Issuer Free Writing Prospectus

Filed Pursuant To Rule 433

Registration Statement No. 333-131716

October 1, 2007

The issuer has filed a registration statement (including a prospectus) with the SEC for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents the issuer has filed with the SEC for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the SEC Web site at www.sec.gov. Alternatively, the issuer, any underwriter or any dealer participating in the offering will arrange to send you the prospectus if you request it by calling (713) 287-2261. The prospectus relating to this offering is available by clicking on the following link or by copying it and pasting the link into your web browser:

http://searchwww.sec.gov/EDGARFSClient/jsp/EDGAR_MainAccess.jsp#topAnchor; and then type GMET.

IPAA OGIS San Francisco October 1, 2007

2 Forward Looking Statements This presentation includes forward-looking statements made in reliance on the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Words such as "believes," "anticipates," "expects," "intends,“ "targeted," and similar expressions, generally identify forward-looking statements and should be read carefully. These statements are based on GeoMet's current expectations and beliefs and are subject to a number of risks, uncertainties and assumptions that could cause actual results to differ materially from those described in the forward-looking statements. Risks, uncertainties and assumptions include (i) risks inherent in the exploration for and development and production of coalbed methane and in estimating reserves, (ii) the presence or recoverability of estimated reserves, (iii) the ability to replace reserves, (iv) unexpected future capital expenditures, (v) general economic conditions, (vi) gas price volatility, (vii) the success of our hedging and other risk management activities, (viii) competition, (ix) regulatory changes, (x) the ability of management to execute its plans to meet its goals, (xi) cost and availability of transportation to get our gas to market, and (xii) other factors discussed in GeoMet's filings with the United States Securities and Exchange Commission. GeoMet assumes no obligation to publicly update or revise any forward-looking statements contained in this presentation, whether as a result of new information, future events, or otherwise.

3 Summary Track Record of Success Substantial expertise and experience as a developer and operator of coalbed methane properties since 1985 Developed 5 large scale CBM projects in four separate basins (Black Warrior, Raton, Central Appalachia and Cahaba Basins) 19 person technical, professional and project management team averages more than 16 years of CBM experience Operational Characteristics Proved reserves of 326 Bcf at YE 06 (75 % proved developed) Long lived reserves with low finding and development and unit operating costs Current net daily gas sales volumes of approximately 20 MMcf 100% operational control Positioned for Growth Large inventory of development locations in existing 100% W.I. projects High potential in new development and exploration opportunities

4 Recent Developments New Development Projects Lasher – 10 miles north of Pond Creek Field, West Virginia – Approximately 16,548 net leasehold acres – Operator with 100% W.I. Peace River – Near Hudson’s Hope, British Columbia – Approximately 50,188 gross leasehold acres – Operator with 50% W.I. New Exploration Prospect Garden City – Chattanooga Shale opportunity in North Central Alabama – Approximately 60,000 gross leasehold acres – Complementary production characteristics to CBM – Significant resource in-place – Operator with 100% W.I.

5 Recent Developments Gurnee Field Production – Field not yet responding like a typical CBM project and production has been essentially flat over the past four quarters – High-graded 2007 drilling program – Conducting new well-treatment techniques to increase production – Similar production difficulties encountered in the early stages of Pond Creek field development Pond Creek Gathering Line Right-of-Way Litigation – May 23, 2007 – Virginia Trial Court ruled in favor of CNX Gas’ “exclusive rights claim” and enjoined us from transporting gas across the PMC property unless we satisfied several restrictive requirements – June 20, 2007 – Virginia Supreme Court vacated the injunctive portion of the order and removed the restrictive requirements allowing us to move our Pond Creek production through our gathering line – July 30, 2007 – GeoMet petitioned the Virginia Supreme Court to accept our appeal of the portion of the order that affirmed CNX Gas’ “exclusive rights claim” Existing Projects

Existing Development Projects

7 Pond Creek Field (Central Appalachia) Locator Map West Virginia, Virginia border Pennsylvanian Age Pottsville coals Coal thickness ranges from 10 – 30 feet High gas content - > than 500 cubic feet per ton 34,982 net acres under lease Operator - GeoMet – 100% W.I. Key Facts CDX Equitable Resources Dickinson CNX Gas Lasher Prospect Virginia West Virginia GeoMet Operations Other Operations GeoMet Operations Other Operations GeoMet Gathering Pipeline Jewell Ridge Pipeline ETNG Pipeline Virginia West Virginia Nora Field Oakwood Field

8 Pond Creek Field Profile 2H 2007 Plan $12 MM CAPEX Bring online 19 additional wells Resolve or advance litigation Operating Data Initial gas sales in February 2003 Current net sales of approximately 12.5 MMcf/d Over 200 wells producing Reserve & Resource Base 130 Bcf of Proved Reserves at YE 2006 68% proved developed 14 coreholes to determine gas in-place Approximately 287 undrilled locations (85 PUDS) at YE 06 Proved Undeveloped Potential Drill Sites Compressor Sites Proved Developed Drilled Coreholes Well locations High Pressure Pipelines

9 Pond Creek Field Daily Sales Gross Daily Gas Sales Well Count 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 17,000 18,000 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 400

10 Gurnee Field (Cahaba Basin) Locator Map Across anticline from Black Warrior Basin Pennsylvanian Age Pottsville coals Average coal thickness 50 feet 43,686 net acres under lease Operator - GeoMet – 100% W.I. GeoMet Cahaba Operations GeoMet Cahaba Operations Black Warrior Methane El Paso Energen Energen Constellation Dominion Resources El Paso White Oak Creek Dominion Resources Cahaba Basin Black Warrior River Cahaba River White Oak Creek Black Warrior Basin GeoMet Projects Water Discharge Pipeline SONAT Bessemer Calera Pipeline SONAT Interstate Pipeline GeoMet High Pressure Pipeline CDX Pipeline Enbridge Pipeline Other CBM Projects Alabama Key Facts

11 Gurnee Field (Cahaba Basin) Profile Reserve & Resource Base 193 Bcf of Proved Reserves at YE 06 78% Proved Developed 33 Coreholes to determine gas in-place Approximately 346 undrilled locations (74 PUDS) at YE 06 2H 2007 Plan $10.4 MM CAPEX Bring online 23 additional wells Well treatment program Complete and test 2 wells west of Cahaba River Operating Data Full scale development in March 2005 Current net sales approximately 6.5 MMcf/d Over 200 wells producing Water Discharge Pipeline High Pressure Pipeline Proved Undeveloped Potential Drill Sites Compressor Sites Drilled Coreholes Proved Developed Well locations Cahaba River

12 Gurnee Field (Cahaba Basin) Daily Sales Gross Daily Gas Sales Daily Water Production 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000

New Development Projects

14 Lasher Project Locator Map 10 miles north of Pond Creek Field Operator with 100% W.I. 16,548 net contiguous leasehold acres Key Facts Virginia West Virginia Pond Creek Lasher Wyoming County McDowell County Buchanan County GeoMet Operations Columbia Pipeline West Virginia

15 Lasher Project Profile Drill 2 production wells Secure agreements for pipeline tie-in Targeting the Pocahontas formation of the Pottsville coal group at depths up to 1,800 feet 4 coreholes to determine gas in-place 2 production test wells drilled Approximately 130 undrilled locations Operational salt water disposal well on property Firm Capacity on Columbia KA-20 pipeline which crosses property - Salt water disposal well - Corehole - Well sites Columbia pipeline - Production wells 2H 2007 Development Plan Profile

16 Peace River Project Locator Map Near Hudson’s Hope, British Columbia 50,188 gross acres (25,094 net acres) Operator with 50% W.I. Attractive royalty incentive package – Expected effective rate < 10% No severance tax United States Mexico Canada British Columbia Key Facts

17 Peace River Project Profile Activity To Date 3 coreholes to determine gas in-place 7 production test wells 2 water disposal wells Summary Cretaceous age Gething coals Depth ranges from 1,000 – 3,000 ft Over 400 MMcf/d of available pipeline capacity crosses acreage Access to both U.S. and Canadian gas markets 2007 – 2008 Development Plan Complete consultations, permitting and project infrastructure Drill one or more water disposal wells Drill up to 25 initial development wells Net CAPEX up to US$25 MM ? Hudson's Hope - Production Test Well - Corehole - Salt Water Disposal Well

Garden City Prospect

19 Garden City Prospect Locator Map Tuscaloosa County Fayette County Walker County Jefferson County Shelby County Bibb County Chilton County Coosa County Talladega County St. Clair County Blount County Cullman County Winston County Birmingham (Technical Headquarters) Gurnee Field Alabama Garden City

20 Garden City Prospect Profile Activity To Date 4 coreholes drilled to determine gas in-place and reservoir properties 2H 2007 Plan $ 2.7 MM Capex 1 Corehole 3 production test wells Expand acreage position Summary Approximately 60,000 gross leasehold acres Highly organic gas bearing Chattanooga Shale Depth ranges from 1,700 to 2,000 feet Shale thickness ranges from 35 – 90 feet Multiple gas marketing options Stratigraphic Unit Series Eocene Paleocene Claiborne Group Wilcox Group Midway Group Selma Group Eutaw Group Tuscaloosa Group Pottsville Formation Parkwood Formation Floyd Shale Upper Middle & Lower Upper Lower Fort Payne Chert Chattanooga Shale Unnamed Cherty Limestone Undifferentiated Undifferentiated Stones River Group Knox Group Conasauga Group Rome Formation Upper & Middle Lower Upper Middle Lower Middle

Financial Overview

22 Economic Parameters (1) The cost of finding and developing reserves is calculated for the three year time period by taking the sum of the cost incurred for exploration, development and acquisition, including future development costs attributable to proved undeveloped reserves, adjusted for the change for the period in the balance of unevaluated gas properties not subject to amortization and dividing such amount by the total proved reserve additions (2) Reserve additions for the period used to compute finding and development costs have been estimated by independent petroleum engineers and adjusted for revisions to previous estimates. (3) See appendix for calculations of three average finding and development 3 year average (excluding future development costs (2) ) $0.84 per Mcf (3) 3 year average (including future development costs (2) ) $1.16 per Mcf (3) Low Finding & Development Costs (1) Moderate and declining operating costs < $2.00 per Mcf Positive gas price differentials > $0.10 per Mcf Other

23 Capitalization ($ in thousands) Long-Term Bank Debt 80,500 $  6/30/07 Stockholders' Equity Total Capitalization 213,726 294,226 $  $ Long Term Bank Debt  / Total Capitalization 27% Bank Debt per Mcf (1) 0.25 $      (1) Reserves as of December 31, 2006

24 Track Record of Growth (1) Adjusted EBITDA is defined as EBITDA before unrealized losses (gains) on derivative contracts, stock-based compensation and accretion of asset retirement obligations. For reconciliation of Adjusted EBITDA, please refer to the appendix. (2) Proved reserves and capital expenditures include White Oak Creek Field working interest, sold in 2004 (3) Excludes $27 million for acquisition of producing properties in Pond Creek in 2004 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 2003 2004 2005 2006 1H 2007 Net Daily Sales Volumes Adjusted EBITDA (1) 0 50 100 150 200 250 300 350 2003 2004 2005 2006 210 263 326 104 White Oak Creek Field working interest, sold in 2004 0 10 20 30 40 50 60 70 80 90 100 2003 2004 2005 2006 2007 E 59 82 62 36 59 0 5000 10000 15000 20000 25000 2003 2004 2005 2006 1H 2007 7,148 9,860 17,829 22,779 3,246 7,226 12,585 3,560 1,475 6,806 8,701 17,064 19,154 12,919 Proved Reserves (2) Capital Expenditures (2) (3)

25 Natural Gas Production Hedges (1) (1) As of June 30, 2007 (2) Protection is the difference between the Floor (a bought put) and the Floor Price Phase-out (a sold put). This protection remains a constant and fixed price enhancement as prices decline below the Floor Price Phase-out. Period Volume MMBtu Cap Floor Protection (2) July 2007 – October 2007 984,000 $ 10.50 $ 7.38 $ 1.63 November 2007 – March 2008 1,216,000 $ 14.80 $ 9.00 $ 3.00 April 2008 – October 2008 1,712,000 $ 10.50 $ 7.00 $ 2.00 Three Way Collars Traditional Collars July 2007 – October 2007 492,000 $ 9.75 $ 7.50 n/a November 2007 – March 2008 608,000 $ 11.25 $ 8.25 n/a Weighted Average Price per MMBtu Type

26 % Estimated Sales Volumes Hedged 0% 10% 20% 30% 40% 50% 60% 70%

27 Summary Track Record of Success Operational Characteristics Positioned for Growth

Appendix

29 Three Year Average Finding and Development Cost Costs Incurred Three Years Ended 12-31-06 Acquisition Costs - Proved and Unproved 40,072 $               Exploration Costs 27,339 Development Costs 158,186 Abandonment Costs 2,058 Increase (decrease) in Unevaluated properties not subject to amortization (23,330) Three Year Total 204,325 $             Change in Future Development Costs 77,945 Total Finding & Development Costs - Including Estimated Future Development Costs 282,270 $             Proved Reserve Additions (MMcf) Revisions to Previous Estimates 17,434 Extensions & Discoveries 193,079 Acquisition 33,599 Three Year Total 244,112 Finding Cost - Excluding Future Development Costs 0.84 $                    Finding Cost - Including Future Development Costs 1.16 $

30 Reconciliation of Non-GAAP Measure Six Months Ended June 30, 2007 2006 2005 2004 2003 Net Income (loss) 1,973 $         17,296 $       (1,573) $        3,836 $         2,560 $         Add: Interest expense, net of interest income and amounts capitalized 2,111 3,097 3,818 916 138 Add (Deduct): Other expense (income) loss 25 10 21 4 7 Add (Deduct):Expense (benefit) for income taxes 1,491 10,880 (993) 2,312 1,651 Add: Depreciation, depletion and amortization 4,341 7,876 4,867 2,691 2,120 Add: Minority interest - 23 (442) 584 571 EBITDA 9,940 39,182 5,698 10,343 7,047 Add (Deduct): Unrealized losses (gains) on derivative contracts 2,713 (16,877) 12,059 (542) 101 Add: Stock based compensation 163 317 - - - Add: Accretion expense 103 157 72 59 - Adjusted EBITDA 12,919 $       22,779 $       17,829 $       9,860 $         7,148 $         December 31, Twelve Months Ended

For More Information, Please Contact: J. Darby Seré Chairman, President & CEO dsere@geometcbm.com (713) 287 - 2253 William C. Rankin Executive Vice President & CFO brankin@geometcbm.com (713) 287 - 2257 Stephen M. Smith Treasurer ssmith@geometcbm.com (713) 287 - 2251