale.

(3)

Does not include Yegua

or

Eagle Ford Shale potential or proved undeveloped reserves.

(4)

Includes net interest in 6 non-proved locations.

(5)

Represents Company estimated base case for one prospect area.  Excludes other prospective

areas and deep potential below 16,000 feet.

(6)

Includes one proved and three non-proved locations.  Third seismic shoot may alter non-

proved  sub-surface locations and is expected to result in additional locations.

(7)

Engineering estimates for a successful flood range from 1.4 to 2.3 MMBO.

Bakken

24.4%

North Dakota

29.2%

Louisiana

26.6%

Texas

17.2%

Oklahoma

2.5%

Oil

Gas

Total

Field

State

Mmbo

Bcf

Bcfe

Bakken

Shale

(1)

ND,MT

2.3

1.0

14.8

Chittim

(2)

TX

-

1.1

1.1

Giddings

(3)

TX

-

8.3

8.4

Mak

TX

0.2

-

1.2

Northeast Landa

ND

0.4

-

2.4

Oklahoma (various net)

(4)

OK

-

1.5

1.5

Quarantine Bay

(5)

LA

1.4

2.3

10.7

Roth/Leonard

ND

0.3

-

1.8

Sherman/Wayne

ND

0.7

-

4.2

St. Martinville

(6)

LA

1.0

-

6.0

SW Starbuck

ND

0.2

-

1.2

Starbuck Waterflood

Unit

(7)

ND

1.4

-

8.4

Non-Proved Potential

7.9

14.3

61.7

________________________________________________________________________________

(1)

Estimated participation in 100 wells pending continued favorable drilling results.  Does not

include in-fill drilling or Three Forks / Sanish horizontal potential.

22

Bakken Shale –

East Nesson

Bakken Shale

Note:  Yellow-highlighted areas represent the Company’s acreage position.

•

Joint venture with varying working

interests ranging from 10% to 15.5% in

approximately 100,000 net acres.

•

59,000 acres in Mountrail County.

•

24 horizontal Bakken Shale wells drilled

and in process of completing. Joint

venture expects to drill 60 wells in the next

18 months.

(1)

•

Initial gross production rates range from

350 to 1,400 Bopd per well.

(1) Well counts exclude numerous wells with nominal interests.

23

Giddings Field

Austin Chalk Play

Houston

Master’s 

Creek field

Texas

Louisiana

Arkansas

Gulf of Mexico

Brookeland

Giddings

Pearsall

Mississippi

North

Bayou Jack

Mexico

Houston

Master’s 

Creek field

Texas

Louisiana

Arkansas

Gulf of Mexico

Brookeland

Giddings

Pearsall

Mississippi

North

Bayou Jack

Mexico

•

Approximately 67,000 acres.

•

Producing properties and acreage in the

Austin Chalk Formation.

–

GEOI owns an average direct working

interest of ~ 37%.

–

Partnership owns ~ 53%.

–

GEOI owns a 30% general partner interest.

•

Thirteen

wells

drilled

–

100%

success.

•

Additional upside includes:

–

Multiple wells with rate increase potential

from slick water fracture stimulations.

–

At least 15 additional locations.

–

Yegua and Eagle Ford Shale potential.

Quarantine Bay

Quarantine Bay Field

LA

New

Orleans

Black Bay

Breton Sound

Eloi

Bay

Lake Salvador

Lake Borgne

Lake Ponchartrain

Quarantine Bay

Violet

Westwego

Belle Chasse

Braithwaite

Pointe A La Hache

Port Sulphur

Quarantine Bay

Oil & Gas Field

New

Orleans

Black Bay

Breton Sound

Eloi

Bay

Lake Salvador

Lake Borgne

Lake Ponchartrain

Quarantine Bay

Violet

Westwego

Belle Chasse

Braithwaite

Pointe A La Hache

Port Sulphur

Quarantine Bay

Oil & Gas Field

•

GeoResources has a 7% working interest above

10,500 feet and a 33% working interest below

10,500 feet, in approximately 14,000 acres.

•

Cumulative Production = 180 Million Bbls and

285 BCF

•

Shallow zone potential (<10,500 ft):

–

Numerous behind pipe opportunities due to

multiple stacked sand reservoirs.

–

Rate acceleration wells.

•

Pending prices and drilling cost

reductions.

•

Significant deep potential (>10,500 ft): 

–

Schlumberger reprocessed and interpreted

the 3-D seismic data.

–

Initial prospect.

•

Multiple objectives to 16,000 ft.

24

25

Starbuck Waterflood Unit 

Starbuck Unit

ND

HAAS

North Dakota

LANDA NE

LEONARD

ZION

LANDA

ROTH N

ROTH

SHERMAN

WAYNE

STARBUCK

CANADA

Bottineau County

T163N

T162N

T161N

R79W

R81W

R80W

R82W

R83W

HAAS

North Dakota

LANDA NE

LEONARD

ZION

LANDA

ROTH N

ROTH

SHERMAN

WAYNE

STARBUCK

CANADA

Bottineau County

T163N

T162N

T161N

R79W

R81W

R80W

R82W

R83W

•

Unitized effective November 1, 2007 and

includes over 6,000 acres.

–

95.8% working interest.

•

Phase One waterflood installation

completed early 2008.

–

Recent initial response.

–

Phase Two waterflood expansion

substantially completed.  

•

The Starbuck Midale Zone has produced

584 MBO and the Berentson Zone has

produced 754 MBO on primary recovery,

for total field production of 1.4 MMBO.

•

The Company estimates additional

reserves of 1.4

–

2.3 MMBO.

26

Key Investment Highlights

Value Creation

Experienced Management and Technical Staff

Prior Track Record of Growth, Profits and Liquidity

Strategically Located, Geographically Diverse Asset Base

Strong Growth with High Level of Operating Control

Active Hedging Program

Significant Identified Upside Potential

Developing Additional Prospects

Strong Financial Position