GeoResources, Inc Corporate Profile December 00
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 reserve 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, 009 Annual Report on Form 0-K and Form 0-K/A 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 free 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.
Key Investment Highlights Significant Bakken and Eagle Ford upside Strategically located in high rate of return resource plays High level of operating control Significant Bakken Exposure 0,000 net operated acres 4,000 net non-operated acres 44,000 TOTAL ACRES Rapidly expanding Eagle Ford Position 7,000 net acres Commitment for additional leasing Solid Proved Reserve and Production Base 4 Mmboe proved reserves (as of 7//0) are 56% oil 5,088 BOE/d average YTD Sept 00 Value Creation
Geographic Overview 44,000 net acres in Bakken 7,000 net acres in Eagle Ford Company Highlights Proved Reserves (MMBOE) () 4.0 Oil 56% Proved Developed 7% PV 0% (millions) $84 Production (BOEpd) () 5,088 Oil 56% Operated 80% Gross Acreage () 584,74 Net Acreage () 6,770 () As of July, 00. () Represents the Company s average production rate YTD September 0, 00. () Acreage information estimated as of November 0, 00. (4) Map depicts focus areas and excludes minor value properties. 4 4
(MMBOE) (BOEpd) Reserves and Production Developed Non- Producing % Current Proved Reserves 4.0 MMBOE () Williston 8% Mid-Continent 6% Permian Basin 9% Undeveloped 7% Producing 6% Oil 56% Gas 44% Louisiana 6% Gulf Coast/ETX/S TX 7% Other 4% Proved Reserves (MMBOE) () Average Daily Production (BOEpd) 0.0 5.0 0.0 5.0 5.7 4.6 0.7 4.0 6,000 5,000 4,000,000,88 4,589 5,088 0.0,000,86 5.0.4,000 768 0.0 006 007 008 009 00 (Strip) () As of July, 00. Excludes partnership interests. () 006 009 proved reserves based on SEC guidelines. () 008 Reserves reflect lower prices and divestitures. (4) 7//0 strip prices based on NYMEX strip as of 6/0/0. 0 006 007 008 009 YTD Sept 00 5
GeoResources Asset Overview Oil Weighted Development 6
Bakken Shale Overview 7,000 (44,000 Net) Acres in the Bakken 69,000 (0,000 net) operated acres 04,000 (4,000 net) non-operated acres 50 miles Bakken Non-Operated Project CANADA Partnered with Slawson Exploration MT ND 00,000 acres in Mountrail County, ND 0-8% WI,000 net acres Currently, three rigs operating by Slawson Bakken Operated Project Roosevelt County Williams County Parshall Sanish 50,000 acres in Williams County, ND Retained 47.5% WI and operations 4,000 net acres Drilling started in September 00 40 operated, 4 non-operated,80 acre units Eastern Montana Bakken 7,000 net acres in Roosevelt County, MT 6,000 operated /,000 non-operated acres 5 operated,80 acre units Participate with Brigham Exploration Company in the Swindle 6-9 #H with a 9.% WI 7
Bakken Shale - Non-operated Partnered with experienced operator - Slawson Exploration Bakken Shale Working interests ranging from 0% to 8% in 00,000 acres,000 net acres Slawson has three rigs running currently and has drilled over 75 wells Additional opportunities: Slawson evaluating Three Forks potential with one producer and one well waiting to frac as well as encouraging offset results by EOG & Whiting Slawson and others evaluating appropriate spacing and infill drilling with several drilling units containing second wells in the unit Note: Yellow-highlighted areas represent the Company s acreage position. 8
Bakken Shale - Non-operated Activity GeoResources Non-Operated 00 Drilling Results - Sample Wells Map Spacing Frac 4-hour IP () 0 Day Avg. 60 Day Avg. # Well Name (Acres) Stages Bbls/d Bbls/d Bbls/d Atlantis Federal #-4-5H,80 40,44,79,08 Cannonball Federal #-7-4H (),80 9,57 87 67 Jericho #-5H-TF () 640 0 5 0 4 Lunker Federal #--4H,80 40 650 56 4 5 Sauger Federal #-H 640,597,,00 6 Tarantula #-6H 640,00 6 494 7 Shad Federal #--H,80 4,04 () See Additional Disclosures in APPENDIX for definitions and information regarding specific wells. Mountrail County Sample 00 Wells 6 5 4 7 Note: Yellow-highlighted areas represent the Company s acreage position. 9
Bakken Shale - Operated 4,000 Net Acres with 47.5% WI and operations in Williams County 40 operated,80 acre units plus 4 non-operated units Preparing to frac the Carlson #-H (640 ac unit) Completing Siirtola -8-H and will move to the Anderson -4-H (80 acre unit wells) Impressive Offsetting Activity 7 nearest southern offsets have NDIC-reported initial rates of,8-,947 BOPD 4-5 rigs drilling within or immediately south of AMI 0
Bakken Shale - Activity Carlson -H Awaiting Completion Anderson -4-H Est. Spud December 00 Siirtola -8-H Spud October 00 OAS: Grimstvedt 4-4H Drilling GEOI WI =.% OAS: Bean 570-4-4 Waiting on Completion Results BEXP: BCD Farms 6- IP:,776 Boe/d OAS: Somerset -7H & Ellis -7H Waiting on Compl. Results OAS: Njos Federal IP:,080 Boe/d OAS: Somerset 4-8H & Ellis 4-8H Waiting on Compl. Results OAS: Sandaker -H IP:,407 Boe/d BEXP: Rooks Farm 7-0H Permitted Location BEXP: Kalil 5-6#H IP:,586 Boe/d BEXP: Kalil Farm 4-H & McMaster 4-H Waiting on Compl. Results BEXP: Lee 6- IP:,544 Boe/d BEXP: Arnson -4 IP:,9 Boe/d BEXP: Strand 6-9 IP:,65 Boe/d BEXP: Sukut 8- IP:,959 Boe/d
Eagle Ford Shale Tom Green Coryell Leon Concho Irion Falls McCulloch Lampasas San Saba TEMPLE Madison Menard Milam Burnet Mason Clayton Williams Llano Grimes Burleson Kimble Travis GEOI retains 50% WI and operations Strong industry partner purchased 50% of acreage Will fund six horizontal wells Paid $0 million upfront cash payment Joint commitment for additional leasing Hays Val Verde Comal TEXAS Bandera Magnum-Hunter /Hunt Oil Guadalupe SAN ANTONIO Bexar Uvalde Medina Acquired additional acreage in Fayette, Gonzales, Atascosa & McMullen counties 5,600 net acres acquired,500 additional net acres to close before year-end Colorado IL O Gonzales EOG's Marshall Area Lavaca ET S GA Wharton W Wilson DeWitt Jackson Zavala S Karnes Atascosa Frio Y DR GA PetroHawk/GeoSouthern VICTORIA BlackHawk Area Victoria Matagorda Maverick EAGLE PASS Eagle Ford Expansion Austin Fayette Kinney Waller Caldwell Real OIL Goliad Dimmit GeoResources Area Kendall Washington DR Y Kerr Edwards GA S OI Bastrop S Eagle Ford AMI Lee AUSTIN Blanco GA Gillespie Brazos BRYAN Williamson Sutton Robertson Bell Schleicher L Eagle Ford Acreage has increased to 5,000 acres, 7,000 net W ET Calhoun Bee La Salle WET G McMullen Live Oak Refugio AS Aransas DRY MEXICO GAS San Patricio PetroHawk Eagle Ford Trend Discovery Webb Nueces CORPUS Jim Wells CHRISTI Duval GULF OF MEXICO LAREDO Kleberg Jim Hogg Brooks
Eagle Ford AMI Eagle Ford AMI Volatile oil / gas condensate window On strike with Gonzales Co. activity Could spud first well by year-end 00 or early 0 Offset operator activity Magnum Hunter announced completion of their st well in Gonzales Co. with an Initial Production (IP) over 600 boepd. nd & rd wells drilling EOG has multiple completions in Gonzales Co. with IPs ranging from 700 to,000 bopd Clayton Williams has completed wells to the NE in Burleson Co. & Lee Co. with a 4th well completing in Lee Co. Burleson Co, IPs range from 4 to 49 bopd
Additional Assets
Giddings Field Austin Chalk 68,000 Acres (9,000 net acres) 6 wells drilled 00% success 0 additional drilling locations WI ranges from 7% - 5% Operating control Majority of acreage Held-by- Production Milam Giddings Field Acreage Brazos CWEI APACHE APACHE APACHE APACHE Burleson Grimes W Eastern Giddings Development Area Eastern acreage in Grimes and Montgomery Counties is dry gas Western acreage is liquids-rich gas and condensate Lee CWEI APACHE Washington Additional Upside Includes: Yegua and Georgetown potential Rate increase potential from slick water fracture stimulations Bastrop Fayette Austin Waller Eagle Ford AMI announced SW of Giddings acreage Eagle Ford AMI MAGNUM-HUNTER Colorado 5
A C D 5 0 A 4 9A 5A 49A 5 4 6 54 44A 45A 8 0 7 ST 7A 9 50A A 47A() 8A 48A 5A 8A 7 0A 5A A A 5A 4A 5 4 40A A 7A 6A A D 9 6A 4A A 7A 6A 4A 46A 5A 9A 8A 4 A 8 A A 8A 6 7A 7 9A 4A 4A A 5 6A 0A 4A B 5A 0A 4A 6 7 8 4 6 5 6 5 E 4 7 4C E 7 0D 8D 4 9D 7D 6D 9 5 5E 8 6 9A 4 5 4 4 5-4 Louisiana - St. Martinville & Quarantine Bay St. Martinville Field 54 net acres of owned minerals (green),585 net acres of HBP or leased (yellow) Average WI 97% & NRI 9% Multiple objectives from,000 0,000 Cumulative shallow production of 5. MMBO and 6.6 BCFG Cumulative production over 5 Bcfe at 0,000 6 6 04 8 86 7 A-5 5 8 4 St. Martinville D 8 85 67 57 8 84 80 64 65 66 79 LOUISIANA 4,000 gross acres 7% WI above 0,500 and a % WI below 0,500 Cumulative production of 80 MMBO and 85 BCF Shallow zone behind pipe potential (<0,500 ) and significant deeper exploration potential (-,000 ) Quarantine Bay Field 6
Financial Overview
Development Program Capital Allocations 4 th Quarter 00 Capital Budget 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 Current Allocations Favors Lower- Risk, High Cash Flow Oil Projects Project Budgeted Comments $(Millions) Bakken Operated $6.9 wells Non-Operated 4.4 9-0 wells Montana Bakken.4 Other.0 $4.7 0 Capital Budget is $88.0 million Currently re-evaluating and expect increased budget 8
Strong Financial Position Can fund current CapEx with cash flow and debt capacity Conservative use of leverage to maintain strong balance sheet $45 Million borrowing base EBITDAX () : rd Quarter = $7.7 Million YTD 00 = $5. Million Annualized = $7.0 Million Total debt of $75.0 million proforma December 00 EBITDAX Debt / EBITDAX ($ in millions) $80.0 $7.0.0.0x $70.0 $60.0 $50.0 $40.0 $0.0 $0.0 $0.0 $8.4 $54. $48..5.0.5.0 0.5 0.7x.4x.0x $0.0 007 008 009 00 Annualized (() See reconciliation of net income to EBITDAX following in Appendix. - 007 008 009 00 9
Appendix
Management History Track record of profitability and liquidity Extensive industry and financial relationships Significant technical and financial experience Long-term repeat shareholders Cohesive management and technical staff Team has been together for up to years through multiple entities 99-996 Hampton Resources Corp Gulf Coast 997-00 Texoil Inc. Gulf Coast, Permian Basin SOLD TO BELLWETHER EXPLORATION Preferred investors 0% IRR Initial investors 7x return SOLD TO OCEAN ENERGY Preferred investors.5x return Follow-on investors x return Initial investors 0x return 00-004 AROC Inc. Gulf Coast, Permian Basin, Mid-Con. DISTRESSED ENTITY LIQUIDATED FOR BENEFIT OF INITIAL SHAREHOLDERS Preferred investors 7% IRR Initial investors 4x return 988-000 Chandler Company Rockies, Williston Basin MERGED INTO SHENANDOAH THEN SOLD TO QUESTAR 000-007 Chandler Energy, LLC Williston Basin, Rockies ACQUIRED BY GEORESOURCES, INC. 004-007 Southern Bay Energy, LLC Gulf Coast, Permian Basin REVERSE MERGED INTO GEORESOURCES, INC.
Proved Reserves () Proved Reserves by Category ($ in millions) Oil Gas Total % of Corporate Interests MMBO BCF MMBOE Total PV-0 PDP 8. 7.4 4.6 60.8% $46.0 PDNP. 5.4.0.5% 6.0 PUD. 0. 6.4 6.7% 74.8 Total Proved Corporate Interests.5 6. 4.0 00.0% 8.8 Partnership Interests 0. 9..6 6.8 Total Proved Corporate and Partnerships.6 7. 5.6 $400.6 Proved Reserves by Area Partnership Proved % of Interests Total Proved % of Total Area MMBOE Proved MMBOE MMBOE Reserves Central and South Texas 9. 7.9%.5 0.6 4.4% Williston 6.7 7.9% 0.0 6.7 6.% Louisiana.8 5.8% 0.0.8 4.8% Other 4.4 8.4% 0. 4.5 7.6% Total 4.0 00.0%.6 5.6 00.0% () As of July, 00
% of Production % of Production Hedging Strategy GEOI uses commodity price risk management in order to execute its business plan throughout commodity price cycles. Based on currently producing reserves, 6% of production is hedged for 0 and 9% for 0. Natural gas hedges include hedge volumes intended to cover GEOI s share of partnership production. Term of hedges is July, 00 through December, 0. Oil Hedges Natural Gas Hedges 70% Swaps Swaps Collar 60% 50% 90% 80% 70% Collar $7.00 - $9.90 40% 0% 0% 0% 0% Swap $74.7 to $85. Swap $74.7 to $88.45 Swap $86.85 to $87. 00 0 0 60% 50% 40% 0% 0% 0% 0% Swap $5.9 - $6.07 Collar $7.00 - $9.0 Swap $6.07 - $6.45 Swap $6.4 - $6.45 00 0 0
Income Statement Historical Operating Data Nine Months 00 rd Qtr. 00 009 008 Key Data: Average realized oil price ($/Bbl) $ 70.5 $ 70.4 $ 6.09 $ 8.4 Avg. realized natural gas price ($/Mcf) $ 5.9 $ 5.74 $.97 $ 8. Oil production (MBbl) 780 76 85 74 Natural gas production (MMcf),656,076 4,944,96 (millions except for per share amounts) Total revenue $ 79.9 $ 6.9 $ 80.4 $ 94.6 Net income before tax $ 7.4 $ 0. $ 4.8 $. Net income after tax $ 8. $ 7.6 $ 9.8 $.5 Earnings per share (diluted) $ 0.90 $ 0.8 $ 0.59 $ 0.86 EBITDAX () $ 5. $ 7.7 $ 48. $ 54. (() See reconciliation of net income to EBITDAX following in Appendix. 4
EBITDAX Reconciliation Nine Months rd Qtr. Years Ended December, (in millions) 00 00 009 008 Net income $ 8. $ 7.6 $ 9.8 $.5 Add back: Interest expense.9.4 5.0 4.8 Income taxes 9..6 5. 7.8 Depreciation, depletion and amortization 8.5 6..4 6.0 Hedge and derivative contracts (.0) (0.6) 0. 0.4 Noncash compensation 0.8 0..4 0.7 Exploration and impairments.5 0. 4. 0.9 EBITDAX $ 5. $ 7.7 $ 48. $ 54. 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. 5
Additional Disclosures The disclosures below apply to the contents of this presentation: In April, 007, 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 007 relates solely to Southern Bay. Proved reserves, and estimates of discounted present values associated therewith ( PV-0 ), as shown throughout this profile, are internal estimates as of 7//0 and are based on five year NYMEX strip pricing at 6/0/0 and held flat thereafter. The NYMEX oil strip used for the estimates ranged from $77. per Bbl for 00 to $84.56 per Bbl for years 05 and beyond. The NYMEX gas strip ranged from $4.84 per Mcf for 00 to $6.6 per Mcf for years 05 and beyond. Actual realized prices will likely vary materially from the NYMEX strip at 6/0/0. 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 (BOPD) (4 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. Cannonball Federal #-7-4H had only half of the frac completed. Remaining stages to be completed at a later date. Jericho Federal #-5H-TF had less than 50% of the stages frac d correctly due to mechanical problems with the stimulation sleeves. 6