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GeoMet, Inc. Announces Fourth Quarter and Year-end 2007 Results

Houston, Texas – March 17, 2008—GeoMet, Inc. (NASDAQ: GMET) (“GeoMet” or the “Company”) today announced financial and operating results for the fourth quarter and the year ended December31, 2007.

Fourth Quarter 2007 Results

For the quarter ended December31, 2007, GeoMet recorded net income of $1.6 million, or $0.04, per fully diluted share as compared to net income of $3.6 million, or $0.09, per fully diluted share for the same period in 2006. During both periods, net income was impacted by unrealized gains or losses from the change in the market value of its derivative contracts. In the current quarter, the Company experienced an unrealized loss from such derivative contracts of $0.76 million ($0.44 million after income taxes or $0.01 per fully diluted share) as compared to an unrealized gain $2.30 million ($1.86 million after income taxes or $0.05 per fully diluted share) for the same period in 2006.

EBITDA was $6.7 million for the quarter as compared to $7.4 million in the same period of 2006. Adjusted EBITDA for the quarter was $7.6 million compared to $5.1 million for the prior year period. EBITDA and Adjusted EBITDA are non-GAAP measures.  See the accompanying table for reconciliations of net income to EBITDA and of EBITDA to Adjusted EBITDA.

Average net gas sales volumes for the quarter were 20.2 MMcf per day, a 7% increase from the fourth quarter of 2006.  The average natural gas price, adjusted for realized hedging gains, was $7.80 per Mcf during the fourth quarter of 2007 versus $7.04 per Mcf for the same period in 2006. Excluding the impact of hedging, the average natural gas price during the quarter was $7.07 per Mcf as compared to the prior year period average of $6.64 per Mcf.

Capital expenditures for the quarter ended December 31, 2007 were $9.0 million, compared to $19.5 million for the same period in the prior year.

Year-End 2007 Results

For the year ended December31, 2007, GeoMet recorded net income of $5.2 million, or $0.13, per fully diluted share as compared to net income of $17.3 million, or $0.48, per fully diluted share for the same period in 2006.  During both periods, net income was impacted by unrealized gains or losses from the change in the market value of its derivative contracts. In the current year, the Company experienced an unrealized loss from such derivative contracts of $3.00 million ($1.88 million after income taxes or $0.05 per fully diluted share) as compared to an unrealized gain of $16.88 million ($10.37 million after income taxes or $0.29 per fully diluted share) for 2006.

EBITDA was $22.4 million for the year ended December31, 2007 as compared to $39.1 million in the same period of 2006. Adjusted EBITDA for the year end was $26.1 million as compared to $22.8 million for the prior year period. EBITDA and Adjusted EBITDA are non-GAAP measures.  See the accompanying table for reconciliations of net income to EBITDA and of EBITDA to Adjusted EBITDA.

Net gas sales volumes for the year ended 2007 averaged 19.5 MMcf per day, a 14% increase compared to 2006. The average natural gas price, adjusted for realized hedging gains, was $7.52 per Mcf during 2007 versus $7.37 per Mcf for 2006. Excluding the impact of hedging, the average natural gas price for 2007 decreased to $6.97 per Mcf as compared to the prior year period average of $7.19 per Mcf.

 Capital expenditures for the year ended 2007 were $53.9 million, compared to $81.6 million for the prior year.

Commenting on the year just ended, Darby Seré, Chairman, President & Chief Executive Officer stated, “Although we faced several challenges in 2007, we never lost our focus. Our three-year finding and development cost for the period ended December 31, 2007 was $1.25 per Mcf, and our reserve replacement over the same period was 882%.  In January, we announced year-end 2007 proved reserves of 350 Bcf, an increase of 8% over 2006, as detailed in a report prepared by DeGolyer & McNaughton (“D&M”), an independent petroleum engineering firm.  Since the release of that information, D&M prepared a report which identified approximately 480 net additional unproved drilling locations in the Pond Creek, Gurnee and Lasher fields, assigning 189 Bcf of net probable reserves to these additional unproved drilling locations. In addition, considering the significant resource potential in our Peace River coalbed methane project in British Columbia and our Garden City Chattanooga Shale prospect in Alabama, I believe that we are in excellent position to continue significant growth in production, reserves and cash flows.” Finding and development cost is a non-GAAP measure. 

Fourth Quarter & Year-end 2007 Financial Schedules

Disclosure Statements

Reserve Disclosure

The Securities and Exchange Commission (“SEC”) permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. GeoMet and the independent petroleum engineering firm that GeoMet engaged use the term “probable reserves” to describe volumes of reserves potentially recoverable through additional drilling that the SEC's guidelines do not allow to be included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves. All estimates of probable reserves in this news release have been prepared by an independent petroleum engineering firm.

Forward-Looking Statements Notice

This press release may contain “forward-looking statements” within the meaning of Section27A of the Securities Act of 1933, as amended, and Section21E 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.

Finding and Development Cost Disclosure

Finding and development cost is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States of America and, thus, may be calculated differently by different companies; however, we believe that it is useful to GeoMet and to an investor in evaluating our company versus other companies in the industry because it is a widely used measure within the oil and gas industry. See our calculation, as well as an alternative calculation below (calculations may also be found on our website at www.geometcbm.com):

Three Year Finding and Development Costs

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

Three-year average finding and development cost (per Mcf)

$1.25

Alternate Method Including Changes in Unevaluated Gas Properties Not Subject To

Amortization and Future Development Costs Related to Proved Undeveloped Reserves

Total costs incurred per SFAS 69 (from above)

$197,457,748

Change in future development costs related to proved undeveloped reserves

68,113,380

Change in unevaluated gas properties, not subject to amortization

(17,942,217)

Total costs incurred per SFAS 69 adjusted for changes in future development costs less the changed in unevaluated gas properties, not subject to amortization

$247,628,911

Three-year average finding and development cost including changes in unevaluated gas properties not subject to amortization and future development costs related to proved undeveloped reserves (per Mcf)

$1.56

Conference Call Information

GeoMet will hold its quarterly conference call to discuss fourth quarter and year-end 2007 results on Monday, March17, 2008 at 10:30 a.m. Central Time. To participate, dial (888)571-8168 a few minutes before the call begins. Please reference GeoMet, Inc. conference ID 38041025. The call will also be broadcast live over the Internet from the Company’s website at www.geometinc.com.A replay of the conference call will be archived on the Company’s website shortly after the end of the call on Monday, March17, 2008.

About GeoMet, Inc.

GeoMet, Inc. is an independent energy company primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane”) and non-conventional shallow gas. Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the Central Appalachian Basin in West Virginia and Virginia. We also control additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia.

For more information please contact Stephen M. Smith at (713)287-2251 or ssmith@geometcbm.com or visit our website at www.geometinc.com.