GEORESOURCES INC - FORM 8-K - EX-99.1 - SLIDESHOW PRESENTATION - March 22, 2012

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GeoResources, Inc.
INVESTOR PRESENTATION
MARCH 2012
Exhibit 99.1

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, 2011 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.

Balanced Portfolio
Long-Term
Growth
–
79,000
net
acres
in
two
premier
U.S. liquids-rich resource plays
Strong Current Cash Flow/Profitability
6,116
Boe/d
net
production
in
4Q
2011
(67%
oil)
(1)
6,982
Boe/d
including
acquisition
(62%
oil)
(2)
Geographic
and
Geologic
Diversity
–
Oil
and
gas
assets
in multiple basins
Significant Producing Bakken Position
55,000 net acres (40,000 operated)
Continuing to add to leasehold
Growing to three operated rigs in second quarter of
2012
Substantial Eagle Ford Position
24,000 net acres (primarily operated)
Strong recent drilling results
Two operated rigs currently running
Strong Financial Position
Strong cash flow
Significant liquidity
(1)
Does not include interests in affiliated partnerships. See Additional Disclosures in Appendix.
(2)
Includes 4Q 2011 production generated by assets acquired in February 2012 in the Austin Chalk trend.
3
Company Highlights

1992-1996
Hampton Resources Corp
Gulf Coast
SOLD TO BELLWETHER EXPL.
Preferred investors –
30% IRR
Initial investors –
7x return
2005-2007
Southern Bay Energy, LLC
Gulf Coast, Permian Basin
REVERSE MERGED INTO
GEORESOURCES, INC.
Initial investors –
40% IRR
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
Success with multiple entities over multiple
years
Several long-term repeat shareholders
Extensive industry and financial
relationships 
Significant technical and financial
experience
Team has been together for up to 23 years
through multiple entities 
4
Investors in GEOI have experienced a 4.9x return on capital and a 38%
annualized IRR
(1)
since management took over in 2007
(1)
Return and IRR calculated based on GEOI stock price of $6.77 on date of merger between Southern Bay  Energy and GeoResources, Inc. (April  17, 2007) and stock price of
$32.91 as of March 8, 2012.
Management Track Record

(1)
Reserves
based
on
SEC
pricing
as
of
1/1/12
and
excludes
interests
in
two
affiliated
partnerships.
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.
(3)
Includes
4Q
2011
production
and
estimated
1/1/12
proved
reserves
associated
with
assets
acquired
in
February
in
the
Austin
Chalk
trend.
(4)
Excludes impact of revolver draw down in February 2012 related to acquisition of assets in the Austin Chalk trend.
Reserve and Production Snapshot
(1)
Operations focused on Bakken,
Eagle Ford and Austin Chalk
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 associated with
legacy assets (Austin Chalk, South
Louisiana, Permian)
Strong cash flow generation
Adjusted
EBITDAX
of
$89
MM
(2)
for
year ended December 31, 2011
Significant liquidity
$219MM of cash and revolver
availability
as
of
December
31,
2011
(4)
24,000 net acres
55,000 net acres
200,000+ net acres
5
GEOI
Including
Pre-Acquisition
Acquisition
(3)
01/01/12 Proved Reserves (Mmboe)
29.2
31.7
Oil % (Proved Reserves)
67%
64%
Proved Developed %
70%
70%
4Q 2011 Production (Boe/d)
6,116
                    
6,982
                
Oil % (Production)
67%
62%
Operated Proved Reserves
75%
77%
Company Overview
Eagle Ford
Bakken
Austin Chalk

6
Reserves and Production –
SEC 1/1/12
(1)
2.4
15.7
14.6
20.7
24
29.2
0
5
10
15
20
25
30
35
2006
2007
2008
2009
2010
2011
768
1,826
3,388
4,589
5,090
6,116
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2006
2007
2008
2009
2010
2011
PDP,
55%
PDNP,
15%
PUD,
30%
Oil,
67%
Gas,
33%
Bakken,
24%
Eagle
Ford,
4%
Austin
Chalk,
20%
Other,
52%
January
1,
2012
Proved
Reserves
–
29.2
MMBOE
(1)
Proved
Reserves
(1)(2)
Average
Daily
Production
(BOE/d)
(1)
(1)
Data excludes interests in two affiliated partnerships and also excludes estimated 1/1/12 proved reserves associated with assets acquired in February 2012 in the
Austin Chalk trend.
(2)
2006 – 2011 proved reserves based on SEC pricing.  2008 reserves reflect lower prices and divestitures.  See Additional  Disclosures in Appendix.

FOCUSED ON
DEVELOPMENT
Asset Overview
OIL-WEIGHTED

Williams County Project (28,000 net acres)
Primarily operated with average WI of ~34%
19 gross wells drilled to date (14 producing)
20 to 24 gross wells planned for 2012
Eastern Montana Project (13,000 net acres)
Primarily operated with average WI of ~50%
One operated well drilled to date
Third operated rig to drill in this area beginning in
2Q 2012
Three to five gross Bakken wells planned for 2012
Mountrail County Project (10,000 net acres)
Operated primarily by Slawson Exploration
Average WI of ~8%
Three to four rigs currently running
45-60 gross wells planned for 2012
McKenzie Line Project (4,000 net acres)
Operated primarily by Zavanna, LLC
WI range from 7% to 20% (11% avg.)
One rig running, three wells waiting on completion
Six to eight gross wells planned for 2012
Bakken Shale Overview
8

9
Williams County Project Drilling Results
397 bo/d
(9 Wells)
389 bo/d
(10 Wells)
375 bo/d
(5 Wells)
282 bo/d
(6 Wells)
312 bo/d
(3 Wells)
276 bo/d
(3 Wells)
245 bo/d
(1 Well)
345 bo/d
(3 Wells)
MARATHON
500 bo/d
(2 Wells)
216 bo/d
(3 Wells)
Peak Month Average Rates In Project Area
Concentrated 28,000 net acre block
in NW Williams Co., ND
20 to 24 gross operated wells planned to
be spud in 2012  (6 spud as of mid-March)
25% - 35% WI
Multi-year drilling inventory
2 dedicated rigs currently running
Maintain 2 rig program throughout 2012
Successful initial drilling has de-risked
acreage
265 bo/d peak month average rate on
GEOI operated wells
Focused on cost containment
Targeting $7.0 to $8.0 million well costs
Pad drilling
Building oil and gas gathering system
Installing saltwater disposal wells
production and excludes months with less than 20 days of production.  Source of all production data is NDIC website.
information
as
of
March
2012.
Peak
Month
Avg.
rate
calculated
as
maximum
average
daily
production
rate
within
first
four
calendar
months
of
Note: Peak month average

10
300 Mboe Case Returns
(1)(2)
450 Mboe Case Returns
(1)(2)
(1)
Dry gas price held constant at $4.50/Mcf. See additional assumptions in Appendix.
(2)
EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells.  See Additional Disclosures in Appendix.
Williams County/Eastern Montana Economics

11
Bakken Resource Potential
Undeveloped Bakken Acreage Provides Net
Resource Potential of ~45 to ~68 MMboe
Net Resource Potential
(1)
Bakken
Bakken
(Williams,
McKenzie,
E.
Montana)
(Mountrail County)
300 Mboe
450 Mboe
400 Mboe
600 Mboe
Assumed Spacing Unit Size (Acres)
1,280
1,280
1,280
1,280
Estimated # Wells per Spacing Unit (Bakken Only)
4
4
3
3
# Acres per Well (Spacing Unit / # Wells per Unit)
320
320
427
427
Estimated 1/1/12 Remaining Net Undeveloped Acres
43,500
43,500
5,000
5,000
Number of Potential Net Drilling Locations
136
136
12
12
Estimated EUR per Well (Mboe)
300
450
400
600
Net Resource Potential (Mboe)
40,781
61,172
4,688
7,031
(1)
Data is for illustrative purposes only and is based on management assumptions.  Resource potential estimate excludes developed acreage on which proved reserves are already 
booked.  EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells.  See Additional Disclosures in Appendix.

Concentrated 24,000 net acre
block in volatile oil window in
Fayette/Gonzales Counties
Note:
Information
as
of
March
2012.
12
Primarily operated with average WI
of 35% -
55%
10 gross wells drilled to date (7
producing)
20 to 24 gross operated wells to be
spud in 2012
Eagle Ford AMI
Partnered with Ramshorn
Investments, Inc., an affiliate of
Nabors Industries, Ltd.
GEOI retained 50% WI and
operations
Multi-year drilling inventory
Two dedicated rigs under contract
and drilling
Eagle Ford Shale Overview

13
Note:
Source
of
GeoResources’
data
is
internal
figures.
Information
as
of
March
2012.
Eagle Ford Drilling Results
Peebles #1H
30 day Avg. Rate:  436 Boe/d
Black Jack Springs #1H
30 day Avg. Rate:  369 Boe/d
Arnim #1H & 2H
10 day Avg. Rate:  636 Boe/d
Flatonia East #1H & #2H 
30 day Avg. Rate:  428 Boe/d
Newtonville #1H
30 day Avg. Rate:  566 Boe/d
12 wells spud to date
Seven wells drilled, completed and on
production
445 boe/d 30-day avg. rate (excluding
most recently completed Arnim wells)
Positive offset operator activity
Magnum Hunter Resources
Penn Virginia
EOG
Austin Chalk upside on acreage block
Participated in oily Chalk well in 2011 with
another operator on block
Recently spud first operated oily Chalk
location
Successful drilling has de-risked
acreage

(1)
Dry gas price held constant at $4.50/Mcf. See additional assumptions in Appendix.
(2)
EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells.  See Additional Disclosures in Appendix.
14
325 Mboe Case Returns
(1)(2)
500 Mboe Case Returns
(1)(2)
Eagle Ford Economics

15
(1)
Data is for illustrative purposes only and is based on management assumptions.  Resource potential estimate excludes developed acreage on which proved reserves
are already booked.  EUR refers to management’s internal estimates of reserves potentially recoverable from successful drilling of wells.  See Additional Disclosures
in Appendix.
Undeveloped Eagle Ford Acreage Provides Net
Resource Potential of ~50 to ~80 MMboe
Eagle Ford Shale
325 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
Estimated 1/1/12 Remaining Net Undeveloped Acres
23,750
23,750
Number of Potential Net Drilling Locations
158
158
Estimated EUR per Well (Mboe)
325
500
Net Resource Potential (Mboe)
51,458
79,167
Eagle Ford Resource Potential
Resource Potential
(1)

Drilling without intermediate casing
Pad drilling
Walking rigs
Recent well drilled in just 21 days
16
Improving drilling efficiencies
Improving drilling efficiencies
Efforts to date have reduced drilling time from
~30 to ~20 days resulting in cost savings of
~$900K compared to first several wells
Additional cost savings expected with future
pad drilling and walking rigs
Improving frac efficiencies
Simultaneous / back-to-back frac jobs
300 feet or less between frac stages
Increased proppant size and volume
Resin-coated sand
Enhancing knowledge
Taking cores
Micro-seismic
Pilot holes
Monitoring peer activity
Improving frac efficiencies
Simultaneous / back-to-back frac jobs
Mass sliding sleeves
Infrastructure development
Oil and gas gathering lines being installed
Saltwater disposal wells being developed
Enhancing knowledge
Taking cores
Micro-seismic
Monitoring peer activity
Improving Economics
Eagle Ford
Bakken

Austin Chalk
17
(1)
Includes 4Q 2011 production associated with assets acquired in February 2012 in the Austin Chalk trend.
Giddings Area (~30,000 net
acres):
17 wells drilled –
100% success
WI ranges from 37% -
53%
Majority of acreage held-by-
production
20+ remaining gassy locations -
Valuable “option”
on future gas
prices
Recently drilled two successful
oily Chalk wells
Recently commenced drilling
the Rightmer A #2HRE (50%
WI) in Fayette County
Brookeland Area (~170,000
net acres)
WI averages ~70%
Majority of acreage held-by-
production
Multiple drilling locations
identified (~50% liquids)
Eagle Ford AMI
Rightmer A #2HRE
Currently Drilling
Tilicek #1H
30 Day Avg.: 326 Boe/d (93% oil)
200,000 operated net acres across Giddings and Brookeland field areas of the Austin Chalk trend
Acreage provides potential for multiple targets across large geographic region (Austin Chalk,
Woodbine, Buda, Wilcox, Edwards, etc.)

FOCUSED ON
MAXIMIZING
SHAREHOLDER
VALUE
Financial Overview

2012 capital plan of $194 MM to $272 MM
(excluding Q1 2012 acquisitions)
Current project allocations favor lower-risk,
high cash flow oil-weighted projects primarily
in Bakken and Eagle Ford
2012 Capital and Production Guidance
19
Year Ending December 31, 2012
7,300 to 8,300 boe/d estimated daily rate
70% to 75% oil
Drilling and completion efficiencies provide
opportunity to achieve high end of range
($ in millions)
Low
High
Notes
Bakken (Williams County Project Area)
$45
$58
20-24 gross wells at $7.5-$8.0 (30% WI)
Bakken (Eastern Montana Project Area)
10
18
3-5 gross wells at $7.5-$8.0 (45% WI)
Bakken (Mountrail County Project Area)
19
28
46-60 gross wells at $5.5-$8.5 (6% WI)
Bakken (McKenzie Line Project Area)
6
8
6-8 gross wells at $9.5-$10.5 (10% WI)
Eagle Ford
73
98
20-24 gross wells at $8.0-$9.0 (46% WI)
Austin Chalk
3
7
2-4 gross wells at $2.8-$3.3 (50% WI)
Other Drilling
10
14
Other conventional/legacy properties
Total Drilling Capital Expenditures
$166
$231
Acreage and Seismic
25
35
Bakken and Eagle Ford Primarily
Infrastructure and Other
3
6
Saltwater disposal, etc.
Total Capital Expenditures Excluding Acquisitions
$194
$272
1Q 2012 Acquisitions (Bakken and Chalk)
53
53
Total Capital Expenditures
$247
$325
McKenzie Line & Brookeland Acquisitions
Capital Allocation
Production Guidance
2012 Capital Budget

Conservative use of leverage to maintain strong balance sheet
Ability to fund 2012 capital budget with cash flow and undrawn debt capacity
Year
ended
12/31/11
Adjusted
EBITDAX
(1)
=
$89.2
MM
$219 MM of liquidity
(2)
-
Undrawn
revolver
with
$180
MM
borrowing
base
(2)
-
December 31, 2011 cash balance of $39 MM
($ in millions)
Strong Financial Position
20
(1)
EBITDAX is a non-GAAP financial measure.  See Additional Disclosures in Appendix.
(2)
Excludes revolver draw down in February 2012 related to acquisition of assets in the Austin Chalk trend.
Debt / Trailing 12 Mos. Adj. EBITDAX
(1)
Adjusted EBITDAX
(1)
$49.0
$45.8
$66.7
$89.2
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
$70.0
$80.0
$90.0
$100.0
2008
2009
2010
2011
0.8x
1.5x
1.3x
0.0x
-
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
2008
2009
2010
2011

Long-Term Growth Potential Imbedded in Eagle Ford and Bakken positions
Multi-year drilling inventory
100+ Mmboe of undeveloped net resource potential
Ongoing leasing and acquisition program to further expand acreage positions
Solid Proved Reserve and Production Base
31.7
MMBOE
of
proved
reserves
(including
acquisitions)
(1)
with
bias
towards
liquids
High level of operating control
Additional oil and gas 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 more than 20% of the company
Summary Investment Highlights
21
(1)
Reserve data as of January 1, 2012. Reserves based on SEC pricing as of 1/1/12.  Reserves include February 2012 acquisition of producing properties in the Austin Chalk
trend.  Data excludes interests in two affiliated partnerships.
See Additional Disclosures in Appendix.

Financials
Production
Reserves
Hedging
Additional Disclosures
Appendix

Select Historical Operating and Financial Data
Historical Performance
23
(1)
EBITDAX and adjusted net income are non-GAAP financial measure.  See Additional Disclosures in Appendix.
Years Ended December 31,
2011
2010
2009
2008
Key Data:
Avg. realized oil price  after hedges ($/Bbl)
88.42
$
70.33
$
61.09
$
82.42
$
Avg. realized natural gas price after hedges ($/Mcf)
5.36
$   
5.30
$   
3.97
$  
8.12
$   
Oil production (MBbl)
1,222
1,060
851
743
Natural gas production (MMcf)
4,209
4,789
4,944
2,962
% Oil
64%
57%
51%
60%
($ in millions except per share data)
Total revenue
137.7
$
107.0
$
81.0
$   
94.6
$  
Reported net income attributable to GeoResources
31.3
$   
23.3
$  
9.8
$     
13.5
$   
Adjusted net income
(1)
34.9
$  
24.3
$  
10.9
$   
16.3
$   
Adjusted earnings
per share (diluted)
1.36
$   
1.21
$   
0.66
$  
1.03
$   
Adjusted EBITDAX
(1)
89.2
$  
66.7
$  
45.8
$   
49.0
$  

(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.
Reconciliation of Non-GAAP Measures
24
Adjusted EBITDAX Reconciliation
Years Ended December 31,
2011
2010
2009
2008
($ in millions)
Net Income Attributable to GeoResources
31.3
$    
23.3
$ 
9.8
$    
13.5
$  
Adjustments:
(Gain) on sale of property and equipment
(0.9)
(1.0)
(1.4)
(4.4)
Interest and other income
(0.4)
(1.5)
(1.0)
(0.8)
Interest Expense
1.9
4.7
5.0
4.8
Income Taxes
20.0
11.9
5.1
7.8
Depreciation, depletion and amortization
27.7
24.7
22.4
16.0
Unrealized (gain) / loss on hedge and derivatives
0.6
(0.9)
0.3
0.4
Non-cash Compensation
2.1
1.1
1.4
0.6
Exploration
0.9
0.8
1.4
2.6
Impairments
6.0
3.4
2.8
8.3
Adjusted EBITDAX
(1)
89.2
$   
66.7
$ 
45.8
$ 
49.0
$ 

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.
Reconciliation of Non-GAAP Measures
25
Years Ended December 31,
2011
2010
2009
2008
($ in millions)
Net Income Attributable to GeoResources
31.3
$    
23.3
$ 
9.8
$    
13.5
$  
Adjustments:
Unrealized (gain) / loss on hedge and derivatives
0.6
(0.9)
0.3
0.4
Impairments
6.0
3.4
2.8
8.3
(Gain) on sale of property and equipment
(0.9)
(1.0)
(1.4)
(4.4)
Tax impact
(1)
(2.2)
(0.6)
(0.7)
(1.7)
Adjusted Net Income
(2)
34.9
$   
24.3
$ 
10.9
$ 
16.3
$  

Diverse production base from multiple areas
Oil-weighted production continues to accelerate
Production by Area
26
(Boe/d)
3 Mos Ended 12/31/11
3 Mos Ended 9/30/11
Rate
% Oil
Rate
% Oil
Growth
Bakken
1,998
                      
93%
1,582
                      
92%
26%
Eagle Ford
176
                          
94%
281
                          
98%
-37%
Austin Chalk
1,716
                       
26%
1,513
                       
20%
13%
Other
2,226
                      
80%
2,169
                      
72%
3%
Total
6,116
                    
67%
5,545
                    
65%
10%
(1)
Data excludes estimated production associated with the February 2012 acquisition of producing properties in the Austin Chalk trend.
Daily Production by Area
(1)

(1)
Data excludes estimated reserves associated with the February 2012 acquisition of producing properties in the Austin Chalk trend.
(2)
PV-10% is a non-GAAP financial measure.  See reconciliation of SEC PV-10 to standardized measure in Appendix.
($ in millions)
Oil
Gas
Total
% of
MMBO
BCF
MMBOE
Total
PV-10
(2)
PDP
10.8
31.9
16.1
55.1%
$376.7
PDNP
3.1
6.6
4.2
14.4%
109.5
PUD
5.8
18.8
8.9
30.5%
128.7
Total Proved Corporate Interests
19.7
57.3
29.2
100.0%
$614.9
Partnership Interests
0.1
7.0
1.2
11.2
Total Proved Corporate and Partnerships
19.8
64.3
30.4
$626.1
% Oil and % Gas
64.8%
35.2%
Proved Reserve Summary
27
GEOI Proved Reserves
(1)
–
SEC Pricing at 1/1/12

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.
Standardized Measure
28
($ in millions)
1/1/2012
Direct interest in oil and gas reserves:
Present value of estimated future net revenues (PV-10)
$614.9
Future income taxes at 10%
(188.1)
Standardized measure of discounted future net cash flows
$426.8
Indirect interest in oil and gas reserves:
(2)
Present value of estimated future net reserves (PV-10)
$11.2
Future income taxes at 10%
(4.2)
Standardized measure of discounted future net cash flows
$7.0

Oil Hedges
GeoResources uses commodity price risk management in order to execute its business plan
throughout commodity price cycles
Natural Gas Hedges
Hedging
Collar
Swap
Weighted Average Oil Hedge Price
2012
2013
$96.21
$102.18
Weighted Average Gas Hedge Price
2012
2013
$5.15
$4.18
29

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 2011 of $96.19 per Bbl for oil and $4.11 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.  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.
EUR estimates do not necessarily represent reserves as defined under SEC rules and by their nature are more speculative
and substantially less certain of recovery.  Further, 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. 
Additional Disclosures

GEORESOURCES INC Reports

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