Georesources (GEOI) 8-K Regulation FD Disclosure

GeoResources, Inc

Corporate Profile

March 2010

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,

2009

Annual

Report

on

Form

10-K

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

Additional Disclosures

4

Key Investment Highlights

Value Creation

Experienced Management and Technical Staff with Large Ownership

Stake

Board and management own or control approximately 43% of the Company

Successful track record of creating value and liquidity for shareholders

Attractive Value Proposition

Trading at a significant discount to NAV

Strong Asset Base

Strategically located and geographically diverse

Balanced oil vs. gas

High level of operating control

Significant Identified Growth Opportunities on Existing Properties

Low risk development drilling

Higher impact exploration upside

Strong Financial Position

Moderate leverage with significant cash flow

5

Company Overview

Company Highlights

(1)

Represents the Company’s 4Q 2009 production rate.

(2)

Acreage information estimated as of 12/31/09.  Maps herein exclude minor value properties.

.

5

Direct

Direct +

Ownership

Partnership

Proved Reserves (MMBOE)

23.7

25.4

Oil

53%

50%

Proved Producing

60%

61%

Proved Developed

72%

73%

PV 10% (millions)

$422

$444

Production

(BOEpd)

(1)

5,464

5,925

Operated

80%

80%

Gross

Acreage

(2)

477,374

477,374

Net

Acreage

(2)

216,495

222,893

6

Value-Driven Growth Strategy

Asset

Rationalization

Selectively divest assets to upgrade portfolio

Focus on maximizing IRR for investors

Cost Control

Operate as efficiently as possible by focusing on minimizing development,

production, and G&A expenses

Pursue promoted partner positions to reduce costs and generate operating fees

Pursue exploration prospects on both new and existing fields

Solicit partners on a promoted basis to reduce risk

Exploration

Acquire operated properties with existing production, development

opportunities, and exploration potential

Acquisitions

Development   

and     

Exploitation

Drill PUDs and probable reserves to enhance property value

Focus on areas with development and exploitation upside

Implement re-engineering and development programs to extend field life,

increase proved reserves, lower unit operating costs, and enhance economics

7

Management History

2004-

2007

Southern Bay Energy, LLC

Gulf Coast, Permian Basin

REVERSE MERGED INTO

GEORESOURCES

2000-2007

Chandler Energy, LLC

Williston Basin, Rockies

ACQUIRED BY

GEORESOURCES

1988-2000

Chandler Company

Rockies, Williston Basin

MERGED INTO

SHENANDOAH THEN SOLD 

TO QUESTAR 

1992-1996

Hampton Resources Corp,

Gulf Coast

SOLD TO BELLWETHER

EXPLORATION

Preferred investors –

30% IRR

Initial investors –

7x return

1997-2001

Texoil Inc.

Gulf Coast, Permian Basin

SOLD TO OCEAN  ENERGY

Preferred investors –

2.5x return

Follow-on investors –

3x return

Initial investors –

10x return

2001-2004

AROC Inc.

Gulf Coast, Permian Basin, Mid-Con.

DISTRESSED ENTITY LIQUIDATED

FOR BENEFIT OF INITIAL

SHAREHOLDERS

Preferred investors –

17% IRR

Initial investors –

4x return

Track record of profitability and liquidity

Long-term repeat investors

Extensive industry and financial relationships 

Significant operational and financial experience

Cohesive management and technical staff

Team has been together for up to 20 years

through multiple entities 

8

Net Asset Value 

Net Asset Value

(1)

Nymex

strip pricing.

(2)

Excludes derivative financial instruments.

($ in millions)

PV-10

(1)

% of Total

Proved Reserves:

Proved Developed Producing

262.7

$        

62.3%

Proved Developed Non-Producing

69.0

16.4%

Proved Undeveloped

90.0

21.3%

Total Proved PV-10 Value

421.7

$        

100.0%

Plus:

Working Capital

(2)

16.0

$          

Unproved Property, at cost

10.3

Partnership Value

22.1

Less:

Total Debt

(69.0)

Total Net Asset Value

401.1

$        

Shares Outstanding (thousands)

19,705

Net Asset Value Per Share

20.36

$        

December 31, 2009

9

Proved Reserves

Proved Reserves by Category

Proved Reserves by Area

Partnership

Proved

% of

Interests

Total Proved

% of Total

Area

MMBOE

Proved

MMBOE

MMBOE

Reserves

Gulf Coast/ETX/STX

9.2

38.8%

1.6

10.8

42.5%

Williston

6.0

25.3%

0.0

6.0

23.6%

Louisiana

3.7

15.6%

0.0

3.7

14.6%

Permian

2.3

9.7%

0.0

2.3

9.1%

Mid-Continent

1.5

6.3%

0.1

1.6

6.3%

Other

1.0

4.2%

0.0

1.0

3.9%

Total

23.7

100.0%

1.7

25.4

100.0%

($ in millions)

Oil

Gas

Total

% of

Corporate Interests

MMBO

BCF

MMBOE

Total

PV-10

PDP

7.8

37.7

14.1

59.5%

$262.7

PDNP

2.1

5.4

3.0

12.7%

69.0

PUD

2.6

23.7

6.6

27.8%

90.0

Total Proved Corporate Interests

12.5

66.8

23.7

100.0%

421.7

Partnership Interests

0.1

10.0

1.7

22.1

Total Proved Corporate and Partnerships

12.6

76.8

25.4

$443.8

10

Selected Balance Sheet Data

Financial Summary

(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.

(2)

Adjusted to reflect 11/24/09 equity offering.

($  & shares in millions)

Dec. 31, 2009

Dec. 31, 2008

Dec. 31, 2007

Cash

12.7

$         

14.0

$         

24.4

$         

Other

Working

Capital

-

Net

(1)

3.3

$           

(8.7)

$          

(10.5)

$        

Total

Working

Capital

-

Net

(1)

16.0

$         

5.3

$           

13.9

$         

Oil & Gas Assets (Successful Efforts)

246.8

$        

181.6

$        

181.4

$        

Equity in Partnerships

3.5

$           

3.3

$           

1.8

$           

Long-Term Debt

69.0

$         

40.0

$         

96.0

$         

Common Stock and Additional Paid in Capital

147.2

$        

112.7

$        

79.8

$         

Retained Earnings

27.5

$         

21.0

$         

7.5

$           

Common

Stock

Outstanding

(2)

19.7

11

Financial Summary

Historical Operating Data

($ in millions except per share data)

4th Qtr 2009

2009

2008

2007

Key Data:

Average realized oil price  ($/Bbl)

65.57

$         

61.09

$         

82.42

$         

67.20

$         

Avg. realized natural gas price ($/Mcf)

4.02

$           

3.97

$           

8.12

$           

6.19

$           

Oil production (MBbl)

250

851

743

392

Natural gas production (MMcf)

1,514

4,944

2,962

1,648

Total revenue

23.6

$           

80.4

$           

94.6

$           

40.1

$           

Net income before tax

2.3

$            

14.8

$           

21.3

$           

8.0

$            

Net income after tax

2.4

$            

9.8

$            

13.5

$           

3.1

$            

Net income per share (basic)

0.14

$           

0.59

$           

0.87

$           

0.25

$           

Adjusted EBITDAX

14.1

$           

48.2

$           

54.2

$           

18.4

$           

12

Financial Summary

Historical Production Data

Historical Operating Netback Data

(1)

Represents

severance

tax

expense

and

re-engineering

and

workover

expense.

4

Qtr

2009

2009

2008

2007

Oil Production (MBbls)

250

851

743

292

Gas Production (MMCF)

1,514

4,944

2,962

1,648

Total Production (Mboe)

503

1,675

1,237

667

Avg. Daily Production (Boe/d)

5,464

4,589

3,388

1,826

4

Qtr

2009

2009

2008

2007

($ per BOE)

Revenue

$46.97

$48.01

$76.50

$60.17

Less:

LOE

$11.06

$11.20

$18.53

$16.23

G&A

5.02

5.07

5.80

9.77

Other

Field

Level

Opex

(1)

3.60

3.84

8.92

7.46

Total Field Level Operating Costs

$19.68

$20.11

$33.25

$33.46

Field Level Operating Netback

$27.29

$27.90

$43.25

$26.71

th

th

13

2009 Finding & Development Costs

Capital Expenditures ($M)

Reserve

Adds

(MBOE)

(1)

Finding & Development Costs

Category

2009 Capital

Acquisitions

66,594

Drilling

23,623

Exploration

1,406

Total Capital

91,623

Reserve Category

Reserve Adds

Acquisitions

4,874

Drilling

2,510

Revisions

430

Total direct additions

7,814

Increase partnership share

1,257

Total additions

9,071

Category

$/BOE

Acquisitions

$13.66

Drilling

$9.41

Total including revisions

$11.73

Total including partnership

$10.10

(1)

Reserves

based

on

SEC

guidelines.

14

Proved

Reserves

(MMBOE)

(2)

Average Daily Production (BOEpd)

Reserves and Production –

Direct Interests

(1)

Current Proved Reserves –

23.7 MMBOE

(2)

CAGR: 81%

CAGR: 105%

(4)

(3)

(1)  Excludes partnership interests.  (2) 2006 – 2009 proved reserves based on SEC guidelines.  

(3)  2009 strip reserves based on 12/31/09 NYMEX strip prices.  (4) 2008 Reserves reflect divestitures.

15

Adjusted EBITDAX

Total Leverage

Ability to control destiny without reliance on capital markets

Conservative use of leverage to maintain strong balance sheet

$ 145 Million borrowing base

Total debt of $69.0 million at December 31, 2009 to Adjusted EBITDAX is 1.4x

Credit facility

led

by

Wells

Fargo

and

is

priced

at

LIBOR

plus

2.25

–

3.00%

Strong Financial Position

($ in millions)

16

Hedging Strategy

Oil Hedges

GEOI

uses

commodity

price

risk

management

in

order

to

execute

its

business

plan

throughout

commodity price cycles

2010

–

2012

natural

gas

hedges

include

hedge

volumes

intended

to

cover

GEOI’s

share

of

partnership

production

Hedged

volumes

shown

below

are

about

50%

of

combined

production

volumes

Swaps

Fixed Contract

Swaps

Collar

Natural Gas Hedges

17

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 approximately 73% of reserves

and 78% of total production

High-impact exploration potential

Development and recompletion potential

Approximately 38% of the region’s proved

reserves are oil

Continuous successful Austin Chalk drilling

program

Significant working interests plus partnership

interests

Fourteen wells drilled with 100% success rate

66 producing wells

6-8 wells per year expected to be drilled in 2010

and in 2011

Recent additional acreage acquisitions

May deploy additional rig

Yegua, Eagle Ford Shale and Georgetown

potential

Two 3D seismic projects in South Louisiana

18

Northern Region

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 approximately 27% of reserves and 22% of

total production

Approximately 93% of the region’s proved reserves are oil

Bakken Operated Joint Venture:

Acquired 61,000 gross (42,000 net) acres in Williams Co., ND

Retains 45% working interest in  Area of Mutual Interest and

brought in 2 industry partners

Bakken Non-Operated Joint Venture:

10-18% working interest in approximately 106,000 gross acres

(approximately 13,900 net acres)

Current five rig program, with plan to maintain four rigs in 2010

42 joint venture operated gross wells drilled

Acquired and/or participated in over 140 non-operated wells

Joint venture expects to drill approximately 90 wells in the next

24 months

Williston Basin Other:

Starbuck  & SW Starbuck waterflood installation completed in early 2008 & in early 2009

Initial response realized

Additional upside in horizontal and vertical infill locations within the unit boundaries

Horizontal proved undeveloped and non-proved drilling opportunities within producing fields

19

Current

project

inventory

totals

$160

million

and

is

diversified

across

GeoResources’

core

areas

with

exposure

to

15.3

MMBOE

Estimated

24

month

capital

budget

of

~$90

to

100

million

This

budget

can

be

accelerated

and

expanded

as

deemed

appropriate

by

management

Current

budget

allocation

favors

lower-risk,

high

cash

flow

projects

Exploratory success could expand drilling inventory

Actual

expenditures

will

reflect

recent

acquisitions,

commodity

prices,

and

risk

Flexibility

between

gas

and

oil

projects

Flexibility

between

development

and

exploration

Southern Region Capital Expenditures

Northern Region Capital Expenditures

$73 million total

$87 million total

Near-Term Exploration & Development Projects

(1)

Excludes potential in-fill drilling.

20

24 Month Budget –

Project Reserve Potential

$90 to 100 million of identified capital projects budgeted over next 24 months:

10.3 MMBOE reserve addition

$9.19/boe estimated F&D cost

Consistent with management prior track record

Acreage and seismic expenditures will likely result in additional projects and drilling inventory

Re-engineering should result in lower per-unit lifting costs and may result in incremental reserves by extending field lives and lowering

economic limits

Current Budget

(1)

Capital

assumes

1,280

acre

units

at

$6

million

per

well

with

added

technical

data

(cores,

logs,

pilot

holes).

Reserves

estimated

at

500

MBOE

per

well.

All

non-proved.

(2)

Initial

exploration

well

below

field

pay

to

16,350+/-.

Represents

base

exploratory

reserve

case

to

test

six

objectives.

Investment

represents

drilling

costs

only;

a

discovery

well

will

result

in

completion

costs

estimated

at

$1.0

million.

Reserve

potential

for

GEOI

is

3.0

MMBOE

and

would

set

up

additional

drilling.

.

Net Reserve

Gross

Net

Potential

Net Investment

F&D Cost per

Field

Wells

Wells

MBOE

(in $ millions)

BOE

Austin Chalk

Proved

6

2.7

1,236

$14.5

$11.70

Non-Proved

4

1.5

1,701

12.5

7.38

Bakken

Proved

22

1.8

263

$3.4

$13.03

Non-Proved

100

8.0

2,560

28.0

10.94

St. Martinville

Non-Proved

6

5.8

1,365

$5.5

$4.05

Starbuck and SW Starbuck Waterflood

Proved

215

$2.4

$11.24

Non-Proved

996

0.8

0.79

Total Proved/Non-Proved Projects in Budget

8,336

$67.2

$8.06

Bakken

Operated Non-proved

(1)

3

1.4

553

$8.1

$14.65

Quarantine Bay North

Exploration

(2)

1

0.3

1,443

$2.1

$1.46

Reengineering and Other

$3.5

Acreage and Seismic

$14.0

Total 24 Month Budget

10,332

$94.9

$9.19

21

Additional Development

Potential Budget Acceleration

The capital budget can be accelerated to take advantage of additional development drilling opportunities

within our current project portfolio

Development Potential:

5.0 MMBOE reserve potential

~$65 million capital cost

$13.00/boe estimated F&D cost

Several PUD locations have exploratory objectives

Field

Gross

Wells

Net Wells

Net Reserve

Potential MBOE

Net Investment 

(in $ millions)

F&D Cost per

BOE

Other Southern Development

Proved

2,079

$17.6

$8.46

Other Northern Development

Proved

1,265

$22.5

$17.75

Austin Chalk

Proved

5

2.3

889

$11.3

$12.71

Non-proved

7

2.7

773

12.5

16.23

Waterflood

Expansion

$1.2

Total Budget Acceleration

5,005

$65.1

$13.00

Total 24 Month Budget (previous slide)

10,332

$94.9

$9.19

Total

15,337

$160.0

$10.43

22

Additional Upside

Shallow

Yegua

potential

in

Giddings

Field

(above

the

Austin

Chalk)

Eagle

Ford

and

Georgetown

potential

in

Giddings

Field

(below

the

Austin

Chalk)

Eagle

Ford

and

Pearsall

shale

potential

in

Maverick

County,

TX

Three

Forks/Sanish

potential

in

the

Williston

basin

Additional Starbuck upside

0.8 MMBOE from increased waterflood

recovery and federal acreage development

Quarantine

Bay

upside

Seismic-based regional analogies below 18,000’

Other

projects,

consistent

with

management

track

record

of

expanding

inventory

with

growth

Work in Progress

Additional Reserve Potential on Current Projects

(1)

Additional reserve exposure on the prospects noted above and prior slides of 7.1 MMBOE.

Net Reserve

F&D

Potential

Investment

Cost per

Field

MBOE

(in $ millions)

BOE

Bakken Infill

Non-proved

1,440

$21.0

$14.58

St. Martinville

Shallow

910

$3.8

$4.18

Discorbis (10,000')

1,517

7.0

4.60

Quarantine Bay

(1)

SW - Exploratory

186

$3.1

$16.70

SE - Exploratory

743

3.1

4.18

Total

4,795

$38.0

$7.93

23

Type Well Economics

Diverse set of drilling opportunities provides for growth and flexibility in changing commodity price cycles

Most drilling opportunities remain highly economic in the current price environment

(1)

Well cost of $6.8 million and reserves of 6.5 BCF.

(2)

Well cost of $4.4 million and reserves of 1.15 BCF and 150 MBO.

(3)

Well cost of $3.5 million and reserves of 400 MBO.

(4)

Well cost of $3.5 million and reserves of 600 MBO.

(5)

Well cost of $1.3 million and reserves of 250 MBO.

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

Assumed Gas/Oil Price

Chalk Gas(1)

Chalk O&G(2)

Bakken

400(3)

Bakken

600(4)

St Martinville

Oil(5)

24

Key Investment Highlights

Value Creation

Experienced Management and Technical Staff with Large Ownership

Stake

Board and management own or control approximately 43% of the Company

Successful track record of creating value and liquidity for shareholders

Attractive Value Proposition

Trading at a significant discount to NAV

Strong Asset Base

Strategically located and geographically diverse

Balanced oil vs. gas

High level of operating control

Significant Identified Growth Opportunities on Existing Properties

Low risk development drilling

Higher impact exploration upside

Strong Financial Position

Moderate leverage with significant cash flow

APPENDICES

26

Demonstrated History of Successful A&D

2007/2008:

High-graded

portfolio

and

expanded

drilling

inventory

April 2007:

Reverse merger and Chandler acquisition

October

2007:

$104.0 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

2009:

Expanded

in

core

areas,

high-graded

portfolio

and

increased

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

August

2009:

$1.6

million

acquisition

–

Giddings

Field,

Texas 

Summary of Acquisitions/Divestitures

27

Bakken Shale Operated

Williams County, ND Joint Venture Acreage

Joint Venture controls 61,000 Gross 

(42,000 net ) Acres

GEOI operated

Partner with Resolute Energy and Private

Independent

GEOI retains 45% Working Interest

18,900 net acres

Continued leasing

Plan to drill at least 3 wells in 2010

Operator Activity Increasing in the County

American

Brigham Exploration

Continental Resources

EOG

Whiting

XTO

CANADA

ND

MT

50 miles

Williams

County

Parshall

Sanish

27

28

Bakken Shale

Non-operated

Bakken Shale

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

Working interests ranging from 10% to 18%

in 106,000 gross acres (approximately

13,900 net acres)

69,000 gross acres in Mountrail County , ND

(approximately 8,000 net acres)

Five rigs running

Joint Venture has drilled 42 wells to date and

plans to drill 90 wells in the next 24 months

Developing on 640 acre units as well as

1,280 acre and larger units

Additional upside in Three Forks and Bakken

increased density wells

Detailed map on next slide

29

Bakken Shale

Non-operated

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

640 and 1,280 acre units being drilled

Some larger units under the lake

Multiple wells from single drilling pad

Minimize facilities and roads

Maximize infrastructure

Developing reserves with difficult access

Minimize disturbance and the number of

locations

Van Hook Area

30

Giddings Field

Austin Chalk Play, Texas

Working interests range from

37% -

53% in 68,000 gross acres

(approximately 29,000 net acres)

22 additional gross drilling

locations (9.2 net wells)

14 wells drilled –

100% success

Additional upside includes:

Yegua, Eagle Ford shale and

Georgetown  potential

Multiple wells with rate increase

potential from slick water

fracture stimulations 

31

Giddings Field Acreage Position

Giddings Field

GEOI produces oil & gas

from Austin Chalk

Horizontal wells

Other Potential Reservoirs

Yegua

Wilcox

Eagle Ford Shale

Buda

Georgetown

Edwards

32

Grimes and Montgomery Counties, TX

Austin Chalk Development

Proved Undeveloped and

Probable Horizontal

Locations

Last well: Longstreet 1H

produced 1.0 BCFG in 67

days

Single and multiple laterals

Eastern Grimes / Western

Montgomery dry gas

Western Grimes gas  with

large volume of liquids

Single rig continuous

program

Tight gas –

severance  tax

exemption

Longstreet 1H

33

Eagle Ford Trend

South & Central Gulf Coast Texas

Significant acreage

position in trend

Eagle Ford shale present

over much larger area

than apparent trend

Trend depicted where

Eagle Ford is +-7,000’

to

+-14,000’

Early in development

34

Recent Activity Map

Apache & Clayton Williams active

in our area

Majority of Apache wells vertical

Our Brazos, Burleson, Fayette

and Washington County holdings

currently appear most prospective

for Eagle Ford

Central Texas Eagle Ford

Quarantine Bay

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 MMBO and 285

BCF

Shallow zone potential (<10,500 ft):

Numerous behind pipe opportunities due to

multiple stacked sand reservoirs

Rate acceleration wells

Significant hi-potential exploration deep potential: 

Schlumberger reprocessed and interpreted

the 3-D seismic data

Initial prospect

Multiple objectives to 16,000 ft

Deeper objectives

35

LOUISIANA

Quarantine Bay

Field

36

Quarantine Bay

Nearby

Lake

Washington

East

which

is

an

analogy

for

deep

production

has

produced

9

MMBO

&

14

BCF

from

the

Big

Hum

+-15,000’

Significant

Big

Hum

sand

encountered

at

Quarantine

Bay

and

is

productive

in

one

well

on

the

southeast

flank

New

“state

of

the

art”

pre-stack

depth

and

simultaneous

inversion

3-D

processing

to

evaluate

the

pressured

deep

strata

(14,000’-18,000’)

and

ultra-deep

strata

(>18,000’)

Multiple

prospective

areas

have

been

identified

on

our

leases

Current

focus

is

on

a

opportunities

identified

above

16,000’

with

a

estimated

cost

of

$6.5MM

to

test

37

St. Martinville

St. Martinville

5.3 square mile “high resolution”

3-D survey to be

completed in Q4; processed and interpreted in Q1 2010

Intermediate depth salt dome

Average working interest 97% and average NRI 91%.

Royalty burden ranges from Zero on owned minerals to

22% on lease acreage

Complex faulted structural closures provide

hydrocarbon traps

534 net acres of owned minerals (green)

2,585 net acres of HBP or leased (yellow)

Main

objectives

Miocene

age,

low

risk,

shallow,

highly

productive

multi-sand,

oil,

from

3,000’

–

5,000’.

Over

50

individual

sands

productive

in

field

with

cumulative

shallow

production

est.

15.2

MMBO

and

16.6

BCFG

Exploratory

objectives

in

Discorbis

and

Bol

perca

(gas

and

condensate)

LOUISIANA

38

St. Martinville Shallow Leads Example

St. Martinville Shallow Leads Example

Miocene 11D sand lead map        

(+/-4,000’)

Most recent well Std. Kansas 7.

Current cumulative 58 MBO (one

sand), all sands have reserves of

approximately 250 MBO

Subsurface leads at this sand level

Main field production at this sand

39

St. Martinville Discorbis

Miocene lower Discorbis sand lead

map

Previously productive areas

Cumulative 124 BCF and 1.8

MMBO

Subsurface leads at this level

40

Starbuck and SW Starbuck Waterflood Units

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

Starbuck 6,618 acres, 96% WI

SW Starbuck 560 acres, 98% WI 

Starbuck phase one completed 2008

Phase two and SW Starbuck expansion

completed 2009

Recent initial response

Primary production totals 1.4 MMBO for the 

Starbuck Midale and Berentson Zones

Primary production for SW Starbuck totals

162 MBO 

Approximately $6.0 million on waterflood

implementation

The Company estimates additional reserves

of 1.6 –

2.5 MMBO for both projects

Starbuck Unit

41

Starbuck and SW Starbuck Waterflood Units

Starbuck Unit

Designed as line-drive waterflood

14 producers

6 injectors

One dedicated water supply well

One dedicated injection facility and one

shared facility with SSMU

SW Starbuck Unit

Single producer/injector pair

Shared water supply well and injection facility

with larger Starbuck Unit

Additional vertical and horizontal wells

planned for both units as pressure response

and increased oil rate is achieved