Bank of America 2008 Energy Conference Bank of America Energy Conference

Transcription

1 Bank of America 2008 Energy Conference 0

2 Forward Looking Statements This presentation may contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the SEC. GeoMet undertakes no duty to update or revise these forward-looking statements 1

3 CBM / Shallow Gas Experts About GeoMet Developer and operator of coalbed methane properties since 1985 Growth primarily through organic, self generated development of green field projects Technical staff has developed 5 large scale CBM projects in four separate basins (Black Warrior, Raton, Central Appalachia and Cahaba Basins) 16 person technical, professional and project management team that averages more than 19 years of CBM experience Proved reserves of 350 Bcf at % Operated 76% Developed Approximately 210,000 gross undeveloped acres Current net daily gas sales volumes of 21 MMcf 2

4 About Coalbed Methane Gas Manufacturing Large scale, low risk, repeatable, multiyear projects Shallow gas with significant resources-in-place Low finding & development costs Declining unit lifting costs Economies of scale drive down unit development and operating costs Long-lived reserves (low reinvestment risk) 3

5 Reasons to Invest in GeoMet Value Drivers Ownership Management & directors interests aligned with investors (own near 50% of outstanding shares) 100% operational control over large scale, multiyear projects Positioned for Long-Term Growth Multiyear, low risk drilling opportunities: 170 net undrilled PUD locations at 12/31/07 (83 Bcf D&M reserves) 480 net undrilled probable locations at 12/31/07 (189 Bcf D&M reserves) Early stage Canadian development project with over 1 Tcf gross gas-in-place (NS&A) Shale prospect (approximately 80,000 gross acres under lease and growing) Market Discount Low comparative valuation 4

6 Operational & Financial Strengths Long, shallow decline reserves (reserve life greater than 30 years) Mitigates impact to current low commodity prices Reduces reinvestment risk Low growth hurdles 75% of reserves are developed Minimal capital required to maintain current levels of production Capital expenditures benefit both production and reserves Low asset intensity (free cash flow to build reserves) Attractive full cycle economics Strong capital structure, good liquidity and attractive hedges 5

7 Resource in Place - - Provides Platform for Growth Gas Content By Basin GeoMet Operations Scf/ton Powder River Cherokee Cahaba Raton Black Warrior Peace River San Juan Central Appalachia Note: Gas content is based on averages from producing areas 6

8 Net Daily Sales Volumes Growth in Production 20,000 Pond Creek 19,523 18,000 16,000 14,000 Cahaba Other CAGR = 30% 12,585 17,064 12,000 10,000 8,709 8,000 6,806 6,000 4,000 2, Note: 2003 and 2004 include properties sold June 2004 History of Consistent Growth 7

9 Growth in Proved Reserves Reserve Profile 400 Bcf CAGR = 36% % Organic Reserve Replacement 8

10 Reserve Profile at December 31, 2007 Proved and Probable Reserves Total Proved 350 Bcf BCF Total Probable 189 Bcf Total 2P 539 Bcf Reserves Probable PUD Proved Developed 19 Bcf Proved Reserves at December 31,

11 Project Inventory Lifecycle Diversified Portfolio of Assets Asset Profile HIGHER RISK Prospect Leads Evaluating Garden City (Shale Play) Exploration Peace River Lasher Cahaba Early Stage Development Pond Creek LOWER RISK Development / Production EARLY STAGE MATURE 10

12 Financial Review 2008 Capital Expenditure Estimate Total Capex - $56.0 MM Gurnee $8.6 MM Pond Creek $15.8 MM Lasher $10.4 MM Development $43.3 MM Other $4.4 MM Garden City $8.4 MM Peace River $8.4 MM Land & Leasehold $2.7 MM Other $4.4 MM Exploration & Evaluation $5.6 MM Preliminary 2009 Capex Estimate - $40.0 MM 11

13 Areas of Operation Locator Map Peace River (British Columbia) Pond Creek (Virginia & West Virginia) Garden City - Shale (Alabama) Gurnee (Alabama) Birmingham, Alabama (Technical Headquarters) Lasher (West Virginia) Production and Development Area Early Stage Development Exploration Houston, Texas (Corporate Headquarters) 12

14 Existing Development Projects 13

15 Pond Creek Field (Central Appalachia) Locator Map Pond Creek Field (Central Appalachian Basin) Operator - GeoMet 100% W.I. PMC North Well # 066 Coal Group Coal Thickness (feet) Average coal thickness: 21 feet Welch 2.02 feet High gas content: approximately 460 cubic feet per ton Approximately 35,000 net acres under lease at 12/31/07 (42% developed) Reserves at 12/31/07 (D&M): Bcf Proved o o 77% Developed 65% Recovery factor 43.0 Bcf Probable War Creek Fire Creek 4 Pocahontas 8 Pocahontas 7 Pocahontas 6 Pocahontas 5 Pocahontas 4 Pocahontas 3 Pocahontas 2 Pocahontas feet 1.46 feet 1.54 feet 1.36 feet 1.75 feet 1.28 feet 8.58 feet 1.49 feet 2.46 feet 1.38 feet Total: feet 14

16 Pond Creek Field (Central Appalachia) Locator Map Pond Creek Field (Central Appalachian Basin) 231 Producing wells at 9/30/08 Near 14,000 Mcf/day current net gas sales Undrilled locations at 12/31/07 West Virginia Virginia West Virginia Lasher Lasher Prospect 83 PUD 190 Probable Pond Creek CDX Expected EUR per undrilled location = 453 MMcf Average cost per well - $484,000 (fully allocated) Kentucky Virginia Dickinson Nora Equitable Resources Field Oakwood CNX Gas Field Virginia Full Cycle economics approximately 25% ROR at $7.50/Mcf (NYMEX) Russell GeoMet Operations Other Operations 2009 Activity (Preliminary) GeoMet Gathering Pipeline Jewell Ridge Pipeline Drill 20 wells ETNG Pipeline 15

17 Pond Creek Field (Central Appalachia) Locator Map Pond Creek Field (Central Appalachian Basin) Litigation Update September 12,2008 Virginia Supreme Court unanimously ruled in favor of GeoMet in pipeline easement dispute with CNX Gas 16

18 Gurnee Field (Cahaba Basin) Locator Map Gurnee Field (Cahaba Basin) Operator - GeoMet 100% W.I. Average coal thickness: 50 feet USS Well # Coal Group Coal Thickness (feet) Thompson 3.20 feet Gholson 3.40 feet Average gas content: 300 cubic feet per ton Approximately 44,000 net acres under lease at 12/31/07 (38% developed) Coke Atkins Jones Alice feet 9.70 feet feet Reserves at 12/31/07 (D&M): Bcf Proved Big Bone J feet o 78% Developed o 55% Recovery Factor Wadsworth feet Bcf Probable Big Dirty feet Total: feet 17

19 Gurnee Field (Cahaba Basin) Locator Map Gurnee Field (Cahaba Basin) 239 Producing wells at 9/30/08 Over 6,000 Mcf/day current net gas sales Black Warrior Basin Dominion Resources Chevron White Oak Creek Creek El Paso El Paso Undrilled locations at 12/31/07 Energen Cahaba GeoMet Operations Cahaba 82 PUD 232 Probable Expected EUR per undrilled location = 676 MMcf Constellation Black Warrior River Dominion Resources Cahaba River Average cost per well - $622,000 (fully allocated) Energen Full Cycle economics approximately 20% ROR at $7.50/Mcf (NYMEX) Cahaba Basin 2009 Activity (Preliminary) Drill 5 wells Alabama Other CBM Projects GeoMet Projects Water Discharge Pipeline SONAT Bessemer Calera Pipeline GeoMetHigh Pressure Pipeline Enbridge Pipeline CDX Pipeline SONAT Interstate Pipeline 18

20 Early Stage Development Projects 19

21 Lasher Project (Central Appalachian Basin) Operator with 100% W.I. 10 miles north of Pond Creek Field West Virginia West Virginia Average coal thickness: 15 feet Average gas content: 375 cubic feet per ton Pond Creek Lasher Wyoming County Approximately 17,000 net acres under lease at 12/31/07 (3% developed) McDowell County Reserves at 12/31/07 (D&M): 7.4 Bcf Proved o 20% Developed Buchanan County o 61% Recovery factor 30.6 Bcf Probable Virginia GeoMet Operations Columbia Pipeline 20

22 Lasher Project (Central Appalachian Basin) Production commenced in October producing wells at 12/31/08 Total undrilled locations 114 Expected EUR per undrilled location MMcf Average cost per well - $424,000 (fully allocated) Economics similar to Pond Creek - Corehole - Salt water disposal well - Well sites - Production wells Columbia pipeline 21

23 Peace River Project (British Columbia) Operator with 50% W.I. 50,000 gross acres (25,000 net acres) Average coal thickness: 52 feet Average gas content: 400 cubic feet per ton Estimated gross gas-in-place in excess of 1 Tcf (NS&A) Activity through 12/31/08: 4 coreholes 12 production wells Constructed & installed facilities Commence production from 8 wells in December British Columbia Canada United States Adequate gas pipeline and water disposal capacity 2009 Activity (Preliminary) Drill 10 wells (5 wells, net) Mexico 22

24 Exploration Prospect 23

25 Garden City Prospect (Shale Gas) Approximately 80,000 gross leasehold acres Highly organic gas bearing Chattanooga Shale Depth ranges from 1,600-2,100 feet Shale thickness ranges from feet Winston County Cullman County Blount County Garden City Operator with 100% W.I. Multiple gas marketing options Activity through 12/31/08: 8 coreholes 6 production wells, including 2 horizontal wells Fayette County Tuscaloosa County Walker County Birmingham (Technical Headquarters) Jefferson County Shelby County St. Clair County Talladega County Connected 3 wells to sales 2009 Activities (Preliminary) Bibb County Chilton County Coosa County Drill 8 wells, including 2 horizontal wells Additional leasehold acquisition Alabama Gurnee Field 24

26 Financial Review 25

27 Financial Review Low-Cost Operations (2007) $6.00 $5.00 $4.00 Average: $4.09 GeoMet Components: 3 Year F&D: $1.25 LOE: $1.78* Transportation: $0.36 Compression: $0.37 Production taxes: $0.17 $ year F&D costs / Mcfe Operating Expense / Mcfe $3.00 $2.00 $1.00 $0.00 EQT PETD KWK RRC SWN XTO EOG PVA GMET EGN CHK PXD XEC HK UNT BRY SM WLL PQ DNR * Net of third party cost recoveries included in revenue Competitive cost structure that will improve with growth 26

28 Approximate Differential to NYMEX U.S. Regional Production Areas $1.00 $0.75 $0.50 $0.25 $- $(0.25) $(0.50) $(0.75) $(1.00) $(1.25) $(1.50) $(1.75) $(2.00) $(2.25) $(2.50) $(2.75) $(3.00) $(3.25) $(3.50) $(2.96) $(2.63) Rocky Mountains Financial Review $(0.36) $(0.74) Canadian Border (West) $(0.16) $(0.35) $(0.81) $(1.47) $(0.05) $- $0.09 East Texas Mid Continent South Louisiana GMET $ Differential to NYMEX 9 mo 2008 Differential to NYMEX 27

29 Low Asset Intensity Asset Intensity Advantage (2007) 70% 60% 50% 40% Average: 40% 30% 20% 10% 0% EQT UNT XTO KWK RRC GMET PETD EGN DNR CHK SWN XEC BRY EOG WLL HK SM PXD PQ Percentage of Operating Cash Flow to Replace Production 28

30 Growing Adjusted EBITDA* Financial Review $30,000 $25,000 $20,000 CAGR = 38% $22,779 $26,100 $15,000 $12,829 $10,000 $9,860 $5,000 $7,148 $ *Adjusted EBITDA is defined as net income before income taxes, net interest expense, other non-operating income or losses, DD&A, unrealized gains or losses on derivative contracts, stock based compensation and accretion expense. 29

31 Capitalization ($ in 000 s) Financial Review 9/30/08 Long Term Bank Debt (net of cash) $ 106,783 Stockholders' Equity 230,706 Total Capitalization $ 337,489 Long Term Bank Debt / Total Capitalization 32% Bank Debt Per Mcf Proved Reserves* $ 0.30 Borrowing Base $ 180,000 Availability, net $ 73,217 % Utilized, net 59% * Proved reserves at December 31, 2007 were Bcf 30

32 Low Debt Levels Relative to Asset Base $ Debt per Mcfe Proved Developed Reserves $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 Average: $0.98 $0.50 $- EOG XEC UNT GMET EGN PETD SWN SM EQT PXD DNR BRY RRC XTO WLL KWK PQ PVA CHK HK 31

33 Financial Review Consolidated Hedge Position as of September 30, 2008 Three-Way Collars Swaps Floor Quantity Floor Sold Purchased Cap Sold Quantity MMBtu/mo. $/MMBtu $/MMBtu $/MMBtu MMBtu/mo. $/MMBtu October ,000 $5.00 $7.00 $ ,000 $8.00 Winter 2008/2009 1,812,000 $6.13 $8.58 $ Summer ,568,000 $5.88 $8.00 $ Winter 2009/ ,000 $7.00 $9.50 $ Note: Winter includes the months of November through March and Summer includes the months of April through October 32

34 Enterprise Value per Mcf $8.00 Financial Review $7.00 $6.00 $5.00 $4.00 $3.00 Average: $2.52 $2.00 $1.00 $- GMET PETD PXD BRY EGN SM KWK WLL EQT XTO CHK XEC EOG DNR RRC PVA UNT PQ HK SWN Note: Based on proved reserves at 12/31/07; debt at 6/30/08 and closing stock price as of 10/29/08 33

35 Investment Considerations Summary Long life, shallow decline reserves Low finding and development costs Large inventory of low risk, low cost organic drilling opportunities Solid balance sheet, strong liquidity and attractive hedges 34

36 Appendix 35

37 Appendix Summary of Field Information As of 12/31/07 Appalachian Basin Cahaba Basin Pond Creek Lasher Gurnee Peace River (VA, WVA) (WVA) (ALA) (BC) Operator GeoMet GeoMet GeoMet GeoMet WI 100% 100% 100% 50% Average Coal Depths (feet) Average Coal Thickness (feet) Average Gas Content Core Holes Gas Desorption Tests Net Acres 35,000 17,000 44,000 25,000 % Developed 42% 3% 38% 0% Producing Wells Proved Reserves (Bcf) N/A % Developed 77% 20% 78% N/A Probable Reserves (Bcf) N/A Undrilled Locations Proved N/A Probable N/A 36

38 Appendix Three Year Average Finding and Development Cost For the Period Ended For the 3 Year Period ended 12/31/07 Costs Incurred ($): Acquisition costs-proved and unproved $17,036,242 Exploration costs 27,489,049 Development costs 151,558,136 Asset retirement costs 1,374,321 Total costs incurred per SFAS 69 $197,457,748 Proved Reserve Additions (Mcf): Revisions to previous estimates 7,922,000 Extensions and discoveries 148,526,000 Acquisition 1,824,000 Proved reserves additions 158,272,000 Change in proved developed reserves (Mcf) 97,355,000 Three-year average finding and development cost (per Mcf) $

39 Appendix Reconciliation of Non-GAAP Measures - Adjusted EBITDA ($ in 000 s) 9 Months Net Income $ 12,163 $ 3,561 $ 5,169 $ 17,296 $ (1,573) Add: Interest expense, net of interest income and amounts capitalized 3,502 3,551 5,090 3,097 3,818 Add (Deduct): Other expense (47) Add (Deduct): Expense for income taxes 8,135 1,958 3,095 10,866 (993) Add: Depreciation, depletion and amortization 7,472 6,688 9,092 7,876 4,867 Add: Minority interest (442) EBITDA 31,225 15,809 22,514 39,145 5,698 Add (Deduct): Unrealized losses (gains) on derivative contracts (820) 2,249 3,007 (16,877) 12,059 Add: Stock based compensation Add: Accretion expense Adjusted EBITDA $ 31,148 $ 18,473 $ 26,042 $ 22,792 $ 17,829 38

40 Appendix Reconciliation of Non-GAAP Measures - Adjusted Net Income ($ in 000 s) 9 Months Net Income As Reported $ 12,163 $ 3,561 $ 5,169 $ 17,296 $ (1,573) Unrealized losses (gains) on derivative contracts, net of tax (492) 1,456 2,110 (10,238) 12,059 Adjusted Net Income $ 11,671 $ 5,017 $ 7,279 $ 7,058 $ 10,486 39

41 Appendix Reconciliation of Non-GAAP Measures - Adjusted Lease Operating Expense ($ in 000 s) 9 Months Lease Operating Expenses as Reported $ 10,867 $ 10,353 $ 13,981 $ 11,579 Less: Saltwater disposal fees rported as income , Adjusted Lease Operating Expense $ 10,220 $ 9,396 $ 12,692 $ 11,438 40

42 For More Information, Please Contact: J. Darby Seré Chairman, President & CEO (713) William C. Rankin Executive Vice President & CFO (713) Stephen M. Smith Treasurer (713)