Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - GEORESOURCES INC | d239786d8k.htm |
| EX-99.1 - PRESS RELEASE - GEORESOURCES INC | d239786dex991.htm |
 Corporate Profile
October, 2011
Exhibit 99.2 |
 Forward-Looking Statements
2
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. |
 3
Corporate 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
–
4,749
Boe/d
of
production in 2Q 2011 (61% 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
Growing to 3 operated rigs in early 2012
Significant Producing Bakken Position
46,000 net acres (33,200 operated)
Continually leasing
2 dedicated rigs currently running on operated position (growing
to 3 in early 2012)
(1)
Does not include interests in affiliated partnerships. Reserves based on SEC
pricing as of 1/1/11. See Additional Disclosures in Appendix. |
 Company Overview
46,000 net acres
Independent oil and natural gas
company focused on operations in the
Southwest, Gulf Coast and Williston
Basin
Significant upside potential through
growing positions in liquids-rich resource
plays:
61% of 2 quarter 2011 production is oil
and expected to increase through near-
term development in the Eagle Ford and
Bakken
Operate approximately 75% of proved
reserves
Generated Adjusted EBITDAX of $71
MM
(2)
during twelve month period ended
June 30, 2011
Eagle Ford
25,000 net acres
4
01/01/11 Proved Reserves (MMBOE)
24.0
Oil % (Reserves)
60%
Proved Developed %
74%
2Q 2011 Production (Boe/d)
4,749
Oil % (Production)
61%
Operated Production
75%
Eagle Ford –
25,000 net acres
Bakken –
46,000 net acres
nd
Bakken
(1)
Reserve data as of January 1, 2011 and production data is for 2Q 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.
Company
Highlights
(1) |
 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
(3)
Undeveloped,
26%
Developed
Non-
Producing,
14%
Producing,
60%
Gas
40%
Oil
60%
Mid-Con
6%
Permian Basin
9%
Louisiana
16%
Other
3%
Gulf
Coast/ETX/S
TX
34%
Williston
32%
(3)
2.4
0.0
5.0
10.0
15.0
20.0
25.0
15.7
14.6
20.7
24.0
2006
2007
2008
2009
2010
768
1,826
3,388
5,090
4,589
0
1,000
2,000
3,000
4,000
5,000
6,000
2006
2007
2008
2009
2010
30.0 |
 Oil
Weighted Development GeoResources Asset Overview
6 |
 Eagle
Ford Shale Overview o
Upfront cash payment
o
Will fund 100% of cost of first six
horizontal wells
Note:
Information as of August, 2011.
7
25,000 net acres primarily located in
Southwest Fayette County, TX
Eagle Ford AMI
Leasehold continues to increase
Fayette County: 20,300 net acres
Gonzales County: 2,700 net acres
Atascosa & McMullen counties
combined: 1,800 net acres
Plan to spud 8 -
9 gross wells in 2011 and
21 -
24 gross wells in 2012
2011 drilling program averages ~45% WI
Ramshorn Investments, Inc., an affiliate of
Nabors Industries, Ltd. purchased a 50%
interest
GEOI retains 50% WI and operations |
 Eagle
Ford Shale Volatile oil window
On strike with offset operator activity in
Gonzales County
Successful recent drilling results
Completed first three wells in Fayette County
in June/July 2011
o
Flatonia
East
Unit
#1-H:
~3,200’
lateral,
10
stages, 50% WI
o
Flatonia
East
Unit
#2-H:
~4,800’
lateral,
14
stages, 50% WI
o
Black
Jack
Spring
Unit
#1H:
~5,900’
lateral,
16 stages, 43.5% WI
Recently
drilled
Peebles
Unit
#1H:
4,800’
lateral, 39.8% WI –
Awaiting Frac
Multi-year drilling inventory
2nd operated rig coming in Oct. 2011
Planning for 3 operated rigs in early 2012
8
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
September
2011.
GEOI Peebles #1H
Awaiting Frac
GEOI Black Jack Springs #1H
30 day Avg. Rate: 369 Boe/d
GEOI Flatonia East #1H
30 day Avg. Rate: 391 Boe/d
GEOI Flatonia East #2H
30 day Avg. Rate: 465 Boe/d
GEOI Arnim “A”
#1H & #2H
Drilling 1 pad Location
MHR Gonzo North #1H
Peak Month Avg.: 471 Boe/d
MHR Gonzo Hunter #1H
Peak Month Avg.: 313 Boe/d
MHR Furrh #1H
Peak Month Avg.: 711 Boe/d
PVA Hawn Holt #4H
Peak Month Avg.: 327 Boe/d
PVA Gardner El Al #1H
Peak Month Avg.: 852 Boe/d
MHR Geo Hunter #1H
Peak Month Avg.: 329 Boe/d
Positive offset operator activity
Magnum Hunter Resources, Penn Virginia and
EOG have had multiple successful wells near
our acreage position in Gonzales County with
single day IPs ranging from 500 to 2,000 bo/d
st |
 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
25,000 net acres in Williams County, ND
6 wells drilled and completed
Continuous drilling with 2 dedicated rigs currently
running
Interests in 100 spacing units (1,280 acres)
Partnered with Slawson Exploration Company
11,000 net acres primarily Mountrail County, ND
4-5 rigs currently running
10,000 net acres in Roosevelt/Richland County, MT
8,200 operated / 1,800 non-operated acres
17 operated 1,280 acre units
Recently
completed
drilling
1
operated
Bakken
well,
Olson #1-21-16H with a 31.4% WI (awaiting Frac)
Participated with Slawson in the Renegade 1-10H,
Battalion 1-3H & Squadron 1-15-14H
Participated with Brigham in the Swindle 16-9 #1H
11
Information as of August 2011. Symbols on map depict permitted or drilled Bakken
locations.
Note:
46,000 total net acres in three project areas
Williams County Project (Operated)
Mountrail County Project (Non-Op)
Eastern Montana Project (Primarily Operated)
st |
 Williams County Project
25,000 net acres in NW Williams Co., ND
First 4 wells have de-risked acreage
Positive offset activity
12
Note:
Information
as
of
August
2011.
30
Day
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
third
party
production
data
is
NDIC
website.
Plan
to
spud
10
-
11
gross
wells
in
2011
and
23 –
26 gross wells in 2012
2011 drilling program averages ~30% WI
Partnered with Resolute Energy in March ‘10
Retained 47.5% WI in project
Carlson
1-11H
(640
acre):
236
Bo/d
30
Day
Avg. (47.5% W.I.)
Siirtola
1-28-33H
(1,280
acre):
246
Bo/d
30
Day Avg. (41.4% W.I.)
Anderson
1-24-13H
(1,280
acre):
372
Bo/d
30
Day Avg. (35.0% W.I.)
Muller
1-21-16H
(1,280
acre):
250
Boe/d
first
30 Day Avg. (31.1% W.I.)
2 dedicated rigs currently running
Planning for 3 operated rigs in 2012
4-5 rigs drilling in and around our AMI
Bakken AMI
Multi-year drilling inventory |
 Williams County Project Activity
13
13
GEOI Anderson 1-24-13H
Peak Month Avg.: 372 Bo/d
NFX Christensen 159-102-17-
20-1H
Peak Month Avg.: 326 Bo/d
OAS Sandaker 5602 11-13H
Peak Month Avg.: 440 Bo/d
OAS NJOS Federal 5602 11-
13H
Peak Month Avg.: 375 Bo/d
GEOI Muller 1-21-16H
30 Day Avg.: 250 Boe/d
GEOI Carlson 1-11H
Peak Month Avg.: 236 Bo/d
(640 ac. unit -
short lateral)
GEOI Siirtola 1-28-33H
Peak Month Avg.: 246 Bo/d
OAS Grimstvedt 5703 42-34H
Peak Month Avg.: 262 Bo/d
GEOI WI = 2.6%
OAS Bean 5703 42-34H
Peak Month Avg.: 298 Bo/d
OAS Horne 5603 44-9H
Peak Month Avg.: 550 Bo/d
OAS Somerset 5602 12-17H
Peak Month Avg.: 352 Bo/d
OAS Ellis 5602 12-17H
Peak Month Avg.: 421 Bo/d
Petro-Hunt NJOS 157-100-
28A-33-1H
Peak Month Avg.: 215 Bo/d
Petro-Hunt NJOS 157-100-
26B-35-1H
Peak Month Avg.: 344 Bo/d
Petro-Hunt Forseth 157-100-
25B-1H
Peak Month Avg.: 325 Bo/d
NFX Christensen 159-102-8-5-
1H
Drilling (GEOI WI 2.2%)
BEXP BCD Farms 16-21
Peak Month Avg.: 485 Bo/d
GEOI Rasmussen 1-21-16H
24 Hr. IP: 835 Boe/d
Note:
Information as of September 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 HPDI website, except for Muller and Rasmussen well data which is based on GeoResources’ internal figures.
|
 Williams County Completion Comparison
14
14
GeoResources Completions
Offset
Completions
Siirtola/Anderson
(Avg.)
Muller and
Rasmussen Wells
Future Completions
(Estimated Avg.)
30 Day Avg. Oil Rate (bbl/d)
309
-
-
500
60 Day Cumulative Oil (bbls)
15,000
-
-
27,000
Days On Pump (1
60 Days)
0
-
-
22
Lateral Length (feet)
9,800
~ 9,800
~ 9,800
9,500
Number of Frac Stages
30
38
34
34
Stage Length (Feet)
327
~250
~290
290
Frac Method
Sleeve & PnP
Plug 'n Perf
Plug 'n Perf
Plug 'n Perf
Sand Volume (MM lbs)
2.8
4.0
3.6
3.7
Sand Type
Sand & Resin-coated
Sand & Ceramic
Sand & Resin-coated
Sand & Ceramic
Current Water Cut (%)
54%
-
-
56%
Gas-Oil Ratio (cf/bbl)
589
-
-
675
Note:
Comparison limited to 1280 acre unit completions in Williams County (T154-157,
R100-104) occurring after June 2009. Water cut and GOR for offset completions are based
on
average
of
most
recent
monthly
data
from
the
wells
in
the
area
and
will
vary
by
well.
Water
cut
and
GOR
for
GeoResources
are
based
on
Carlson,
Siirtola
&
Anderson
wells
current month averages. Source of offset completion data is NDIC
website st |
 15
Mountrail County Project
11,000 net acres primarily in Mountrail County,
ND
W.I. ranges from 1% to 18%
Average WI of ~8%
Partnered
with
experienced
operator
-
Slawson
Exploration
Slawson has 4-5 rigs currently running
Currently have dedicated frac crews under contract
Drilled over 100 wells to date; 100% success
Additional opportunities:
Slawson and others evaluating appropriate Bakken
spacing and infill drilling with several drilling units
containing second wells and proposals for third wells
in the unit
Slawson evaluating Three Forks potential with two
producers
Encouraging offset Three Forks results from EOG
and Whiting where GEOI has minor working
interests
15
Information, except for map, as of August 2011. Yellow-highlighted areas on map represent
GEOI’s acreage position.
Note: |
 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.
16
16 |
 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. 17
17
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 |
 Additional Assets |
 19
Giddings Field –
Austin Chalk
17 wells drilled
–
100% success
19 additional drilling locations
WI ranges from 37%
-
53%
Operating control
Majority of acreage held-by-production
Eastern acreage in Grimes and
Montgomery Counties is dry gas
Western acreage is liquids-rich gas and
condensate
Eagle Ford, Georgetown and Yegua
potential
Rate increase potential from slick water
fracture stimulations
1,035 boe/d avg. for first 31 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
19
29,000 net acres
Eastern Giddings development area
Additional upside includes:
Recently completed drilling W.
Cannon Unit in northwest Grimes
County (43.4% WI) |
 Louisiana -
Louisiana -
St. Martinville & Quarantine Bay
St. Martinville & Quarantine Bay
2,585 net acres of HBP or leased (yellow), 534
net acres of owned minerals (green)
Average WI of 97% and NRI of 91%
2010 cash flow exceeded $3,000,000
Multiple exploration and development
objectives
from
3,000’
–
10,000’
Cumulative shallow production of 15.2 MMBO and
16.6 BCFG
Cumulative production over 125 Bcfe at 10,000’
LOUISIANA
Quarantine Bay Field
St. Martinville Field
126
1
1
1
2
3
4
5
3-1
2
1
1
2
1
1
2
1
2
3
3
3ST1
2
1
1
2
1
1
1
1
1
2
1
1
1
2
31
1
51
3
4
1
4111
211
1
1
131
221
1
1
1
1B
6A
1211
3
3
21
4
1
1
4
1
51
31
2
¹
1
1
9A
14A
15A
11A32A
10A
13A4A
12A17A24A46A
3A1A37A
5A
16A37A
7A
21
4C
1
2
1
3
1
2
2
1
1
1
5
7D
6D
8A
6
1
2
1
3
7
5
4
1C
1
1D
11²
¹
1
2A
18A31A
19A
1
20A
21A
22A
1
1
2
23A
1
8
9
3
2
10
11
1
3
¹1²
12
13
1
1
25A
1
2
3
1
14
4
15
16
1
1
2
17
6
1
6
2
18
1
234
3
19
¹
1E
20
4
26A39A
2
27A
¹234
28A
1
5E
21
2
1
29A
8D
1
1
2
30A
1
1D
²
²34
9D
33A
6
22
1
34A
35A
7
8
1
10D
4
38A
41A
36A
40A
1
5
7
42A
43A
1
1
7
8
9
2E
44A
1
1
45A
5
1
1
1
47A(2)
¹
6
48A52A
49A
50A
54
1
51A
1
²
7
53
1
A-53
20
20
14,000
gross
acres
(13,000
HBP)
33%
WI
below
major
field
plays
Cumulative
production
of
180
MMBO
and
285
BCF
105’
of
net
pay
encountered
22.0%
WI
Currently
producing
1,211
boe/d
(83%
oil)
Significant
deep
exploration
potential
(11,000
-
25,000’);
plus
sub-salt
potential
Prospect
DN:
16.0
MMBO
+
40
BCFG
at
~16,500’
Additional
deeper
prospects
Recent Exploratory Success |
 Financial Overview |
 Capital Plan and Production Guidance
2012 Capital Budget
2011 capital plan of approximately $120 MM
2012 capital plan of $188 MM to $223 MM
Current project allocations favor lower-risk, high
cash flow oil-weighted projects primarily in
Bakken and Eagle Ford
Capital Allocation
22
22
Production Guidance
Year Ending December 31, 2011
5,000 to 5,500 boe/d estimated daily rate
61% to 65% oil
Year Ending December 31, 2012
6,500 to 7,500 boe/d estimated daily rate
70% to 75% oil
($ 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
6
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. |
 23
EBITDAX
(1)
Debt / EBITDAX
(1)
$145 MM borrowing base
Last twelve months EBITDAX
(1)
= $71.0 MM
Cash balance of $48.3 MM as of June 30, 2011
Strong Financial Position
($ in millions)
(1)
EBITDAX is a non-GAAP financial measure. See reconciliation of net income
to EBITDAX following in Appendix. 23
Ability to fund current capital budget with cash flow and undrawn debt
capacity Conservative use of leverage to maintain strong balance sheet
No debt currently outstanding |
 Investment Highlights
Value Creation
Eagle
Ford
Shale
-
25,000
net
acres
Bakken
Shale
-
46,000
net
acres
Ongoing
leasing
program
to
further
expand
acreage
24
MMBOE
of
proved
reserves
(1)
with
bias
towards
liquids
High
level
of
operating
control
Additional
upside
identified
in
conventional
assets
Significant
free
cash
flow
from
existing
assets
to
invest
in
shale
development
Unlevered
balance
sheet
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
19%
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. 24
Significant
upside
from
Eagle
Ford
and
Bakken
positions
Solid
proved
reserve
and
production
base
Strong
financial
position
to
execute
development
plans
Experienced
management
and
technical
team
with
large
ownership
stake |
 Appendix |
 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 $5/Mcf with an assumed differential of +20% in
the Eagle Ford and no differential in the Bakken. (2)
EUR refers to management’s internal estimates of reserves potentially
recoverable from successful drilling of wells. These estimates do not necessarily represent reserves
as defined under SEC rules and by their nature and accordingly are more speculative
and substantially less certain of recovery and no discount or risk adjustment is
included in the presentation. Actual locations drilled and quantities that may be
ultimately recovered from the Company’s interests could differ substantially.
26
Bakken Shale (Williams Co., North Dakota)
Eagle Ford Shale (Fayette Co., Texas)
350 Mboe
500 Mboe
350 Mboe
500 Mboe
Well Assumptions
Drilling & Completion Cost ($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% |
 27
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 profitability and liquidity
Extensive industry and financial relationships
Significant technical and financial experience
Long-term repeat shareholders
Team has been together for up to 23 years through
multiple entities
27
Cohesive management and technical staff |
 28
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. 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
28
Proved Reserves –
SEC Pricing at 1/1/11
Proved Reserves –
Forward Strip Pricing at 1/1/11
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
$501.7
(1)
(2)
Corporate Interests
Corporate Interests
Oil
Gas
Total
% of
Oil
Gas
Total
% of
($ in millions)
($ in millions) |
 Hedge
Portfolio Oil Hedges
GEOI uses commodity price risk management in order to execute its business plan
throughout commodity price cycles
Natural Gas Hedges
29
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
7/1/2011.
Weighted Average Oil Hedge Price
2011
2012
2013
$85.11
$90.76
$101.85 |
 Operating Performance
Historical Operating Data
(1)
Adjusted Net Income and Adjusted EBITDAX are non-GAAP financial
measures. See reconciliation of net income to Adjusted Net Income and Adjusted EBITDAX in Appendix.
6 Mos Ended
Years Ended December 31,
6/30/2011
2010
2009
2008
Key Data:
Average realized oil price ($/Bbl)
88.12
$
70.33
$
61.09
$
82.42
$
Avg. realized natural gas price ($/Mcf)
5.22
$
5.30
$
3.97
$
8.12
$
Oil production (MBbl)
515
1,060
851
743
Natural gas production (MMcf)
2,015
4,789
4,944
2,962
% Oil
61%
57%
51%
60%
($ in millions except per share data)
Total revenue
59.5
$
107.0
$
81.0
$
94.6
$
Reported net income
15.2
$
23.3
$
9.8
$
13.5
$
Adjusted net income
15.1
$
23.9
$
10.9
$
16.3
$
Adjusted earnings
per share (diluted)
0.60
$
1.19
$
0.66
$
1.03
$
Adjusted EBITDAX
38.4
$
66.7
$
45.8
$
49.0
$
30
(1)
(1)
(1) |
 31
Reconciliation of non-GAAP Measures
31
Adjusted EBITDAX Reconciliation
6 Mos Ended
Years Ended December 31,
6/30/2011
2010
2009
2008
($ in millions)
Net Income Attributable to GeoResources
15.2
$
23.3
$
9.8
$
13.5
$
Adjustments:
(Gain) on sale of property and equipment
(0.7)
$
(1.0)
$
(1.4)
$
(4.4)
$
Interest and other income
(0.4)
$
(1.5)
$
(1.0)
$
(0.8)
$
Interest Expense
1.0
$
4.7
$
5.0
$
4.8
$
Income Taxes
9.6
$
12.1
$
5.1
$
7.9
$
Depreciation, depletion and amortization
11.9
$
24.7
$
22.4
$
16.0
$
Unrealized (gain) / loss on hedge and derivatives
0.6
$
(0.9)
$
0.3
$
0.4
$
Non-cash Compensation
0.8
$
1.1
$
1.4
$
0.7
$
Exploration
0.4
$
1.5
$
1.4
$
2.6
$
Impairments
-
$
2.7
$
2.8
$
8.3
$
Adjusted EBITDAX
(1)
38.4
$
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.
|
 32
Reconciliation of non-GAAP Measures
32
6 Mos Ended
Years Ended December 31,
6/30/2011
2010
2009
2008
($ in millions)
Net Income Attributable to GeoResources
15.2
$
23.3
$
9.8
$
13.5
$
Adjustments:
Unrealized (gain) / loss on hedge and derivatives
0.6
$
(0.9)
$
0.3
$
0.4
$
Impairments
-
$
2.7
$
2.8
$
8.3
$
(Gain) on sale of property and equipment
(0.7)
$
(1.0)
$
(1.4)
$
(4.4)
$
Tax impact
-
$
(0.3)
$
(0.7)
$
(1.7)
$
Adjusted Net Income
15.1
$
23.9
$
10.9
$
16.3
$
Adjusted Net Income Reconciliation
(1)
(2)
(1) Tax impact is estimated as 37.6% of the pre-tax adjustment amounts. (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. |
 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.
Our
calculations
of
PV-10%
and
standardized
measure
of
discounted
future
net
cash
flows
at
July
1,
2010
are
based on our internal reserve estimates, which have not been reviewed or audited by
our independent reserve engineers. (2)
Through two affiliated partnerships.
33
($ 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:
(2)
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 |
 The disclosures below apply to the contents of this presentation:
34
Additional Disclosures
34
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. |