Georesources (GEOI) 8-K GeoResources, Inc. Reports Third Quarter Financial Results

Corporate Profile

November, 2011

Exhibit 99.2

Forward-Looking Statements

Information

included

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

and

costs,

uncertain

effects

of

hedging

activities

and

uncertainties

of

our

oil

and

gas

estimates

of

proved

reserves

and

resource

potential,

all

of

which

may

be

substantial.

In

addition,

past

performance

is

no

guarantee

of

future

performance

or

results.

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,

2010

Annual

Report

on

Form

10-K

and

any

and

all

of

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 

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.

2

3

Company Highlights

Value Creation

Balanced Portfolio

Long-Term

Growth

–

71,000

net

acres

in

two

premier

U.S.

liquids

resource

plays

Strong

Current

Cash

Flow/Profitability

–

5,545

Boe/d

of

production

in

3Q

2011

(65%

oil)

24

Mmboe

proved

reserves;

60%

oil

(1)

Substantial Eagle Ford Position

25,000

net

acres

(primarily

operated)

Successful

recent

drilling

has

de-risked

acreage

and

have

proved

commerciality

of

play

Two

dedicated

rigs

under

contract

Significant Producing Bakken Position

46,000

net

acres

(33,200

operated)

Continually

leasing

Two

dedicated

rigs

currently

running

on

operated

position

(1)

Does

not

include

interests

in

affiliated

partnerships.

Reserves

based

on

SEC

pricing

as

of

1/1/11.

See

Additional

Disclosures

in

Appendix.

3

Company Overview

(1)

Reserve

data

as

of

January

1,

2011

and

production

data

is

for

3Q

2011.

Data

excludes

interests

in

two

affiliated

partnerships.

Reserves

based

on

SEC

pricing

for

2010.

See

Additional

Disclosures

in

Appendix.

(2)

Adjusted

EBITDAX

is

a

non-GAAP

financial

measure.

Please

see

Appendix

for

a

definition

of

Adjusted

EBITDAX

and

a

reconciliation

to

net

income.

Bakken

46,000 net acres

Reserve and Production Snapshot

(1)

Operations focused in Texas, Gulf Coast

and Williston Basin

Oil-weighted

production

and

reserves

from

primarily

operated

properties

Growing production profile

Significant

low-risk

drilling

inventory

in

two

leading

oil-rich

resource

plays

(Bakken,

Eagle

Ford)

Additional

upside

in

legacy

HBP

positions

(Austin

Chalk,

South

Louisiana,

Permian)

Strong cash flow generation

Adjusted

EBITDAX

of

$78

MM

(2)

for

twelve

month

period

ended

September

30,

2011

Significant liquidity

$216MM

of

cash

and

revolver

availability

Eagle Ford

25,000 net acres

4

01/01/11 Proved Reserves (MMBOE)

24.0

Oil % (Reserves)

60%

Proved Developed %

74%

3Q 2011 Production (Boe/d)

5,545

Oil % (Production)

65%

Operated Production

75%

Proved Reserves (MMBOE)

(2)

Average Daily Production (BOE/d)

Reserves and Production

Current Proved Reserves –

24.0 MMBOE

(1)

(1)

As of  January 1, 2011. Excludes partnership interests. 

(2)

2006 –

2010 proved reserves based on SEC guidelines. 

(3)

2008 reserves reflect lower prices and divestitures.  See Additional Disclosures in Appendix.

5

Oil Weighted Development

GeoResources Asset Overview

6

Eagle Ford Shale Overview

25,000 net acres primarily Southwest

Fayette County, TX

Will spud 8 -

9 gross wells in 2011 and 21 -

24 in 2012

2011 & 2012 drilling programs average 40%

-

45% WI

Eagle

Ford

AMI

Ramshorn Investments, Inc., an affiliate of

Nabors Industries, Ltd.  purchased a 50%

interest

o

Upfront cash payment

o

Agreed to fund 100% of cost of first six

horizontal wells

GEOI retains 50% WI and operations

Leasehold continues to increase

Fayette County: 20,300 net acres

Gonzales County: 2,700 net acres

Atascosa & McMullen counties

combined: 1,800 net acres

Note:

Information

as

of

November,

2011.

7

Note:

Third

party

Peak

Month

Avg.

rate

calculated

as

maximum

average

daily

production

rate

of

first

four

calendar

months

of

production.

Source

of

third

party

production

data

is Drilling

Info

and/or

HPDI.

Source

of

GeoResources’

data

is

internal

figures.

Information

as

of

November,

2011.

Eagle Ford Shale

Concentrated

23,000

net

acre

block

in

volatile

oil

window

Multi-year

drilling

inventory

Two

dedicated

rigs

under

contract

Successful

initial

drilling

has

de-risked

acreage

408

boe/d

30-day

average

rate

for

first

three

wells

Recently

drilled

two

additional

wells

-

Awaiting

frac

Positive

offset

operator

activity

Magnum

Hunter

Resources

Penn

Virginia

EOG

Austin

Chalk

upside

on

acreage

block

Recently participated in oily Chalk well that

averaged

388

boe/d

for

first

19

days

(14.8

% WI)

Additional

chalk

drilling

planned

for

2012

8

MHR Gonzo North #1H

Peak Month Avg.: 471 Boe/d 

GEOI Flatonia East #1H 

30 day Avg. Rate:  391 Boe/d

GEOI Flatonia East #2H

30 day Avg. Rate:  465 Boe/d

PVA Munson Ranch #3H

Peak Month Avg.: 728 Boe/d 

MHR Gonzo Hunter #1H

Peak Month Avg.: 341 Boe/d 

MHR Geo Hunter #1H

Peak Month Avg.: 504 Boe/d 

PVA Gardner El Al #1H

Peak Month Avg.: 852 Boe/d 

PVA Hawn Holt #9H

Peak Month Avg.: 951 Boe/d 

GEOI Peebles #1H

Awaiting Frac

GEOI Black Jack Springs #1H

30 day Avg. Rate:  369 Boe/d

GEOI Ring “A”

To Be Spud By Yr. End

GEOI Newtonville #1H

To Be Spud By Yr. End

GEOI Arnim “A”

1

st

pad Location

#1H: Awaiting Frac

#2H: Drilling

Eagle Ford Development Economics

Development Economics  (~5,000 ft. Lateral)

(1)(2)

(1)

Assumes oil differentials of (5%) and assumes gas shrinkage of (15%). Natural gas price held constant at $5/Mcf with a +20% gas differential. 

(2)

EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells. See Additional Disclosures in Appendix.

9

9

Eagle Ford Illustrative Resource Potential

Resource Potential

(1)

(1)

Data is for illustrative purposes only and is based on management assumptions.  EUR refers to management’s internal estimates of reserves potentially recoverable

from successful drilling of wells.  See Additional Disclosures in Appendix.

10

10

Undeveloped Eagle Ford Acreage Provides Net

Resource Potential of ~60 to ~80 MMboe

Eagle Ford Shale (Fayette Co., Texas)

350 Mboe

500 Mboe

Assumed Spacing Unit Size (Acres)

900

900

# Wells per Spacing Unit

6

6

# Acres per Well (Spacing Unit / # Wells per Unit)

150

150

GeoResources Net Undeveloped Acres

25,000

25,000

Number of Potential Net Drilling Locations

167

167

Estimated EUR per Well (Mboe)

350

500

Unrisked Illustrative Resource Potential (Mboe)

58,333

83,333

11

Bakken Shale Overview

46,000 total net acres in three project areas

Williams County Project (Operated)

Concentrated 25,000 net acre block

6 wells drilled and completed

Eastern Montana Project (Primarily Operated)

8,200 operated / 1,800 non-operated acres in

Roosevelt/Richland County, MT

WI range from 25% to 100% with an average WI of

~50%

Recently

completed

1

st

operated

Bakken

well,

Olson #1-21-16H –

flowing back after frac

Participated in four other successful non-op wells to

date

Mountrail County Project (Non-Op)

Partnered with Slawson Exploration Company

11,000 net acres primarily Mountrail County, ND

WI range from 1% to 18% with an average WI of

~8%

Drilled over 100 wells to date; 100% success

4-5 rigs currently running

Note:

Information

as

of

November,

2011. 

11

Williams County Project 

Concentrated 25,000 net acre block

in NW Williams Co., ND

Will spud 10 -

11 gross wells in 2011

and 23 –

26 gross wells in 2012

2011 & 2012 drilling programs average

25% -30% WI

Multi-year drilling inventory

2 dedicated rigs currently running

Bakken AMI

Partnered with Resolute Energy

Retained 47.5% WI in project

Successful initial drilling has de-

risked acreage

288 bo/d peak month average rate

12

Note:

Information

as

of

November,

2011.

Peak

Month

Avg.

rate

calculated

as

maximum

average

daily

production

rate

of

first

four

calendar

months

of

production

and

excludes months

with

less

than

20

days

of

production.

Source

of

all

production

data

is

NDIC

website.

408 bo/d

(6 Wells)

333 bo/d

(5 Wells)

264 bo/d

(3 Wells)

268 bo/d

(4 Wells)

309 bo/d

(2 Wells)

262 bo/d

(1 Well)

245 bo/d

(1 Well)

345 bo/d

(3 Wells)

Peak Month Average Rates In Project Area

MARATHON

Williams County Development Economics

Development Economics (1,280 Acre Unit)

(1)(2)

(1)

Assumes oil differential of (15%) and assumes gas shrinkage of (10%). Natural gas price held constant at $5/Mcf with no gas differential.

(2)

EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells.  See Additional Disclosures in Appendix.

13

13

Bakken Illustrative Resource Potential

Resource Potential

(1)

(1)

Data is for illustrative purposes only and is based on management assumptions.  EUR refers to management’s internal estimates of reserves potentially recoverable

from successful drilling of wells.  See Additional Disclosures in Appendix.

14

14

Undeveloped Bakken Acreage Provides Net Resource

Potential of ~35 to ~50 MMboe

Bakken (Williams Co. & Montana)

Bakken (Mountrail County)

350 Mboe

500 Mboe

400 MBOE

600 MBOE

Assumed Spacing Unit Size (Acres)

1,280

1,280

1,280

1,280

Estimated Remaining # Wells per Spacing Unit (Bakken Only)

3.0

3.0

1.5

1.5

# Acres per Well (Spacing Unit / # Wells per Unit)

427

427

853

853

GeoResources Net Acres

35,000

35,000

11,000

11,000

Number of Potential Net Drilling Locations

82

82

13

13

Estimated EUR per Well (Mboe)

350

500

400

600

Unrisked Illustrative Resource Potential (Mboe)

28,711

41,016

5,156

7,734

Focused on Improving Economics

15

15

Eagle Ford

Bakken

Improving drilling efficiencies

Drilling without intermediate casing

Pad drilling

Walking rigs

Improving frac efficiencies

Simultaneous / back-to-back frac jobs

300 feet or less between frac stages

Optimizing proppant size and volume

Resin-coated sand

Enhancing knowledge

Taking cores

Micro-seismic

Pilot holes

Monitoring peer activity

Improving drilling efficiencies

Efforts to date have reduced drilling time from

~30 to ~20 days resulting in cost savings of

~$900K in last three wells vs. first three wells

Additional cost savings expected with future pad

drilling and walking rigs

Improving frac efficiencies

Simultaneous / back-to-back frac jobs

Mass sliding sleeves

Infrastructure development

Oil and gas gathering agreement executed

Saltwater disposal wells being developed

Enhancing knowledge

Taking cores

Micro-seismic

Monitoring peer activity

Efforts underway to reduce well costs by $500K to $1.0MM per well

Financial Overview

Capital Plan and Production Guidance

2012 Capital Budget

2011 capital plan of approximately $120 MM

2012 capital plan of $188 MM to $223 MM

Current project allocations favor lower-risk, high

cash flow oil-weighted projects primarily in

Bakken and Eagle Ford

Capital Allocation

17

17

Production Guidance

Year Ending December 31, 2011

5,000 to 5,500 boe/d estimated daily rate

61% to 65% oil

Year Ending December 31, 2012

6,500 to 7,500 boe/d estimated daily rate

70% to 75% oil

($ in millions)

Low

(1)

High

(2)

Notes

Bakken Operated (Williams County and Montana)

$61

$73

23 to 26 gross wells (~31% W.I.)

Bakken Non-Operated (Primarily Mountrail County)

23

23

42 gross wells with Slawson (8% W.I.); 12 with others (1% W.I.)

Eagle Ford (Fayette and Gonzales Counties)

74

86

21 to 24 gross wells (~40% W.I.)

Other Drilling

11

11

Williston basin conventional, St. Martinville and Chalk drilling

Acreage and Seismic

15

25

Primarily Eagle Ford and Bakken

Infrastructure and Other

4

5

Saltwater disposal and other infrastructure and equipment

Total Expected 2012 Capital Expenditures

$188

$223

(1) Assumes GEOI grows to 3 drilling rigs in both the Bakken and Eagle Ford in 2012 with gross well costs of $8.0

million on GEOI operated Bakken wells and $8.5 million on GEOI operated Eagle Ford wells.

(2) Assumes GEOI grows to 4 drilling rigs in both the Bakken and Eagle Ford by late 2012 with gross well costs of $8.5

million on GEOI operated Bakken wells and $9.0 million on GEOI operated Eagle Ford wells.

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

2008

2009

2010

Twelve Mos.

Ended

9/30/11

$49.0

$45.8

$66.7

$77.6

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

2008

2009

2010

3Q 2011

0.8x

1.5x

1.3x

0.0x

18

Adjusted EBITDAX

(1)

Debt / Trailing 12 Mos. Adj. EBITDAX

(1)

Conservative use of leverage to maintain strong balance sheet

Ability to fund 2012 capital budget with cash flow and undrawn debt capacity

Twelve months ended 9/30/11 EBITDAX

(1)

= $77.6 MM

$216 MM of liquidity

-

Undrawn revolver with $180 MM borrowing base (commitment received in October 2011)

-

September 30, 2011 cash balance of $36 MM

Strong Financial Position

($ in millions)

(1)

Adjusted EBITDAX is a non-GAAP financial measure. See  reconciliation of net income to Adjusted EBITDAX following in Appendix.

18

Investment Highlights

Value Creation

Significant upside from Eagle Ford and Bakken positions

Eagle Ford Shale -

25,000 net acres

Bakken Shale -

46,000 net acres

Ongoing leasing program to further expand acreage

Solid proved reserve and production base

24

MMBOE

of

proved

reserves

(1)

with

bias

towards

liquids

High level of operating control

Additional gas and oil upside identified in conventional assets

Strong financial position to execute development plans

Significant free cash flow from existing assets to invest in resource plays

Unlevered balance sheet

Experienced management and technical team with large ownership stake

Successful

track

record

of

creating

value

and

liquidity

for

shareholders

Cost

effective

operator

with

significant

operating

experience

in

unconventional

resource

plays

Board

and

management

own

approximately

20%

of

the

company

(1)

Does not include interests in affiliated partnerships. Reserves based on SEC pricing as of 1/1/11.  See Additional Disclosures in Appendix.

19

Appendix

21

Giddings Field –

Austin Chalk

29,000 net acres held

17 wells drilled –

100% success

WI ranges from 37% -

53%

Operating control

Majority of acreage held-by-production

Assets represent value option on gas

prices

Multiple additional drilling locations

(primarily gas weighted)

20%+ IRR at $4.00 gas with 60%+ IRR at

$6.00 gas

Additional upside includes:

Eagle Ford, Georgetown and Yegua

potential

Rate increase potential on existing wells

from slick water fracture stimulations 

Recently completed drilling W. Cannon

Unit in northwest Grimes County

(43.4% WI)

1,014 Boe/d rate for first 60 days

67% oil

APACHE

APACHE

APACHE

APACHE

APACHE

CWEI

CWEI

MAGNUM-HUNTER

Lee

Washington

Waller

Fayette

Austin

Colorado

Milam

Brazos

Grimes

Burleson

Giddings Field Acreage

Eagle Ford AMI

21

GEOI West Cannon Unit

60 Day Avg.: 1,014 Boe/d

22

Management History

2004-

2007

Southern Bay Energy, LLC

Gulf Coast, Permian Basin

REVERSE MERGED INTO

GEORESOURCES, INC.

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 TURNED

AROUND AND MONETIZED

Preferred investors –

17% IRR

Initial investors –

4x return

Track record of creating value and liquidity for

shareholders

Extensive industry and financial relationships 

Significant technical and financial experience

Multiple long-term repeat shareholders

Cohesive management and technical staff

Team has been together for up to 23 years through

multiple entities 

22

23

Quarterly Production By Area

Diverse production base from multiple areas

Bakken and Eagle Ford production are growing

Oil-weighted production continues to accelerate

23

Daily Production by Area

(Boe/d)

3 Mos Ended 9/30/11

3 Mos Ended 6/30/11

Rate

% Oil

Rate

% Oil

Growth

Bakken

1,582

92%

1,255

92%

26%

Eagle Ford

281

98%

33

100%

755%

Austin Chalk

1,513

20%

1,326

18%

14%

Other

2,169

72%

2,135

70%

2%

Total

5,545

65%

4,749

61%

17%

Bakken AMI Drilling Locations

24

Note:

Information

as

of

November,

2011.

GEOI

operated

wells

are

labeled

with

well

names.

Black

labels

represent

GEOI

wells

that

have

been

spud,

red

labels

represent

GEOI

wells

that

have

been

surveyed

but

not

yet

spud.

A

green

dot

indicates

that

the

well

is

producing,

a

solid

blue

dot

indicates

the

well

is

drilling/completing,

and

a

blue

open

circle

means

that

it

is

a

location

to

be

spud

in

the

future. 

Marathon Wells

Development Economics Table

Development Economics

(2)

(1)

Assumes Bakken and Eagle Ford oil differentials of (15%) and (5%), respectively. Assumes Bakken and Eagle Ford gas shrinkage of (10%) and (15%), respectively.

Natural gas price held constant at $5/Mcf with an assumed differential of +20% in the Eagle Ford and no differential in the Bakken. 

(2)

EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells. These estimates do not necessarily represent reserves

as defined under SEC rules and by their nature and accordingly are more speculative and substantially less certain of recovery and no discount or risk adjustment is

included in the presentation. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests could differ substantially.

25

Bakken Shale (Williams Co., North Dakota)

Eagle Ford Shale (Fayette Co., Texas)

350 Mboe

500 Mboe

350 Mboe

500 Mboe

Well Assumptions

Drilling & Completion Cost ($M)

$8,500

$8,500

$9,000

$9,000

Lateral Length (feet)

10,000

10,000

5,000

5,000

WI

100%

100%

100%

100%

NRI

80.0%

80.0%

82.5%

82.5%

First 30 Day Average Oil IP (Bopd)

441

689

448

847

GOR (Scf/bbl)

600

600

1,000

1,000

Economics @ $80/bbl and $5/Mcf

(1)

NPV @ 10%

$1,335

$5,715

$2,979

$7,847

IRR

16.2%

42.9%

25.1%

66.4%

Payout (Yrs)

4.0

1.9

2.7

1.3

ROI

1.7

2.4

1.8

2.5

Price Sensivity (IRR)

(1)

$100/Bbl (WTI)

30.0%

68.3%

44.4%

109.1%

$90/Bbl (WTI)

22.9%

54.9%

34.7%

85.6%

$80/Bbl (WTI)

16.2%

42.9%

25.1%

66.4%

$70/Bbl (WTI)

9.9%

30.0%

17.2%

48.5%

26

Proved Reserves

(1)

PV-10% is a non-GAAP financial measure.  See reconciliation of SEC PV 10% to standardized measure in Appendix.

(2)

Utilizing five year NYMEX forward prices at 1/1/11.  See Additional Disclosures in Appendix.

($ in millions)

Oil

Gas

Total

% of

Corporate Interests

MMBO

BCF

MMBOE

Total

PV-10

PDP

8.9

33.0

14.4

60.0%

$239.6

PDNP

2.3

6.1

3.4

14.2%

68.5

PUD

3.2

18.4

6.2

25.8%

70.2

Total Proved Corporate Interests

14.4

57.6

24.0

100.0%

378.3

Partnership Interests

0.1

8.0

1.4

12.0

Total Proved Corporate and Partnerships

14.5

65.6

25.4

$390.3

26

Proved Reserves –

SEC Pricing at 1/1/11

Proved Reserves –

Forward Strip Pricing at 1/1/11

($ in millions)

Oil

Gas

Total

% of

Corporate Interests

MMBO

BCF

MMBOE

Total

PV-10

PDP

9.2

35.2

15.1

60.2%

$303.6

PDNP

2.4

6.3

3.4

13.5%

83.7

PUD

3.3

19.6

6.6

26.3%

98.5

Total Proved Corporate Interests

14.9

61.1

25.1

100.0%

485.8

Partnership Interests

0.1

8.3

1.4

15.9

Total Proved Corporate and Partnerships

15.0

69.4

26.5

$501.7

(1)

(2)

Hedge Portfolio

Oil Hedges

GEOI uses commodity price risk management in order to execute its business plan throughout

commodity price cycles

Natural Gas Hedges

$85 .00  to

$110.00

27

Weighted Average Gas Hedge Price

2011

2012

2013

$6.76

$5.48

$4.85

Collar

Swap

Note:

2011

hedge

volume

and

weighted

average

price

data

is

as

of

10/1/2011.

Weighted Average Oil Hedge Price

2011

2012

2013

$85.11

$90.76

$101.85

28

Operating Performance

Historical Operating Data

12 Mos Ended

Years Ended December 31,

9/30/2011

2010

2009

2008

Key Data:

Average realized oil price  ($/Bbl)

83.45

$          

70.33

$    

61.09

$    

82.42

$    

Avg. realized natural gas price ($/Mcf)

5.30

$            

5.30

$       

3.97

$       

8.12

$       

Oil production (MBbl)

1,127

1,060

851

743

Natural gas production (MMcf)

4,219

4,789

4,944

2,962

% Oil

62%

57%

51%

60%

($ in millions except per share data)

Total revenue

123.7

$          

107.0

$    

81.0

$       

94.6

$       

Reported net income attributable to GeoResources

29.8

$            

23.3

$       

9.8

$         

13.5

$       

Adjusted net income

(1)

29.7

$            

24.3

$       

10.9

$       

16.3

$       

Adjusted earnings

(1)

per share (diluted)

1.22

$            

1.21

$       

0.66

$       

1.03

$       

Adjusted EBITDAX

(1)

77.6

$            

66.7

$       

45.8

$       

49.0

$       

28

(1)

Adjusted  Net Income and Adjusted EBITDAX are non-GAAP financial measures.  See  reconciliation of net income to Adjusted Net Income and Adjusted EBITDAX in Appendix.

28

29

Reconciliation of non-GAAP Measures

(1) As used herein, Adjusted EBITDAX is calculated as net income

attributable to GeoResources, Inc. before interest, income taxes, depreciation, depletion and amortization, and

exploration expense and further excludes non-cash compensation, impairments, hedge ineffectiveness and income

or loss on derivative contracts.  Adjusted EBITDAX should not be

considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is

not in accordance with, nor superior to, generally accepted accounting principles,

but provides additional information for evaluation of our operating performance.

29

12 Mos Ended

Years Ended December 31,

9/30/2011

2010

2009

2008

($ in millions)

Net Income Attributable to GeoResources

29.8

$            

23.3

$     

9.8

$        

13.5

$     

Adjustments:

(Gain) on sale of property and equipment

(1.5)

$             

(1.0)

$      

(1.4)

$      

(4.4)

$      

Interest and other income

(0.6)

$             

(1.5)

$      

(1.0)

$      

(0.8)

$      

Interest Expense

2.3

$               

4.7

$        

5.0

$        

4.8

$        

Income Taxes

18.5

$            

11.9

$     

5.1

$        

7.8

$        

Depreciation, depletion and amortization

25.5

$            

24.7

$     

22.4

$     

16.0

$     

Unrealized (gain) / loss on hedge and derivatives

0.6

$               

(0.9)

$      

0.3

$        

0.4

$        

Non-cash Compensation

1.7

$               

1.1

$        

1.4

$        

0.6

$        

Exploration

0.6

$               

0.8

$        

1.4

$        

2.6

$        

Impairments

0.7

$               

3.4

$        

2.8

$        

8.3

$        

Adjusted EBITDAX

(1)

77.6

$            

66.7

$     

45.8

$     

49.0

$     

Adjusted EBITDAX Reconciliation

30

Reconciliation of non-GAAP Measures

30

12 Mos Ended

Years Ended December 31,

9/30/2011

2010

2009

2008

($ in millions)

Net Income Attributable to GeoResources

29.8

$            

23.3

$     

9.8

$        

13.5

$     

Adjustments:

Unrealized (gain) / loss on hedge and derivatives

0.6

$               

(0.9)

$      

0.3

$        

0.4

$        

Impairments

0.7

$               

3.4

$        

2.8

$        

8.3

$        

(Gain) on sale of property and equipment

(1.5)

$             

(1.0)

$      

(1.4)

$      

(4.4)

$      

Tax impact

0.1

$               

(0.6)

$      

(0.7)

$      

(1.7)

$      

Adjusted Net Income

29.7

$            

24.3

$     

10.9

$     

16.3

$     

Adjusted Net Income Reconciliation

(1) Tax impact is estimated as 38.1% and 37.6% of the pre-tax adjustment amounts for 2011 and prior years respectively. 

(2)  As used herein, adjusted net income is calculated as net income attributable to GeoResources, Inc. excluding (gains) and losses on property sales, impairment of proved and unproved

properties

and

an

unrealized

(gains)

and

losses

related

to

hedge

ineffectiveness

and

income

or

loss

on

derivative

contracts.

Adjusted

net

income

should

not

be

considered

as

an

alternative

to

net

income

(as

an

indicator

of

operating

performance)

or

as

an

alternative

to

cash

flow

(as

a

measure

of

liquidity

or

ability

to

service

debt

obligations)

and

is

not

in

accordance

with,

nor

superior to, generally accepted accounting principles, but provides additional information for evaluation of our operating performance.

(1)

(2)

Standardized Measure

SEC PV-10 Reconciliation to Standardized Measure

(1)

(1)

PV-10% is not a measure of financial or operating performance under

GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of

discounted future net cash flows as defined under GAAP.

(2)

Through two affiliated partnerships.

($ in millions)

1/1/2011

Direct interest in oil and gas reserves:

Present value of estimated future net revenues (PV-10%)

$378.3

Future income taxes at 10%

(101.3)

Standardized measure of discounted future net cash flows

$277.0

Indirect interest in oil and gas reserves:

Present value of estimated future net reserves (PV-10%)

$12.0

Future income taxes at 10%

(4.0)

Standardized measure of discounted future net cash flows

$8.0

31

(2)

The disclosures below apply to the contents of this presentation:

In

April

2007,

GeoResources,

Inc.

(“GEOI”

or

the

“Company”)

merged

with

Southern

Bay

Oil

&

Gas,

L.P.

(“Southern

Bay”)

and

a

subsidiary

of

Chandler

Energy,

LLC

and

acquired

certain

oil

and

gas

properties

(collectively,

the

“Merger”).

The

Merger

was

accounted

for

as

a

reverse

acquisition

of

GEOI

by

Southern

Bay.

Therefore,

any

information

prior

to

2007

relates

solely

to

Southern

Bay. 

Cautionary

Statement

–

The

SEC

has

established

specific

guidelines

related

to

reserve

disclosures,

including

prices

used

in

calculating

PV

10%

and

the

standardized

measure

of

discounted

future

net

cash

flows.

PV

10%

is

not

a

measure

of

financial

or

operating

performance

under

General

Accepted

Accounting

Principles

(GAAP),

nor

should

it

be

considered

in

isolation

or

as

a

substitute

for

the

standardized

measure

of

discounted

future

net

cash

flows

as

defined

under

GAAP.

In

addition,

alternate

pricing

methodologies,

such

as

the

NYMEX

forward

strip

price

curve,

are

not

provided

for

under

SEC

guidelines

and

therefore

do

represent

GAAP.

PV-10%

is

not

a

measure

of

financial

or

operating

performance

under

GAAP,

nor

should

it

be

considered

in

isolation

or

as

a

substitute

for

the

standardized

measure

of

discounted

future

net

cash

flows

as

defined

under

GAAP.

PV-10

%

for

SEC

price

calculations

are

based

on

the

12-month

unweighted

average

prices

at

year-end

2010

of

$79.43

per

Bbl

for

oil

and

$4.37

per

Mmbtu

for

natural

gas.

These

prices

were

adjusted

for

transportation,

quality,

geographical

differentials,

marketing

bonuses

or

deductions 

and

other

factors

affecting

wellhead

prices

received.

For

the

Strip

Price

reserve

case,

five

year

NYMEX

strip

pricing

at

12/30/10

was

utilized

for

2011

–

2015.

NYMEX

oil

strip

ranged

from

$93.85

per

Bbl

to

$92.48

per

Bbl

and

then

constant

thereafter.

NYMEX

gas

strip

ranged

from

$4.59

per

Mmbtu

to

$5.64

per

Mmbtu

and

then

held

constant

thereafter.

These

prices

were

adjusted

for

transportation,

quality,

geographical

differentials,

marketing

bonuses

or

deductions

and

other

factors

affecting

wellhead

prices

received.

Actual

realized

prices

will

likely

vary

materially

from

the

NYMEX

strip.

The

Company’s

independent

engineers

are

Cawley,

Gillespie

&

Associates,

Inc.

BOE

is

defined

as

barrel

of

oil

equivalent,

determined

using

a

ratio

of

six

MCF

of

natural

gas

equal

to

one

barrel

of

oil

equivalent.

IP

(BO/d

or

BOE/d)

(24

hour

rate)

is

defined

as

the

peak

oil

volume

produced

on

a

daily

basis

through

permanent

production

facilities

that

occur

within

the

first

few

days

of

initial

production

from

the

well.

EUR

estimates

do

not

necessarily

represent

reserves

as

defined

under

SEC

rules

and

by

their

nature

and

accordingly

are

more

speculative

and

substantially

less

certain

of

recovery

and

no

discount

or

risk

adjustment

is

included

in

the

presentation.

Actual

locations

drilled

and

quantities

that

may

be

ultimately

recovered

from

the

Company’s

interests

could

differ

substantially.

32

Additional Disclosures

32