Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - GEORESOURCES INC | d8k.htm |
 Corporate Profile
August, 2011
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, 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
Corporate Highlights
Value Creation
Balanced Portfolio
Long-Term Growth –
70,000 net acres in two premier U.S. liquids
resource plays
production in 2Q 2011 (61% oil)
24
Mmboe
proved
reserves;
60%
oil
(1)
Substantial Eagle Ford Position
24,000 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. 3
Strong
Current
Cash
Flow/Profitability
–
4,749
Boe/d
of
production |
 Company Overview
(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.
Bakken
46,000 net acres
Company
Highlights
(1)
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:
Eagle Ford –
24,000 net acres
Bakken –
46,000 net acres
61%
of
2
nd
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
24,000 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% |
 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)
Gas
40%
Oil
60%
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
2.4
15.7
14.6
20.7
24.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
2006
2007
2008
2009
2010
Developed
Non-
Producing,
14%
Undeveloped,
26%
Producing,
60%
Mid-Con
6%
Permian Basin
9%
Louisiana
16%
Other
3%
Gulf
Coast/ETX/S
TX
34%
Williston
32% |
 Oil
Weighted Development GeoResources Asset Overview
6 |
 Eagle
Ford Shale Overview 24,000 net acres primarily located in
Southwest Fayette County, TX
Plan to spud 7-10 gross wells in 2011
2011 drilling program averages ~45% WI
Eagle Ford AMI
Ramshorn Investments, Inc., an affiliate of
Nabors Industries, Ltd. purchased a 50%
interest
o
Upfront cash payment
o
Will fund 100% of cost of first six
horizontal wells
GEOI retains 50% WI and operations
Leasehold continues to increase
Fayette County: 19,600 net acres
Gonzales County: 2,700 net acres
Atascosa & McMullen counties
combined: 1,700 net acres
Note:
Information
as
of
August,
2011.
7 |
 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, 44.1% WI
Preparing to drill Peebles Unit #1H: ~5,000’
lateral, 15 stages, 39.8% WI
Multi-year drilling inventory
2nd operated rig planned for Fall 2011
Planning for 3 operated rigs in early 2012
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
8
MHR Gonzo North #1H
30 Day Avg. Rate.: 471 Boe/d
Note:
GEOI Flatonia East #1H
30 day Avg. Rate: 391 Boe/d
GEOI Flatonia East #2H
30 day Avg. Rate: 465 Boe/d
GEOI Black Jack Springs #1H
22 day Avg. Rate: 390 Boe/d
MHR Furrh #1H
30 Day Avg. Rate.: 711 Boe/d
MHR Gonzo Hunter #1H
30 Day Avg. Rate.: 313 Boe/d
MHR Geo Hunter #1H
30 Day Avg. Rate.: 329 Boe/d
PVA Gardner El Al #1H
30 Day Avg. Rate.: 852 Boe/d
PVA Hawn Holt #4H
30 Day Avg. Rate.: 327 Boe/d
Third party 30 Day 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 August 2011. |
 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 ~55 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
24,000
24,000
Number of Potential Net Drilling Locations
160
160
Estimated EUR per Well (Mboe)
350
500
Unrisked Illustrative Resource Potential (Mboe)
56,000
80,000 |
 11
Bakken Shale Overview
46,000 total net acres in three project areas
Williams County Project (Operated)
25,000 net acres in Williams County, ND
4 wells drilled and completed
Continuous drilling with 2 dedicated rigs currently
running
Interests in 100 spacing units (1,280 acres)
Mountrail County Project (Non-Op)
Partnered with Slawson Exploration Company
11,000 net acres primarily Mountrail County, ND
4-5 rigs currently running
Eastern Montana Project (Primarily Operated)
10,000 net acres in Roosevelt/Richland County, MT
8,200 operated / 1,800 non-operated acres
17 operated 1,280 acre units
Currently
drilling
1
st
operated
Bakken
well,
Olson
#1-21-16H with a 31.4% WI
Participated with Slawson in the Renegade 1-10H,
Battalion 1-3H & Squadron 1-15-14H
Participated with Brigham in the Swindle 16-9 #1H
Note:
11
Information as of August 2011. Symbols on map depict permitted or drilled Bakken locations. |
 Williams County Project
25,000 net acres in NW Williams Co., ND
Plan to spud 11-13 gross wells in 2011
2011 drilling program averages ~30% WI
Interest in 100 spacing units
Bakken AMI
Partnered with Resolute Energy in March ‘10
Retained 47.5% WI in project
First 4 wells have de-risked acreage
Carlson
1-11H
(640
acre):
236
Bo/d
30
Day
Avg.
Siirtola
1-28-33H
(1280
acre):
246
Bo/d
30
Day
Avg.
Anderson
1-24-13H
(1280
acre):
372
Bo/d
30
Day Avg.
Muller
1-21-16H
(1280
acre):
275
Boe/d
first
12
Day Avg.
Multi-year drilling inventory
2 dedicated rigs currently running
Planning for 3 operated rigs in 2012
Positive offset activity
4-5 rigs drilling in and around our AMI
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. |
 Williams County Project Activity
13
13
GEOI Anderson 1-24-13H
30 Day Avg.: 372 Bo/d
NFX Christensen 159-102-17-
20-1H
30 Day Avg.: 326 Bo/d
OAS Sandaker 5602 11-13H
30 Day Avg.: 440 Bo/d
OAS NJOS Federal 5602 11-
13H
30 Day Avg.: 375 Bo/d
Note:
GEOI Muller 1-21-16H
12 Day Avg.: 275 Boe/d
GEOI Carlson 1-11H
30 Day Avg.: 236 Bo/d
(640 ac. unit -
short lateral)
GEOI Siirtola 1-28-33H
30 Day Avg.: 246 Bo/d
OAS Grimstvedt 5703 42-34H
30 Day Avg.: 262 Bo/d
GEOI WI = 2.6%
OAS Bean 5703 42-34H
30 Day Avg.: 298 Bo/d
OAS Horne 5603 44-9H
30 Day Avg.: 550 Bo/d
OAS Somerset 5602 12-17H
30 Day Avg.: 352 Bo/d
OAS Ellis 5602 12-17H
30 Day Avg.: 421 Bo/d
Petro-Hunt NJOS 157-100-
28A-33-1H
30 Day Avg.: 215 Bo/d
Petro-Hunt NJOS 157-100-
26B-35-1H
30 Day Avg.: 344 Bo/d
Petro-Hunt Forseth 157-100-
25B-1H
30 Day Avg.: 325 Bo/d
NFX Christensen 159-102-8-5-
1H
Drilling (GEOI WI 6.2%)
BEXP BCD Farms 16-21
30 Day Avg.: 485 Bo/d
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 all production data is HPDI website, except for
Muller well which is based on GeoResources’ internal figures..
|
 Williams County Completion Comparison
14
14
GeoResources Completions
Offset
Completions
Siirtola/Anderson
(Avg.)
Muller and Next 2
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
st
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
|
 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
Note:
Information, except for map, as of August 2011. Yellow-highlighted areas on map represent
GEOI’s acreage position. |
 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
29,000 net acres
17 wells drilled –
100% success
19 additional drilling locations
WI ranges from 37% -
53%
Operating control
Majority of acreage held-by-production
Eastern Giddings development area
Eastern acreage in Grimes and
Montgomery Counties is dry gas
Western acreage is liquids-rich gas and
condensate
Additional upside includes:
Eagle Ford, Georgetown and Yegua
potential
Rate increase potential from slick water
fracture stimulations
Recently completed drilling W.
Cannon Unit in northwest Grimes
County (oily location)
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 |
 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
14,000 gross acres (13,000 HBP)
33% WI below major field plays
Cumulative production of 180 MMBO and 285 BCF
Recent Exploratory Success
105’
of net pay encountered
22% WI
Production expected to commence in late August
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
126
1
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2
3
4
5
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31
1
51
3
4
1
4111
211
1
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131
221
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1B
6A
1211
3
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21
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9A
14A
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11A32A
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3A1A37A
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16A37A
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21
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7D
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A-53
20
20 |
 Financial Overview |
 Development Program
Project
Budgeted
Bakken
Operated
$29.5
Non-Operated
21.0
Eagle Ford
15.8
Giddings & LA
16.1
Acreage & Seismic
25.0
Other
6.6
TOTAL
$114.0
2011 Capital Budget
Budget recently increased to take advantage of
leasing success and robust project inventory
2011 budget increased from $88 MM to $114 MM
2012 budget estimated at $173 MM
Current project allocations favor lower-risk, high
cash flow oil-weighted projects
Project inventory allows flexibility
Weighted towards oil and liquids
Oil and gas projects in inventory
Exploration and development projects in inventory
Held by long-term leases or production
2011 and 2012 capital budget to be updated
later in third quarter
Capital Allocations
($ in millions)
22
22 |
 23
EBITDAX
(1)
Debt / EBITDAX
(1)
Ability to fund current capital budget with cash flow and undrawn debt
capacity Conservative use of leverage to maintain strong balance sheet
$145 MM borrowing base
Last twelve months EBITDAX
(1)
= $71.0 MM
No debt currently outstanding
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
$0.0
$10.0
$20.0
$30.0
$40.0
$50.0
$60.0
$70.0
$80.0
2007
2008
2009
2010
2Q 2011
LTM
$18.4
$54.2
$48.1
$69.1
$71.0
-
0.5
1.0
1.5
2.0
2.5
3.0
2007
2008
2009
2010
2Q 2011
3.0x
0.7x
1.4x
1.3x
0.0x |
 Investment Highlights
Value Creation
Significant upside from Eagle Ford and Bakken positions
Eagle
Ford
Shale
-
24,000
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 upside identified in conventional assets
Strong financial position to execute development plans
Significant free cash flow from existing assets to invest in shale
development 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 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
|
 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%
$70/Bbl (WTI)
9.9%
30.0%
17.2%
48.5% |
 27
Management History
2004-
2007
Southern Bay Energy, LLC
Gulf Coast, Permian Basin
REVERSE MERGED INTO
GEORESOURCES, INC.
1992-1996
Hampton Resources Corp
Gulf Coast
SOLD TO BELLWETHER
EXPLORATION
Preferred
investors
–
30%
IRR
Initial
investors
–
7x
return
1997-2001
Texoil Inc.
Gulf Coast, Permian Basin
SOLD TO OCEAN ENERGY
Preferred
investors
–
2.5x
return
Follow-on
investors
–
3x
return
Initial
investors
–
10x
return
2001-2004
AROC Inc.
Gulf Coast, Permian Basin, Mid-Con.
DISTRESSED ENTITY TURNED
AROUND AND MONETIZED
Preferred
investors
–
17%
IRR
Initial
investors
–
4x
return
Track record of profitability and liquidity
Extensive industry and financial relationships
Significant technical and financial experience
Long-term repeat shareholders
Cohesive management and technical staff
Team has been together for up to 23 years through
multiple entities
27 |
 28
Proved Reserves
(1)
PV-10% is a non-GAAP financial measure. See reconciliation of SEC PV
10% to standardized measure in Appendix. (2)
Utilizing five year NYMEX forward prices at 1/1/11. See Additional
Disclosures in Appendix. ($ 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
$390.3
28
Proved Reserves –
SEC Pricing at 1/1/11
Proved Reserves –
Forward Strip Pricing at 1/1/11
($ 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
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
$101.85 |
 30
Operating Performance
Historical Operating Data
(1)
Adjusted Net Income and Adjusted EBITDAX are non-GAAP financial
measures. See reconciliation of net income to Adjusted Net Income and Adjusted EBITDAX in Appendix.
Key Data:
Average realized oil price ($/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
(1)
15.1
$
23.9
$
10.9
$
16.3
$
Adjusted earnings
(1)
per share (diluted)
0.60
$
1.19
$
0.66
$
1.03
$
Adjusted EBITDAX
(1)
38.4
$
66.7
$
45.8
$
49.0
$
6
Mos Ended
Years Ended December 31,
2010
2009
2008
6/30/2011 |
 31
Reconciliation of non-GAAP Measures
31
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
$
Adjusted EBITDAX Reconciliation
(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
Adjusted Net Income Reconciliation
(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. 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
(1)
-
$
(0.3)
$
(0.7)
$
(1.7)
$
Adjusted Net Income
15.1
$
23.9
$
10.9
$
16.3
$
(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.
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:
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. 34
Additional Disclosures
34 |