Statement Regarding Forward-Looking Information

Management's Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management's beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words "believe," "anticipate," "estimate," "expect," "intend," and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

You should read "Management's Discussion and Analysis of Financial Condition and Results of Operations" in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2007, which are included in our Annual Report on Form 10-K that we filed with the Securities Exchange Commission on March 14, 2008.

Overview

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" or "CBM") 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. As of September 30, 2008, we control a total of approximately 230,000 net acres of coalbed methane and oil and gas development rights.

We primarily explore for, develop, and produce CBM and non-conventional shallow gas. Our objective is to create the premier non-conventional shallow gas company in North America (emphasizing coalbed methane) while maximizing stockholder value through the efficient investment of capital to increase reserves, production, cash flow and earnings. We believe that substantial expertise and experience is required to develop, produce, and operate coalbed methane and non-conventional shallow gas fields in an efficient manner. We believe that the inherent geologic and production characteristics of coalbed methane and non-conventional shallow gas offer significant operational advantages compared to conventional gas production.

Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is subject to a variety of risks. For example, our ability to drill on our properties and fund our capital budgets depends, to a large extent, upon our ability to generate cash flow from operations at or above current levels and maintain borrowing capacity at or near current levels under our revolving credit facility, or the availability of future debt and equity financing at attractive prices. Our ability to fund CBM property acquisitions and compete for and retain the qualified personnel necessary to conduct our business is also dependent upon our financial resources. Changes in natural gas prices, which may affect both our cash flows and the value of our gas reserves, our ability to replace production through drilling activities, a material adverse change in our gas reserves due to factors other than gas pricing changes, our ability to transport our gas to markets, drilling costs, lower than expected production rates, material adverse outcomes from lawsuits and other factors, many of which are beyond our control, may adversely affect our ability to fund our anticipated capital expenditures, pursue property acquisitions, and compete for qualified personnel, among other things.

Impact of Current Credit Market Conditions - We feel that we are well-positioned for the current credit market environment. We have a healthy balance sheet with nearly $2 million in cash and a debt-to-book capital ratio of 47%. The borrowing base on our revolving credit facility was reaffirmed at $180 million in October 2008. If not extended, our credit facility will mature in January 2011. All of our lenders are currently funding our borrowing requests. Because of our cash flows from operations, we are not as dependent on credit to fund our current capital programs. We believe that our current cash and short-term investment balances, cash generated by operations, and access to our credit facility will be sufficient to meet our operating and capital needs in the foreseeable future.

The table below presents information on gas sales, net sales volumes, production expenses and per Mcf data for the three and nine months ended September 30, 2008 and 2007. This table should be read with the discussion of the results of operations for the periods presented below (in millions).

                                                   Three Months Ended             Nine Months Ended
                                                     September 30,                  September 30,
                                                2008      2007     Change      2008      2007     Change
Gas sales                                      $  18.7   $  11.3       65 %   $  55.0   $  36.6       50 %
Production expenses                            $   5.2   $   5.0        4 %   $  15.7   $  15.2        3 %
Net sales volumes (MMcf)                         1,821     1,804        1 %     5,548     5,271        5 %
Average natural gas sales price (per Mcf)      $ 10.26   $  6.26       64 %   $  9.91   $  6.94       43 %

As a result of both the increased gas sales volumes and prices, gas sales revenue for the three and nine months ended September 30, 2008 are up 65% and 50%, respectively.

Operational Developments

Operational activity during the three and nine months ended September 30, 2008, include the following:

Pond Creek - We drilled fifteen and connected seven new wells to sales in the third quarter. We connected eleven wells to sales during the first nine months of 2008 giving us a total of 231 productive wells in the Pond Creek field. Upon completion of required permitting and acquisition of certain right-of-way agreements, five additional new wells are planned to be drilled and twelve new wells placed into sales in the last three months of 2008. Net gas sales increased to 13.6 MMcf per day for the three months ended September 30, 2008, as compared to 12.5 MMcf per day for the three months ended September 30, 2007. Net gas sales increased to 13.5 MMcf per day for the nine months ended September 30, 2008, as compared to 12.2 MMcf per day for the nine months ended September 30, 2007.

Lasher - Production testing continued on three previously drilled wells and thirteen wells drilled in the first nine months of 2008 to begin the initial dewatering process. Two additional wells will be completed in the fourth quarter to bring the total number of producing wells to 18. Water and gas gathering systems and the high-pressure pipeline that will be used to transport the natural gas to the market have been installed and the compressor and metering station is in the final stage of completion. Initial gas sales are expected to begin in the fourth quarter. Initial gas sales commenced on October 28, 2008.

Gurnee - Five new wells were drilled and connected to sales during the first nine months of 2008 bringing the total number of productive wells to 239. Production testing of two test wells west of the Cahaba River is continuing with encouraging results. Seven additional wells are being drilled on the east side of the Cahaba River, which we expect to place into sales in the fourth quarter of 2008. Net gas sales were 6.1 MMcf per day for the three and nine months ended September 30, 2008, as compared to 6.1 MMcf per day and 6.0 MMcf per day, respectively, for the three and nine months ended September 30, 2007.

Garden City - In this Chattanooga shale prospect two vertical wells were re-stimulated and a horizontal well drilled in the second quarter was completed in the third quarter. These three wells were connected to sales in the third quarter with net gas sales averaging 0.2 MMcf per day through September 30, 2008. One additional horizontal well is planned to be drilled and completed in the fourth quarter. Two vertical test wells drilled in the western portion of the prospect are currently shut-in awaiting the identification of adequate water disposal and connection into a gas sales line. Additional activity in the fourth quarter will include evaluating the potential for water disposal.

Peace River - The 2008 capital expenditure plan for Peace River is proceeding according to plan. The installation of the facilities is continuing and five new wells have been drilled and completed. The five new wells and three existing wells are planned to be on production by year-end, at which time initial proved reserves are expected to be booked for this project.

Property Conveyance and Dispute

We had previously entered into an agreement to sell our interests in a property, subject to a preferential right to purchase held by another party, which the other party subsequently exercised. A dispute arose as to whether the preferential right to purchase applied to all the interests we owned in this property or just the working interests. We filed a declaratory judgment action asserting that the preferential right to purchase applied only to the working interests, and that we were entitled to retain all remaining interests we owned in the property. Following a partial agreement with the other party, we assigned all our remaining interests in the property to that party, effective July 1, 2008. The remaining issue in this case relates to the correct application of interest to the sums owed between the parties. On October 17, 2008, the 116th Judicial District Court of Dallas issued an order requiring us to pay $575,000 to the other party in final settlement of the issue.

Consequently, as of September 30, 2008, we have accrued that amount as a liability, representing a purchase price adjustment. We intend to appeal the ruling by the court. The proved reserves being conveyed represent less than 1% of our total proved reserves and the related production is approximately 900 Mcf per day.

Critical Accounting Policies

The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting polices are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. There have been no changes to our critical accounting policies during the three and nine months ended September 30, 2008. We have included additional critical accounting policy information not included in the "Critical Accounting Policies" section of our Annual Report on Form 10-K for the year ended December 31, 2007 in order to expand our revenue recognition accounting policy to include gas balancing.

Revenue Recognition and Gas Balancing. We derive revenue primarily from the sale of produced natural gas. We use the sales method of accounting for the recognition of gas revenue whereby revenues, net of royalties, are recognized as the production is sold to purchaser. The amount of gas sold may differ from the amount to which the Company is entitled based on its working interest or net revenue interest in the properties. We typically do not have any significant producer gas imbalance positions because we own 100% working interest in the majority of our properties. A ready market for natural gas allows us to sell our natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our nominations and net revenue interests. Pipeline imbalances occur when our production delivered into the pipeline varies from the gas we nominated for sale. Pipeline imbalances are settled with cash approximately thirty days from date of production and are recorded as a reduction of revenue or increase of revenue depending upon whether we are over-delivered or under-delivered.

Settlements of gas sales occur after the month in which the gas was produced. We estimate and accrue for the value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period during which payments are received from the purchaser.

                      Producing Fields Operations Summary

The table below presents information on gas sales, net sales volumes, production
expenses and per Mcf data for the three and nine months ended September 30, 2008
and 2007. This table should be read with the discussion of the results of
operations for the periods presented below (in thousands).



                                                        Three Months Ended       Nine Months Ended
                                                          September 30,            September 30,
                                                         2008         2007        2008        2007
Gas sales                                             $    18,674   $ 11,303   $   54,956   $ 36,590

Lease operating expenses                              $     3,475   $  3,560   $   10,867   $ 10,353
Compression and transportation expenses                     1,129      1,166        3,178      4,033
Production taxes                                              599        260        1,655        858

Total production expenses                             $     5,203   $  4,986   $   15,700   $ 15,244

Net sales volumes (MMcf)                                    1,821      1,804        5,548      5,271
Pond Creek field                                            1,252      1,150        3,698      3,326
Gurnee field                                                  558        560        1,667      1,648
Per Mcf data ($/Mcf):
Average natural gas sales price                       $     10.26   $   6.26   $     9.91   $   6.94
Average natural gas sales price realized(1)           $      9.49   $   6.95   $     9.54   $   7.42
Lease operating expenses                              $      1.91   $   1.97   $     1.96   $   1.96
Pond Creek field                                      $      1.46   $   1.56   $     1.53   $   1.65
Gurnee field                                          $      2.81   $   3.13   $     3.07   $   2.95
Compression and transportation expenses               $      0.62   $   0.65   $     0.57   $   0.77
Pond Creek field                                      $      0.65   $   0.80   $     0.62   $   1.00
Gurnee field                                          $      0.55   $   0.47   $     0.53   $   0.45
Production taxes                                      $      0.33   $   0.14   $     0.30   $   0.16
Pond Creek field                                      $      0.19   $   0.01   $     0.15   $   0.01
Gurnee field                                          $      0.64   $   0.37   $     0.60   $   0.41
Total production expenses                             $      2.86   $   2.76   $     2.83   $   2.89
Pond Creek field                                      $      2.30   $   2.37   $     2.30   $   2.66
Gurnee field                                          $      4.00   $   3.97   $     4.20   $   3.81
Depreciation, depletion and amortization              $      1.39   $   1.30   $     1.35   $   1.27

(1) Average realized price includes the effects of realized (gains) losses on derivative contracts.

Results of Operations

Three Months Ended September 30, 2008 compared with Three Months Ended September 30, 2007

The following are selected items derived from our consolidated statement of operations and their percentage changes from the comparable period are presented below.

                                                            Three Months Ended September 30,
                                                           2008              2007          Change
                                                                     (in thousands)
Gas sales                                              $     18,674       $    11,303          65 %
Lease operating expenses                               $      3,475       $     3,560          -2 %
Compression expense                                    $        824       $       620          33 %
Transportation expense                                 $        305       $       546         -44 %
Production taxes                                       $        599       $       260         130 %
Depreciation, depletion and amortization               $      2,524       $     2,347           8 %
General and administrative                             $      2,098       $     2,538         -17 %
Realized losses (gains) on derivative contracts        $      1,390       $    (1,228 )        NM
Unrealized gains from the change in market value of
open derivative contracts                              $    (21,565 )     $      (464 )        NM
Interest expense, net of amounts capitalized           $      1,118       $     1,448         -23 %
Income tax expense                                     $     10,604       $       454          NM
Discontinued operations                                $         -        $        45          NM

NM-Not Meaningful

Gas sales. Gas sales increased by $7.37 million, or 65%, to $18.67 million compared to the prior year quarter. The increase in gas sales was a result of primarily increased gas prices. Production increased 1% and average gas prices increased 64%, excluding hedging transactions. The $7.37 million increase in gas sales consisted of a $7.26 million increase in prices and a $0.11 million increase in production.

Lease operating expenses. Lease operating expenses decreased by $0.09 million, or 2%, to $3.48 million compared to the prior year quarter. The decrease in lease operating expenses consisted of $0.03 million increase in production offset by $0.12 million decrease in costs. The $0.12 million decrease was primarily comprised of a decrease in repair and maintenance expenses for the wells in all of our fields.

Compression expense. Compression expense increased by $0.20 million, or 33%, compared to the same period in the prior year. The increase in compression expense consisted of $0.01 million increase in production and $0.19 million increase in costs. The $0.19 million increase in costs was primarily comprised of an increase in repair and maintenance expenses for the compressors in our Pond Creek field.

Transportation expense. Transportation expenses decreased by $0.24 million, or 44%, to $0.31 million compared to the prior year quarter. The $0.24 million decrease was primarily comprised of a decrease in transportation expenses resulting from the commencement of transportation on our own system from the Pond Creek field and the temporary release of a portion of our firm capacity commitments related to our Pond Creek field.

Production taxes. Production taxes increased by $0.34 million, or 130%, to $0.60 million compared to the prior year quarter. The increase in production taxes is due to the phase-in of the state taxes on production of natural gas in our Pond Creek field, higher gas prices and increased production.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $0.18 million, or 8%, to $2.52 million compared to the prior year quarter. The depreciation, depletion and amortization increase consisted of a $0.02 million increase in production and a $0.15 million decrease in the depletion rate.

General and administrative. General and administrative expenses decreased by $0.44 million, or 17%, to $2.10 million compared to the prior year quarter. The primary drivers for the decreased general and administrative expenses were decreased legal and professional costs.

Realized losses (gains) on derivative contracts. Realized losses on derivative contracts were $1.39 million in the current year quarter as compared to $1.23 million in realized gains in the prior year quarter. Realized losses represent cash settlements paid to the counterparty, while realized gains represent cash settlements paid to us from the counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized gains from the change in market value of open derivative contracts. Unrealized gains on derivative contracts were $21.57 million in the current year quarter as compared to $0.46 million in the prior year quarter. Unrealized gains are non-cash transactions that occur when the corresponding natural gas derivative contract asset or liability are marked to market at the end of each reporting period. The gain was a result of the increased estimated fair value of our natural gas derivative contracts resulting from decreased natural gas prices.

Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) decreased by $0.33 million to $1.12 million compared to the prior year quarter. Gross interest expense for the quarter was $1.24 million net of $0.12 million capitalized. Gross interest expense decreased 18.8% from the prior year quarter due to lower interest rates, while capitalized interest increased 54.9% from the prior year quarter due to an increase in capital expenditures from the prior year quarter.

Income tax (benefit) expense. Income tax expense was $10.60 million in the current quarter as compared to an expense of $0.45 million in the prior year quarter. The effective tax rate for the current quarter increased to 37.7% from 22.7% in the comparable prior year quarter. The increase in the effective tax rate from the prior year quarter was due to lower state income taxes in the prior year quarter resulting from a state apportionment factor shifting.

Discontinued operations. In September 2007, we discontinued the third party natural gas marketing business and second reportable segment that had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46(R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income due to the 100% minority interest to Shamrock Energy LLC. On January 1, 2007, we acquired Shamrock Energy LLC as a wholly owned subsidiary and the consolidation of this wholly owned subsidiary had an insignificant impact on our net income. As a result of exiting our third party marketing business, we are treating these activities as discontinued operations for all the periods presented.

Nine Months Ended September 30, 2008 compared with Nine Months Ended September 30, 2007

The following are selected items derived from our consolidated statement of operations and their percentage changes from the comparable period are presented below.

                                                            Nine Months Ended September 30,
                                                          2008              2007          Change
                                                                    (in thousands)
Gas sales                                              $    54,956       $    36,590          50 %
Lease operating expenses                               $    10,867       $    10,353           5 %
Compression expense                                    $     2,254       $     1,982          14 %
Transportation expense                                 $       923       $     2,051         -55 %
Production taxes                                       $     1,655       $       858          93 %
Depreciation, depletion and amortization               $     7,472       $     6,688          12 %
General and administrative                             $     7,478       $     7,042           6 %
Realized losses (gains) on derivative contracts        $     2,021       $    (2,524 )        NM
Unrealized (gains) losses from the change in market
value of open derivative contracts                     $      (820 )     $     2,249          NM
Interest expense, net of amounts capitalized           $    (3,538 )     $    (3,583 )        -1 %
Income tax benefit                                     $     8,135       $     1,850          NM
Discontinued operations                                $        -        $       166          NM

NM-Not Meaningful

Gas sales. Gas sales increased by $18.37 million, or 50%, to $54.96 million compared to the prior year period. The increase in gas sales was a result of both increased gas prices and production. Production increased 5% and average gas prices increased 43%, excluding hedging transactions. The $18.37 million increase in gas sales consisted of a $16.44 million increase in prices and a $1.93 million increase in production. The increase in production was principally attributable to the continued development activities at our Pond Creek and Gurnee fields.

Lease operating expenses. Lease operating expenses increased by $0.51 million, or 5%, to $10.87 million compared to the prior year period. The increase in lease operating expenses consisted of $0.54 million increase in production offset $0.03 million decrease in costs.

Compression expense. Compression expense increased by $0.27 million, or 14%, compared to the same period in the prior year. The increase in compression expense consisted of $0.10 million increase in production and $0.17 million increase in costs. The $0.17 million increase in costs was primarily comprised of an increase in repair and maintenance expenses for the compressors in our Pond Creek field.

Transportation expense. Transportation expenses decreased by $1.13 million, or 55%, to $0.92 million compared to the prior year period. The $1.13 million decrease was primarily comprised of a decrease in transportation expenses resulting from the commencement of transportation on our own system from the Pond Creek field and the temporary release of a portion of our firm capacity commitments related to our Pond Creek field.

. . .