Attached files
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| 8-K - FORM 8-K - GEORESOURCES INC | d8k.htm |
 GeoResources, Inc.
Corporate Profile
March, 2011
Exhibit 99.1 |
 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
Significant Bakken and Eagle Ford upside
Strategically located in high rate of return resource plays
High level of operating control
Significant Bakken Exposure
32,500 net operated acres
12,500 net non-operated acres
45,000 TOTAL ACRES
Continually leasing
Rapidly expanding Eagle Ford Position
23,000 net acres
Commitment for additional leasing
Solid Proved Reserve and Production
Base
24
Mmboe
proved
reserves
are
60%
oil
(1)
5,090 BOE/d average during 2010
(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)
As of December 31, 2010. Excludes interests in two affiliated partnerships. Reserves
based on SEC pricing for 2010. See Additional Disclosures in
Appendix. (2)
Represents the Company’s average production rate for the year ended December
31, 2010. (3)
Acreage information as of December 31, 2010.
(4)
EBITDAX
is
a
non-GAAP
financial
measure.
Please
see
Appendix
for
a
definition
of
EBITDAX
and
a
reconciliation
to
net
income.
Bakken
45,000 net acres
Company
Highlights
(1,2,3)
Independent oil and natural gas
company focused in the Southwest,
Gulf Coast and Williston Basin
Significant upside potential through
growing positions in liquids-rich shales:
Bakken
–
45,000
net
acres
Eagle Ford –
23,000 net acres
60%
of
4
quarter
2010
production
is
oil
and expected to increase through near-
term development
Operate approximately 75% of proved
reserves
2010
EBITDAX
of
$69
million
(4)
Eagle Ford
23,000 net acres
4
Proved Reserves (MMBOE)
24.0
Oil (reserves)
60%
Proved Developed
74%
Production (Boe/d)
5,090
Oil (2010 average production)
57%
Operated
75%
Net Acreage
235,572
th |
 Proved Reserves (MMBOE)
(2)
Average Daily Production (BOE/d)
Reserves and Production
Current Proved Reserves –
24.0 MMBOE
(1)
5
(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. |
 Oil Weighted
Development
GeoResources Asset Overview
6 |
 7
Bakken Shale Overview
45,000 Net Acres in the Bakken
Bakken Operated Project
25,000 net acres in Williams County, ND
Retained 47.5% WI and operations
Drilling started in September 2010
Interests in 100 spacing units (1,280 acres)
Bakken Non-Operated Project
Partnered with Slawson Exploration Company
11,000 net acres primarily in Mountrail Co., ND
Currently, five rigs operated by Slawson
Eastern Montana
9,000 net acres in Roosevelt/Richland Co., MT
7,500 operated / 1,500 non-operated acres
16 operated 1,280 acre units
Drilling 1
operated Bakken well, Olson #1-21-
16H with a 31.375% WI
Participated with Slawson in the Renegade 1-
10H & Battalion 1-3H with 25% WI
Participated with Brigham in the Swindle 16-9
#1H with a 9.3% WI
Note: Information, except for map, as of March 21, 2011. Symbols in map
depict permitted or drilled Bakken locations. 7
st |
 Bakken
Shale - Operated
25,000 Net Acres with 47.5% WI
and operations in Williams County
Interests in 100 spacing units
First well, Carlson #1-11H (640 acre
unit, short lateral) on production at
an IP of 685 BO/d and an estimated
completed well cost of $5.6 million
Second and third wells are 1,280
acre units with long laterals;
Siirtola 1-28-33H completed with
an IP of 840 BO/d and cleaning up;
Anderson 1-24-13H is being fraced.
Positive Offsetting Activity
9 nearest southern wells have
NDIC-reported initial rates of
972-1,947 BOPD
4-5 rigs drilling within or
offsetting our AMI
8
Note: Information, except for map, as of March 21, 2011.
|
 Bakken
Shale - Activity
9
9
Carlson 1-11H
IP: 685 Bo/d
(640 ac. unit -
short lateral)
Anderson 1-24-13H
Fraced in March 2011
Siirtola 1-28-33H
IP: 840 Bo/d, 480 MCF/d
NFX: Christensen 159-102-17-
20-1H
Waiting on Compl. Results
BEXP: Sukut 28-33 1-H
IP: 1,959 Boe/d
OAS: Grimstvedt 5703 42-34H
Waiting on Compl. Results
GEOI WI = 2.6%
BEXP: Lee 16-21 1-H
IP: 1,544 Boe/d
OAS: Somerset 5602 12-17H
IP = 1,119 Boe/d,
Ellis 5602 12-17H = 1,390
Boe/d
BEXP: Kalil Farm 14-23 1-H &
MacMaster 11-2 #1
Waiting on Compl. Results
OAS: Bean 5703 42-34H
IP: 1,492 Boe/d
BEXP: Arnson 13-24 1-H
IP: 1,339 Boe/d
BEXP: BCD Farms 16-21
IP: 1,776 Boe/d
BEXP: Strand 16-9 1-H
IP: 2,265 Boe/d
OAS: Njos Federal 5602 11-
13H
IP: 2,080 Boe/d
BEXP: Kalil 25-36 1561-H
IP: 1,586 Boe/d
OAS: Baffin 5601 12-18H
Waiting on Compl. Results
OAS: Devon 5601 12-17H &
Glover 5601 12-17H
Waiting on Compl. Results
OAS: Sandaker 5602 11-13H
IP: 1,407 Boe/d
Note: Carlson 1-11H well is the only 640 acre unit, short lateral well
referenced on the map. Information, except for map, as of March 21, 2011. |
 10
Bakken Shale -
Non-operated
Bakken Shale
Note: Yellow-highlighted areas represent the Company’s acreage
position. Partnered with experienced operator -
Slawson Exploration
11,000 net acres with working interests
ranging from 10% to 18%
Slawson has five rigs running currently and
has drilled over 85 wells; 100% success
Additional opportunities:
Slawson and others evaluating
appropriate Bakken spacing and infill
drilling with several drilling units
containing second wells
Slawson evaluating Three Forks
potential with one producer and one
well waiting to frac
Encouraging offset Three Forks results
by EOG and Whiting where GEOI has
minor working interests
Note: Information, except for map, as of March 21, 2011.
10 |
 Eagle
Ford Shale Eagle Ford Acreage has
increased to 23,000 net acres
Eagle Ford AMI
Southwest Fayette County
Ramshorn Investments, Inc., an
affiliate of Nabors Industries, Ltd.
purchased a 50% interest
Made upfront cash payment
Will fund six horizontal wells
GEOI retains 50% WI and operations
Joint commitment for additional
leasing
Eagle Ford Expansion
Recent acreage acquisitions bring
county totals to approximately
Fayette County 17,500 net acres
Gonzales County 3,200 net acres
Atascosa and McMullen counties
combined 2,100 net acres
Note: Information, except for map, as of March 21, 2011.
11 |
 Eagle
Ford Shale Volatile oil / gas condensate window
On strike with operator activity in Gonzales
County.
Spud first well in Fayette County, Flatonia
East Unit #1-H, on January 10, 2011
Drilling second well in Fayette County,
Flatonia East Unit #2-H.
Will frac both wells back-to-back and utilize
micro-seismic in an effort to establish spacing
and frac efficiency
Positive offset operator activity
Magnum Hunter has completed two wells in
Gonzales County with Initial Production (IP)
from 600 boe/d to 1,335 boe/d.
EOG has multiple completions in Gonzales
County with IPs ranging from 700 to 2,000
bo/d.
Clayton Williams has completed 3 wells to the
NE with a 4th well completing located in
Burleson and Lee Counties IPs range from
234 to 492 bo/d.
12 |
 Development Economics
Bakken Shale (Williams Co., North Dakota)
Eagle Ford Shale (Fayette Co., Texas)
Development Economics
(2)
(1)
Assumes Bakken and Eagle Ford oil differentials of 15% and 5%, respectively.
Natural gas price held constant at $5/Mcf. (2)
EUR refers to management’s internal estimates of reserves potentially
recoverable from successful drilling of wells. These estimates do not necessarily represent
reserves as defined under SEC rules and by their nature and accordingly are more
speculative and substantially less certain of recovery and no discount or risk
adjustment is included in the presentation. Actual locations drilled and quantities
that may be ultimately recovered from the Company’s interests could differ
substantially.
13
13
350 MBO EUR
500 MBO EUR
700 MBO EUR
350 MBOE EUR
500 MBOE EUR
Well Assumptions
Drill & Completion cost ($M$)
$6,500
$6,500
$6,500
$7,000
$7,000
Lateral Length (feet)
10,000
10,000
10,000
5,000
5,000
WI
100%
100%
100%
100%
100%
NRI
80%
80%
80%
82.5%
82.5%
IP (Bopd)
500
800
1,100
500
1,000
Econ. @ $80/Bbl and $5/Mcf
(1)
NPV @ 10%
$2,812
$7,667
$12,034
$4,784
$10,591
IRR
25%
72%
89%
45%
237%
Payout (yrs)
3.0
1.3
1.2
1.8
0.9
ROI
2.2
3.3
4.9
2.4
3.5
Price Sensitivity (IRR)
(1)
$90/Bbl (WTI)
34%
91%
150%
57%
337%
$80/Bbl (WTI)
25%
72%
89%
45%
237%
$70/Bbl (WTI)
18%
55%
69%
33%
111%
$60/Bbl (WTI)
12%
40%
52%
23%
69% |
 Additional Assets |
 15
Giddings Field –
Austin Chalk
29,000 net acres
16 wells drilled –
100% success
20 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
Giddings Field Acreage
Eagle Ford Area of
Mutual Interest
15 |
 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’
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
Significant deep exploration potential (11-
25,000’); plus sub-salt potential
Pelican prospect: 1.3 MMBO + 10 BCFG at
~11,500’. Spud March 2011 with 20% WI
Prospect DN: 16.0 MMBO + 40 BCFG at
~16,500’
Additional deeper prospects
16
16 |
 Financial Overview |
 Development Program
Project
Budgeted
Comments
Bakken
Operated
$29.5
18 wells + completions
of 2010 drilling
Non-Operated
21.0
Slawson 3 rig program
+ minor interest wells
Eagle Ford
15.8
6 Carried Interest wells
+ 7 additional wells
Giddings & LA
16.1
Giddings = 3 wells
LA = 8 wells
Acreage & Seismic
25.0
Other
6.6
Non-Operated Drilling
+ Operations Capital
TOTAL
$114.0
2011 Capital Budget
Budget recently increased to take
advantage of leasing success and strong
project inventory
2011 budget increased from $88 MM to
$114 MM
2012 budget estimated at $173 MM
Current project allocations favor lower-risk,
high cash flow oil projects
Project inventory allows flexibility
Weighted towards oil and liquids
Oil and gas projects in inventory
Exploration and development projects in
inventory
Held by long-term leases or production
Capital Allocations
($ in millions)
18
18 |
 19
EBITDAX
Debt / EBITDAX
Can fund current CapEx with cash flow and debt capacity
Conservative use of leverage to maintain strong balance sheet
$145 Million borrowing base
2010 EBITDAX
(1)
= $69.1 Million
Total debt of $87.0 million as of December 31, 2010.
No debt after January 2011 Equity Raise.
Strong Financial Position
($ in millions)
(1) EBITDAX is a non-GAAP financial measure. See reconciliation of net
income to EBITDAX following in Appendix. (2) December 2010 debt / 2010 EBITDAX.
19 |
 Investment Highlights
Value Creation
Significant upside through Bakken and Eagle Ford shale positions
Bakken
Shale
-
45,000
net
acres
Eagle
Ford
Shale
-
23,000
net
acres
Ongoing leasing program to further expand acreage
Solid proved reserve and production base
24 MMBOE of proved reserves
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 post offering
Experienced management and technical staff 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 21% 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. 20
(1) |
 Appendix |
 22
Management History
2004-
2007
Southern Bay Energy, LLC
Gulf Coast, Permian Basin
REVERSE MERGED INTO
GEORESOURCES, INC.
2000-2007
Chandler Energy, LLC
Williston Basin, Rockies
ACQUIRED BY
GEORESOURCES, INC.
1988-2000
Chandler Company
Rockies, Williston Basin
MERGED INTO
SHENANDOAH THEN SOLD
TO QUESTAR
1992-1996
Hampton Resources Corp
Gulf Coast
SOLD TO BELLWETHER
EXPLORATION
Preferred investors –
30% IRR
Initial investors –
7x return
1997-2001
Texoil Inc.
Gulf Coast, Permian Basin
SOLD TO OCEAN ENERGY
Preferred
investors
–
2.5x
return
Follow-on
investors
–
3x
return
Initial investors –
10x return
2001-2004
AROC Inc.
Gulf Coast, Permian Basin, Mid-Con.
DISTRESSED ENTITY LIQUIDATED
FOR BENEFIT OF INITIAL
SHAREHOLDERS
Preferred
investors
–
17%
IRR
Initial investors –
4x return
Track record of profitability and liquidity
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 21
years through multiple entities
22 |
 23
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
$390.3
23
Proved Reserves –
SEC Pricing at 1/1/11
Proved Reserves –
Forward Strip Pricing at 1/1/11
($ 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.
Swaps
Swaps
Collar
Natural Gas Hedges
Collar
$85 .00 to
$110.00
24 |
 25
Operating Performance
Historical Operating Data
2010
2009
2008
Key Data:
Average realized oil price ($/Bbl)
70.33
$
61.09
$
82.42
$
Avg. realized natural gas price ($/Mcf)
5.30
$
3.97
$
8.12
$
Oil production (MBbl)
1,060
851
743
Natural gas production (MMcf)
4,789
4,944
2,962
($ in millions except per share data)
Total revenue
107.0
$
80.4
$
94.6
$
Net income before tax
35.3
$
14.8
$
21.3
$
Net income after tax
23.3
$
9.8
$
13.5
$
Earnings per share (diluted)
1.16
$
0.59
$
0.86
$
EBITDAX
(1)
69.1
$
48.2
$
54.2
$
25
(1) EBITDAX is a non-GAAP financial measure. See reconciliation of
net income to EBITDAX in Appendix. 25 |
 26
Reconciliation of non-GAAP Measure
Years Ended December 31,
($ in millions)
2010
2009
2008
Net income
23.3
9.8
13.5
Add back:
Interest expense
4.7
5.0
4.8
Income taxes
11.9
5.1
7.8
Depreciation, depletion and amortization
24.7
22.4
16.0
Hedge and derivative contracts
(0.9)
0.3
0.4
Noncash compensation
1.1
1.4
0.7
Exploration and impairments
4.3
4.2
10.9
EBITDAX
69.1
48.2
54.1
26
$
$
$
$
$
$
Reconciliation of Net Income to EBITBAX.
As used herein, EBITDAX is calculated as earnings 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. 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 (GAAP), but provides additional information for evaluation of our operating
performance. |
 Standardized Measure
SEC
PV-10
Reconciliation
to
Standardized
Measure
(1)
($ 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
27
(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.
(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. 28
Additional Disclosures
28 |