### 10-K 1 d10k.htm FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2008

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Index to Financial Statements



# UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



# FORM 10-K

For the fiscal year ended December 31, 2008

or

For the transition period from to

Commission file number 000-52155



# GeoMet, Inc.

(Exact name of registrant as specified in its chart er)

Registrant’s telephone number, including area code

(713) 659-3855 Securities registered pursuant to Section 12(b) of the Act :

Securities registered pursuant to Section 12(g) of the Act

Title of Class

None

Indicate by check mark if the registrant is a well-known seasone d issuer, as defined in Rule 405 of the Securities

Act. Yes  No 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the

Act. Yes  No 

Indicate by check mark whether the registrant (1) has filed all r eports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for su ch shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requir ements for the past 90 days. Yes  No 

Indicate by check mark if disclosure of delinquent filers pursuant t o Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10

- K or any amendment to this Form 10

- K.   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SE CURITIES EXCHANGE ACT OF

1934

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF TH E SECURITIES EXCHANGE ACT OF

1934

Delaware 76

- 0662382

State or other jurisdiction of incorporation or organization (I.R.S. Employer Identification No.)

909 Fannin, Suite 1850, Houston, Texas 77010 77010

(Address of principal executive offices) (Zip Code)

Title of Each Class Name of Each Exchange on Which Registered Common stock, par value $0.001 per share NASDAQ Global Market 

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3/3/2010 http://www.sec.gov/Archives/edgar/data/1352302/000119312509052622/d10k.htmIndicate by check mark whether the registrant is a large accele rated filer, an accelerated filer, a non-accelerated file r, or a

smaller reporting company. See the definitions of “large accelerat ed filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  Accelerated filer  Non-accelerated filer  Smaller reporting company  (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company ( as defined in Rule 12b-2 of the Exchange Act). Yes  No 

The aggregate market value of common stock, par value $0.001 per sha re, held by non-affiliates (based upon the closing sales price on the NASDAQ Global Market on June 30, 2008), the last bus iness day of registrant’s most recently completed second fiscal quarter was approximately $372 million.

As of March 1, 2009, 39,049,684 shares of the registrant’s common stock, par value $0.001 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Information required by Part III, Items 10, 11, 12, 13 and 14, is i ncorporated by reference to portions of the registrant’s definitive proxy statement for its 2009 annual meeting of stockholders, which will be filed on or before April 30, 2009. 

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Index to Financial Statements

GeoMet, Inc.

Form 10-K

TABLE OF CONTENTS

2 PART I

Items 1 and 2. Business and Properties 8

Item 1A. Risk Factors 22

Item 1B. Unresolved Staff Comments 32

Item 3. Legal Proceedings 32

Item 4. Submission of Matters to a Vote of Security Holders 33

PART II

Item 5. Market for Registrant ’ s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity

Securities 34

Item 6. Selected Financial Data 36

Item 7. Management ’ s Discussion and Analysis of Financial Condition and Results of Opera tions 38

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 56

Item 8. Financial Statements and Supplementary Data 57

Item 9. Changes in and Disagreements with Accountants on Accounting and Financia l Disclosure 91

Item 9A. Controls and Procedures 91

Item 9B. Other Information 92

PART III

Item 10. Directors, Executive Officers and Corporate Governance 93

Item 11. Executive Compensation 93

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 93

Item 13. Certain Relationships and Related Transactions, and Director Independence 93

Item 14. Principal Accountant Fees and Services 93

PART IV

Item 15. Exhibits and Financial Statement Schedules 94 

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STA TEMENTS

Various statements in this annual report, including those that express a belief, expectation, or intention, as well as those
that are not statements of historical fact, are forward-looki ng statements. The forward-looking statements may include projections and estimates concerning the timing and success of spec ific projects and our future reserves, production, revenues, income, and capital spending. When we use the words “believe,” “intend, ” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, other similar expressions, or the statements that include those words are usually forward-looking statements.

The forward-looking statements contained in this annual report are l argely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on current known market conditions and other factors. Although we believe suc h estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and unc ertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccur ate. Management cautions all readers that the forwardlooking statements contained in this annual report are not guarantee s of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking ev ents and circumstances will occur. Actual results may diffe r materially from those anticipated or implied in the forward-lo oking statements due to the factors listed in the “Risk Factors” section and elsewhere in this annual report. All forward-looking sta tements speak only as of the date of this annual report. Other than as required under the securities laws, we do not int end to publicly update or revise any forward-looking statements
as a result of new information, future events or otherwise. Thes e cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingenci es and uncertainties relate to, among other matters, the following:

3 • our business strategy;

• our financial position;

• our cash flow and liquidity;

• difficult and adverse conditions in the global and domestic capital and credit markets;

• continued volatility and further deterioration of the capital and cred it markets;

• the impairment of financial institutions;

• changes in general economic conditions, including the performance of fi nancial markets and interest rates, which may affect our ability to raise capital and generate operating c ash flow;

• hedging decisions, including whether or not to hedge;

• our hedging activities may prevent us from benefiting from price incr eases and may expose us to other risks;

• actions of third party co

- owners of interests in properties in which we also own an intere st;

• fluctuations in interest rates and availability of capital;

• foreign currency fluctuations could negatively affect the profitabi lity of foreign operations;

• competition in the gas industry;

• declines in the prices we receive for our gas affecting our oper ating results, cash flows and credit capacity;

• uncertainties in estimating our gas reserves;

• replacing our gas reserves;

• uncertainties in exploring for and producing gas; 

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All references in this annual report to the “Company,” “GeoMet,” “we,” “us” or “our” are to GeoMet, Inc. and our wholly owned subsidiaries. Unless otherwise noted, all information i n this annual report relating to natural gas reserves and the estimated future net cash flows attributable to those reserv es is based on estimates prepared by independent engineers and

is net to our interest.

4 • the coalbeds and other strata from which we produce methane gas may contain impurities that may increase the cost of production;

• new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

• our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental r ules;

• other persons could have ownership rights in our advanced gas extraction te chniques which could force us to cease using those techniques or pay royalties;

• availability of drilling and production equipment and field service provid ers;

• disruptions, capacity constraints in, or other limitations on the pi peline systems which deliver our gas;

• costs associated with perfecting title for gas rights in some of our properties;

• our need to use unproven technologies to extract coalbed methane in some pr operties; and

• our ability to retain and attract qualified personnel;

• our joint venture arrangements;

• the outcomes of various legal proceedings, which are more fully des cribed in our reports filed under the Securities Exchange Act of 1934;

• the effects of government regulation and permitting and other lega l requirements;

• the effects of stringent federal and state employee health and safety regulations;

• the effects of proposals to regulate greenhouse gas emissions; and

• other factors discussed under “ Risk Factors. ” 

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GLOSSARY OF NATURAL GAS AND COALBED METHANE TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this document.

Additional drilling locations . Identified potential drilling locations on our existing acreage tha t are not included in our proved undeveloped reserves.

Appalachian Basin. A mountainous region in the eastern United States of America (“U.S.”), running from northern Alabama to Pennsylvania, and including parts of Georgia, South Carolina , North Carolina, Tennessee, Kentucky, Virginia, and all of West Virginia.

Bcf . Billion cubic feet of natural gas.

Btu or British Thermal Unit . The quantity of heat required to raise the temperature of one pound of water by one degree

Fahrenheit.

CBM . Coalbed methane.

CBM acres . Acreage under a lease that excludes oil, natural gas, and all other minerals other than CBM.

Coal seam. A single layer or stratum of coal.

Coal rank. Coal is a carbon rich rock derived from plant material accumula ted in peat swamps. With increasing depth of burial, the plant material undergoes coalification, releasing vola tile matter. The coal rank increases as the percentage of volatile mater (%VM) decreases. The generation of methane is a result of the thermal maturation or increasing rank of the coal. Coals targeted for CBM projects, from low rank to high ra nk, are lignite, sub-bituminous, high volatile bituminous,

medium volatile bituminous and low volatile bituminous coals. The ra nge of %VM associated with these coal ranks decrease from lignite at approximately 60%VM to low volatile bituminous coal s at approximately 15%VM.

Completion . The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage . The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well . A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantit ies such that proceeds from the sale of such production exceed production expenses and taxes.

Estimated proved reserves . The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be reco verable in future years from known reservoirs under existing economic and operating conditions.

Estimated proved undeveloped reserves . Estimated proved reserves that are expected to be recovered f rom new wells on undrilled acreage or from existing wells where a relatively ma jor expenditure is required for recompletion.

Exploratory well . A well drilled to find and produce oil or natural gas reserves no t classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

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Field . An area consisting of either a single reservoir or multiple res ervoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs. A non-GAAP performance measure, expressed in dollars per Mcf, commonly used throughout the oil and gas industry to measure the efficiency of a c ompany in adding new reserves. The finding and development cost measure is calculated for the three year time period by taking the sum of the cost incurred for exploration, development, and acquisition and dividing such amount by the total proved re serve additions. Management believes that this information is useful to an investor in evaluating GeoMet because it measures the efficiency of a company in adding proved reserves as compared to others in the industry. The cost and res erve information is derived directly from line items disclose d in the schedules of Capitalized Costs, Capitalized Costs Incurred, Natural Gas Reserves and Standardized Measure, which are all required to be disclosed by Statement of Financial Accounting Standa rds (“SFAS”) No. 69, Disclosures about Oil and Gas Producing Activities an amendment of FASB Statements 19, 25, 33, and 39 (“SFAS 69”).

Gas desorption test . A process to estimate the volume of natural gas adsorbed in a vol ume of coal (usually expressed as cubic feet per ton) by placing a sample of coal into a sealed canister and taking periodic measurements of gas desorbed, temperature and pressure for up to 90 days. The estimate of total gas adsorbed in the coal sample is the sum of: (i) the measurements of natural gas during the test period, corrected to standard temperature and pressure (the “measured natural gas”), (ii) the “lost natural gas,” which is calculated usi ng the elapsed time the sample desorbed before its placement int o the canister and the rate of desorption determined from the test period, and (iii) the “remaining natural gas,” which is determined by measuring the natural gas released while grinding the coal sam ple into a powder or which is calculated mathematically using the measurements from the test period.

Gas in-place . The total gas measured within any particular formation before any production. A portion of this total resource base is not economically recoverable. This portion varie s due to the formation’s reservoir characteristics such as pressure and permeability.

Gathering system. Pipelines and other equipment used to move natural gas from the we llhead to the trunk or the main transmission lines of a pipeline system.

Gross acres or gross wells . The total acres or wells, as the case may be, in which a working interest is owned.

Mcf . Thousand cubic feet of natural gas.

MMBtu . Million British thermal units.

MMcf . Million cubic feet of natural gas.

Net acres or net wells . The sum of the fractional working interests owned in gross acres or wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Productive well . A well that is found to be capable of producing hydrocarbons in suff icient quantities such that proceeds from the sale of such production exceed production expenses and taxes

.

PV-10 or present value of estimated future net revenues . An estimate of the present value of the estimated future ne t revenues from estimated proved natural gas reserves at a date i ndicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deduct ing any estimates of federal income taxes, a measure not in accordance with accounting principles generally accepted in the U .S. of

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America (“GAAP”), or a non-GAAP measure. The estimated fut ure net revenues are discounted at an annual rate of 10% in accordance with the practice of the Securities and Exchange Com mission (“SEC”), to determine their “present value.” The present value is shown to indicate the effect of time on the val ue of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of futur e net revenues are made using oil and natural gas prices and operat ing

costs at the date indicated and held constant for the life of the reserves.

Reservoir . A porous and permeable underground formation containing a natural accum ulation of producible oil and/or natural gas that is confined by impermeable rock or water barrie rs and is individual and separate from other reservoirs.

Shale . A well hardened, very fine to fine grained sedimentary rock. Sha le has ultra-low permeability and is formed from the compaction of silt, clay, or mud. Many shales contain a mixt ure of organic compounds called kerogen, which liberates natural gas during the maturation process of the shale. Gas withi n the shale can be stored onto the molecular surface of insoluble organic matter, trapped within the rock’s pore space or present within open fractures.

Shut-in . Stopping an oil or natural gas well from producing.

Undeveloped acreage . Lease acreage on which wells have not been drilled or complete d to a point that would permit the production of commercial quantities of oil or natural gas regardles s of whether or not such acreage contains estimated proved

reserves.

Working interest . The operating interest that gives the owner the right to drill, pr oduce and conduct operating activities on the property and receive a share of production.

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PART I

Items 1 and 2. Business and Properties

Overview

GeoMet, Inc. is an independent energy company primarily engaged in the e xploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM ”) and non-conventional shallow gas. We were originally founded as a consulting company to the coalbed methane industry i n 1985 and have been active as an operator and developer of coalbed methane properties since 1993. Our principal operati ons and producing properties are located in the Cahaba Basin in Alabama and the central Appalachian Basin in We st 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 December 31, 2008, we control a total of approximately 213,000 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 (emphasiz ing coalbed methane) while maximizing stockholder value through the efficient investment of capital to incre ase reserves, production, cash flow and earnings. We believe that substantial expertise and experience is required t o 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 operatio nal advantages compared to conventional gas production.

Our ability to successfully leverage our competitive strengt hs 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 a vailability of future debt and equity financing at attractive price s. 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 the global economy and in natural gas prices, which may affect both our cash flows and the value of our gas reserves, our a bility 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, ma ny 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.

Our proved natural gas reserves as of December 31, 2008 as estimat ed by DeGolyer and MacNaughton, independent petroleum engineers, totaled approximately 320 Bcf, a decrease of 8.6% from the approximate 350 Bcf of proved natural gas reserves at year-end 2007. Proved reserve estimates for the curr ent year were calculated using an unescalated natural gas price of $5.71 per MMBtu, adjusted for regional price differentials, as c ompared to an unescalated natural gas price in the prior year of $7.46 per MMBtu.

Our proved reserves were 100% from unconventional reservoirs, were 99% from coalbed methane and were 77% developed. The present value of proved reserves discounted at ten per cent was approximately $352 million at December 31, 2008 as compared to $663 million at year-end 2007. Although reserves dec lined from year-end 2007, before downward revisions and a property conveyance the Company replaced approximately 296% of its production in 2008. Downward revisions totaled approximately 42 Bcf of which approximately 13 Bc f resulted from lower natural gas prices. The remaining downward revisions were primarily in the Gurnee field in Alabama , resulting from production performance issues in certain

sectors of the field.

Approximately 57% of total year-end 2008 proved reserves are in the Gur nee field in Alabama and 41% are in the Pond Creek and Lasher fields in West Virginia and Virginia. The Pe ace River project is the first commercial coalbed methane project in British Columbia, Canada and there are no other simi lar producing

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analogies in the region. As a result, initial proved developed reser ves of only 4 Bcf were booked in 2008. Similarly, our Garden City project it is the first commercial Chattanooga Sha le project in Alabama, and only 2 Bcf of initial proved reserves

were booked in 2008.

Impact of Current Credit Market Conditions—We believe that we are well-positioned for the current credit market environment. We have a healthy balance sheet with over $2 million i n cash and a debt-to-book capital ratio of 38%. The borrowing base on our revolving credit facility was set at $140 mill ion on March 12, 2009. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. If not extended, our credit facility will mature in January 2011. As of December 31, 2008, we were in compliance with all of the covenants in the credit agreement. All of our lenders are currently funding our borrowing requests.

Impact of Decreasing Natural Gas Prices—We account for our gas properties using the full cost method and are required to impair a full cost pool when the net capitalized costs in t he pool exceed the discounted future net revenues of the proved reserves associated with the pool. Based upon the lower natural gas prices at December 31, 2008, we have reported a non-cash impairment to our U.S. full cost pool of $20 million, net of income t ax. Due to limited initial proved reserve bookings in the Peace River project we also reported a non-cash impairment to our Canadian full cost pool of $19 million, net of income tax.

If natural gas prices at March 31, 2009 are below those prices tha t existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas proper ties for the quarter then ended.

Our capital expenditure budget for 2009 will be funded from our estimated operating cash flows. If our cash flows are not sufficient to fund all of our estimated capital expenditures, we may reduce our capital budget. The amount and timing of our expenditures are subject to change based upon market conditions, res ults of expenditures and other factors. We routinely adjust our capital expenditure budget in response to changes in natural gas pric es, drilling and acquisition costs, cash flow, drilling results and borrowing base redeterminations under our revolving cre dit facility. Based on current gas price projections, we expect capital expenditures to be less than the $24.1 million capital budget we previously announced.

Characteristics of Coalbed Methane and Non-Conventional Shallow Gas

The source rock in conventional natural gas is usually different from the reservoir rock, while in coalbed methane the

coal seam serves as both the source rock and the reservoir rock. The storage mechanism is also different. Gas is stored in the pore or void space of the rock in conventional natural gas, but in coalbed methane, most, and frequently all, of the gas is stored by adsorption. Adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of coalbed methane is that the gas flow can be increased by reducing the reservoir pressure. Frequently the coalbed pore space,
which is in the form of cleats or fractures, is filled with w ater. The reservoir pressure is reduced by pumping out the water, releasing the methane from the molecular structure, which allow s the methane to flow through the cleat structure to the well bore. While a conventional natural gas well typically decreases in flow as the reservoir pressure is drawn down, a coalbed methane well will typically increase in production for up to five years from initial production depending on well spacing.

Coalbed methane and conventional natural gas both have methane as thei r major component. While conventional natural gas often has more complex hydrocarbon gases, coalbed methane rarely ha s more than 2% of the more complex hydrocarbons. In the eastern coal fields of the U.S., coalbed methane is ge nerally 98% to 99% pure methane and requires only dehydration of the gas to remove moisture to achieve pipeline quality. In the we stern coal fields of the U.S., it is also sometimes neces sary to strip out either carbon dioxide or nitrogen. Once coalbed methane ha s been produced, it is gathered, transported, marketed, and priced in the same manner as conventional natural gas.

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The content of gas within a coal seam is measured through gas desor ption testing. The ability to flow gas and water to the well bore in a coalbed methane well is determined by the fracture or cleat network in the coal. At shallow depths of less than 500 feet, these fractures often open enough to produce the fluids natura lly. At greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to pr ovide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened i n the coal and a slurry of fluid and sand proppant is pumped into the fractures so that the fractures remain open afte r the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

Areas of Operation

Cahaba Basin

We hold the development rights to approximately 44,000 net CBM acres t hroughout the Gurnee field in the Cahaba Basin of central Alabama. At December 31, 2008, approximately 57% of our estimated proved reserves, or 182.2 Bcf, were located in the Gurnee field, of which approximately 79% were classifi ed as proved developed. We are the operator and own a 100% working interest in the area. As of December 31, 2008, we had 246 product ive wells in the Gurnee field. Net daily sales of gas averaged approximately 6,123 Mcf for 2008.

We extract gas from six coal groups within the Pottsville coal formation at depths ranging from 700 feet to 3,400 feet. At these depths, overall seam thickness in this area averages a pproximately 50 feet of high volatile bituminous rank coal. A total of 33 core holes have been drilled and over 600 gas desorption tests have been conducted on our acreage to determine the gas

content of the coal and to define the coalbed methane resource under a substantial portion of the acreage in our leasehold position.

Our acreage is roughly evenly divided between a northern block, largely on the east side of the Cahaba River, and a southern block, largely on the west side of the river. The geology is generally more complex on the east side of the river with beds dipping from northwest to southeast. The geological setting west of the river tends to be less complex with more gently dipping beds. Most of the development to date in the Gurnee field has bee n on the east side of the river which is near existing
infrastructure. In 2008, we drilled two test wells on the less geologically complex west side of the river in the southern acrea ge block. Production results for 2008 were encouraging with early initial gas production inclines and average gas production rates higher than elsewhere in the field.

We have constructed and operate an approximate 38.5-mile pipeline from the Cahaba Basin to the Black Warrior River for the disposal of produced water under a permit issued by the Ala bama Department of Environmental Management. This pipeline has a maximum design capacity of approximately 45,000 barrels of water per day, but would require additional pump stations and looping a portion of the line in order to reach the maximum design capacity, if needed.

We control and operate a 17.3-mile, 12-inch high pressure steel pipel ine and a gas treatment and compression facility through which we gather, dehydrate, and compress our gas for delivery i nto the Southern Natural Gas pipeline system. As we control the gathering and delivery pipeline system, we incur no third pa rty costs to gather and deliver our gas to market. We believe we have adequate takeaway capacity to meet our future needs.

Garden City

The Garden City Chattanooga Shale prospect is located in north centr al Alabama. At December 31, 2008, we have approximately 72,000 net acres of leasehold. Approximately 1% of our est imated proved reserves, or 1.7 Bcf, were located within the field, all of which were classified as proved deve loped. As of December 31, 2008, we are the operator and own a 100% working interest in 3 productive wells. In 2009, we intend to seek a produced water disposal solution. We market the gas from this field to a local municipality through their pipelin e system. We believe we have adequate takeaway capacity to

meet our future needs.

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Pond Creek

In the Pond Creek field in the central Appalachian Basin of souther n West Virginia and southwestern Virginia, we have the rights to develop approximately 33,000 net CBM acres. At Dece mber 31, 2008, approximately 37% of our estimated proved reserves, or 117.7 Bcf, were located within the Pond Cree k field, of which approximately 77% were classified as proved developed. As of December 31, 2008, we are the operator and own a n average 99% working interest in 242 gross productive wells in the Pond Creek field. Net daily sales of gas averaged approximately 13,670 Mcf for 2008. In 2009, we

intend to drill 20 wells and related additional facilities in the Pond Creek field.

We extract gas from an average of 12 coal seams within the P ocahontas and New River coal formations at depths ranging from 430 feet to 2,400 feet. At these depths overall coal thickness in this area ranges from 10 to 30 feet of low-medium volatile bituminous rank Pennsylvanian Age coal. Prior mining activity revealed that these coal groups are gas rich. A total of 42 core holes have been drilled on and in the area of our acreage in the central Appalachian Basin and a geographically extensive gas desorption testing program has been conducted to determine the gas content of the coal and to define the coalbed methane resource under a substantial portion of our leasehold position.

CBM wells in the Pond Creek field produce comparatively lower le vels of water. Produced water is either used in our operations or injected into a disposal well that we own and operate . We believe this disposal well will meet our future water disposal requirements in the Pond Creek field.

Our gas from the Pond Creek field is gathered into our central d ehydration and compression facility and delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural G as, LLC (“ETNG”). In January 2007, we executed two longterm transportation agreements with ETNG which became effect ive when our pipeline was placed in service on April 1, 2007, with total maximum daily quantities of 15,000 MMBtu’s and 10,000 MMBtu’s and primary terms of 15 years and 10 years, respectively. We believe we have adequate takeaway capacity to meet our future needs.

Lasher

In the Lasher field in the central Appalachian Basin of souther n West Virginia, we have the rights to develop approximately 17,000 net CBM acres. At December 31, 2008, approximatel y 4% of our estimated proved reserves, or 14.1 Bcf, were located within the Lasher field, of which approximat ely 42% were classified as proved developed. As of December 31, 2008, we are the operator and own a 100% working intere st in 18 productive wells. Our gas from the Lasher field is delivered into the Columbia pipeline system for which we have firm transportation contracts continuing until October 31, 2011 with the right to extend these contracts, in five-yea r increments, at the maximum tariff rate. We believe we have adequate takeaway capacity to meet our future needs.

British Columbia

Our Peace River Project is comprised of approximately 25,000 net ac res along the Peace River near Hudson’s Hope, British Columbia. We have drilled 4 core holes targeting the me dium volatile bituminous rank Lower Cretaceous Gething coals. Multiple, mostly thin, coal seams, with an aggregate ave rage thickness of 52 feet, exist at depths from 1,000 to 3,000 feet. The Peace River project is the first commercial coa lbed methane project in British Columbia, Canada and there are no other similar producing analogies in the region. As a result, initia l proved developed reserves of only 3.8 Bcf were booked in 2008. At December 31, 2008, approximately 1% of our estimated proved reserves were located within the Peace River field, all of which were classified as proved developed. As of December 31, 2008, we own a 50% working interest in eight gross productive wells and we are the operator. Our gas from Peace Rive r is delivered on a Spectra Energy Corp pipeline. There are two primary delivery options, namely Westcoast Station 2 in Briti sh Columbia and at Sumas, located near the U.S. and Canadian border. We believe we have adequate takeaway capaci ty to meet our future needs.

11 

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Index to Financial Statements

Estimated Proved Reserves

The following table sets forth certain information with respect to our estimated proved reserves by field as of
December 31, 2008. Reserve volumes and values were determined under t he method prescribed by the SEC which requires the application of period-end prices and current costs held constant throug hout the projected reserve life. The reserve information
as of December 31, 2008 is based on estimates made in a reserve r eport prepared by DeGolyer and MacNaughton.

CBM- producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon
reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploration and development activities or acquisitions, our reserves and production, after an initial period of incline, are expected to decline. This decline rate, however, is slower than wha t is generally experienced with non-CBM wells. See “Risk

Factors” and the notes to our consolidated financial statements inc luded elsewhere in this annual report for a discussion of the risks inherent in CBM gas estimates and for certain additio nal information concerning the estimated proved reserves.

The weighted average prices of gas at December 31, 2008 used to esti mate U.S. and Canadian proved reserves and future net revenue were $5.84 per MMBtu and $5.20 per MMBtu, respectively, an d was calculated using the Henry Hub NYMEX cash price at December 31, 2008 of $5.71 per MMBtu of gas, adjust ed for price differentials at our sales points but excluding the effects of hedging.

12 Estimated Proved Reserves

Field Proved Developed Producing Proved

Developed NonProducing Proved

Undeveloped Total

Proved PV

- 10(1)
(MMcf) (MMcf) (MMcf) (MMcf) (In thousands) Central Appalachia:

Pond Creek field 90,643

— 27,015 117,657 $ 158,250

Lasher field 5,653 229 8,229 14,112 7,654

Alabama:

Gurnee field 120,504 23,711 37,949 182,164 180,130 Garden City field 730 939

— 1,669 1,662

White Oak Creek field 109

— — 109 412

Total

— U.S. 217,639 24,879 73,193 315,711 348,108

Canada:

Peace River field 3,020 798

— 3,818 3,841
Total Gas Properties 220,659 25,677 73,193 319,529 $ 351,949

(1) PV

- 10, a non

- GAAP measure, is our estimated present value of future net re venues from estimated proved reserves

before income taxes. We believe PV -10 to be an important measure for evaluating the relative signific ance of our CBM gas properties and that PV- 10 is widely used by professional analysts and investors in evaluating gas companies. Because many factors that are unique to each individual company impact the amoun t of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basi s. Management also uses PV-10 in evaluating acquisition candidates. PV-10 only differs from the standardized mea sure of discounted future net cash flows (“SMOG”), as calculated and presented in accordance with SFAS 69, in that SM OG takes into account the present value of income

taxes related to our future net cash flows. See “Selected F inancial Data—Reconciliation of Non-GAAP Financial

Measures. ” 

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Index to Financial Statements

Production and Operating Statistics

The following table presents certain information with respect to our production and operating data for the periods presented.

Productive Wells and Acreage

The following table sets forth our interest in undeveloped acreage, de veloped acreage and productive wells in which we own a working interest as of December 31, 2008. Gross represents th e total number of acres or wells in which we own a working interest. Net represents our proportionate working interes t resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and that are producing and wells capable of producing natural

gas.

Our material undeveloped leases are in Alabama, which includes t he Gurnee and Garden City fields, the Central Appalachian Basin, which includes the Pond Creek and Lasher fields, and Canada which includes the Peace River field. Generally, the undeveloped acreage expires on various dates from 2009 through 2013; however, the term of the undeveloped acreage can be extended by drilling and production operations. As to the Gurnee field, we have fulfilled drilling commitments on our largest lease, giving us the ability to postpone fur ther drilling until 2010. Otherwise, the remaining acreage either has expirations that occur from 2009 through 2013 or the lea ses can be extended by drilling and production operations or option payments.

13 Year Ended December 31,

2008 2007 2006
Gas: Net sales volume (Bcf) 7.5 7.1 6.2 Average natural gas sales price ($ per Mcf) $ 9.17 $ 6.97 $ 7.19 Average natural gas sales price ($ per Mcf) realized(1) $ 9.10 $ 7.52 $ 7.37 Total production expenses ($ per Mcf) $ 2.87 $ 2.86 $ 2.75 Expenses: ($ per Mcf) Lease operations expenses $ 1.98 $ 1.96 $ 1.86 Compression and transportation expenses $ 0.60 $ 0.73 $ 0.72

Production taxes $ 0.29 $ 0.17 $ 0.17 Depletion of gas properties $ 1.35 $ 1.24 $ 1.26

General and administrative $ 1.26 $ 1.30 $ 1.05

(1) Average realized price includes the effects of realized gai ns and losses on derivative contracts.

Productive Wells Developed Acres Undeveloped Acres

Area Gross Net Gross Net Gross Net
Gurnee 246.0 246.0 16,027 16,027 27,829 27,578 Garden City 3.0 3.0 240 240 82,513 72,062

Pond Creek 242.0 240.0 15,426 15,294 18,073 17,471

Lasher 18.0 18.0 1,407 1,407 15,270 15,251

Peace River 8.0 4.0 720 360 50,064 25,032

Other

— — — — 22,470 22,470

Total 517.0 511.0 33,820 33,328 216,219 179,864 

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Index to Financial Statements

Drilling Activity

The following table sets forth the number of completed gross explora tory and gross development wells drilled in the U.S. and Canada that we participated in for each of the last three fiscal years. The number of wells drilled refers to the num ber of wells commenced at any time during the respective year. Productive wells are producing wells and wells capable of production.

The following table sets forth, for each of the last three fi scal years, the number of completed net exploratory and net development wells drilled by us based on our proportionate working interest i n such wells.

Title to Properties

Our properties are subject to customary royalty interests, lie ns incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restricti ons. We do not believe that any of these burdens materially interfere with our use of the properties in the operati on of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although t itle to our properties is subject to encumbrances in certain ca ses, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

14 Gross
Exploratory Development
Well Activity (Gross)

— U.S. Productive Dry Total Productive Dry Total Year ended December 31, 2008 2

— 2 54

— 54
Year ended December 31, 2007 4

— 4 49

— 49
Year ended December 31, 2006 2

— 2 102

— 102

Exploratory Development
Well Activity (Gross)

— Canada Productive Dry Total Productive Dry Total Year ended December 31, 2008

— — — 5

— 5
Year ended December 31, 2007 1

— 1

— — — Year ended December 31, 2006 3

— 3

— — —

Net
Exploratory Development
Well Activity (Net)

— U.S. Productive Dry Total Productive Dry Total Year ended December 31, 2008 2.0

— 2.0 54.0

— 54.0
Year ended December 31, 2007 4.0

— 4.0 47.0

— 47.0 Year ended December 31, 2006 2.0

— 2.0 102.0

— 102.0

Exploratory Development
Well Activity (Net)

— Canada Productive Dry Total Productive Dry Total Year ended December 31, 2008

— — — 2.5

— 2.5
Year ended December 31, 2007 0.5

— 0.5

— — — Year ended December 31, 2006 1.5

— 1.5

— — — 

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Index to Financial Statements

Strategy

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 intend to focus on the following strategies:

Competitive Strengths

We primarily explore for, develop, and produce CBM and non-conventional shallow gas. 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 g eologic and production characteristics of coalbed methane and nonconventional shallow gas offer significant operational advantages com pared to conventional gas production, including:

15 • Focus primarily on coalbed methane and non

- conventional shallow gas to exploit our substantial expertise and experience.

• Maximize present value in existing development projects and expand into adjacent areas to leverage our information, knowledge and infrastructure.

• Develop new large scale projects, maintain operational control a nd reduce costs through economies of scale.

• Maintain financial discipline.

• Production Rates . Unlike conventional and unconventional natural gas production, which t ypically declines after initial production is established, production from CBM wells typic ally increases for the first few years of their productive lives although eventual peak rates are often lower than thos e of typical conventional gas wells. CBM wells also generally decline at a shallow rate relative to typical conventional gas wells.

• Low Geologic Risks . Most CBM areas are located in known coal basins where the coal resource has been evaluated for coal mining. These areas have extensive existing geologic infor mation databases. The drilling of new coreholes and a limited number of production test wells reduces the geologic risk prior to committing large development expenditures.

• Low Costs . Our costs of finding and developing coalbed methane tend to be low compa red to industry averages because our well costs are generally lower due to the relatively shallow depths of gas -bearing coal seams underlying our projects. Coal seams possess the ability to store significant ly more gas volumetrically at shallow depths than conventional reservoirs. In the early stages of a CBM project de velopment per unit operating costs are higher because natural gas production per well is initially low and many of our costs are fixed. As average production per well from a project increases over time and economies of scale are realized, the per unit operating costs typically decrease. Over the life of a project, we believe our average per unit costs of finding, developing and producing natural gas will be lower than those of many conventional and unconventional n atural gas industry projects.

• Long

- lived Reserves . Because CBM wells typically have inclining production rates ear ly in their lives and low decline rates thereafter, CBM projects typically result in a reserve life that is significantly longer than many types of conventional gas production.

• Highly Experienced Team of CBM Professionals . Our 18

- person CBM management, professional, and project management team has an average of more than 18 years of CBM exper ience and has participated in the drilling and operation of more than 2,700 CBM wells worldwide since 1977.

• Large Inventory of Organic Growth Opportunities . Our extensive undeveloped acreage position provides us with an additional 582 net drilling locations. 

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Index to Financial Statements

Changes in Global Economy

The global financial and capital markets have been experiencing extr eme volatility and disruption, including the failures of financial services companies and the related liquidity cris is. The sharp economic downturn during 2008 was prompted by a combination of factors: tight credit markets, speculation and fear regarding the health of the U.S. and global financial systems, and weaker economic activity including a global economic recession.

Natural gas exploration companies are capital intensive and, as suc h, rely on the credit markets for liquidity and for the financing of natural gas exploration. In addition, economic recessions hi storically result in lower market demand, resulting in lower prices. A prolonged period of low gas prices may have a materi al impact on our cash generation, although in the near term this would be mitigated by our hedged position of our natural gas produc tion. Although we expect to meet our near term liquidity needs with our working capital on hand, we will continue to need further funding to achieve our business objectives. If the disruptions in the global financial and capital markets continue, debt or equity financing may not be available to us on acceptable terms, if at all. If we are unable to fund future ope rations by way of financing, including public or private offerings of equity or debt securities, our business, financial condition and results of operations will be adversely impacted.

Our operations are affected by local, national and worldwide econom ic conditions. The consequences of a prolonged recession could include a lower level of economic activity and uncerta inty regarding energy prices and the capital and commodity markets. A lower level of economic activity could result in a decline in energy consumption, which could adversely affect our revenues and future growth. Instability in the f inancial markets, as a result of recession or otherwise, al so could affect the cost of capital and our ability to raise capital.

Competition

Our operations primarily compete regionally in the U.S. and Canada. Competition throughout the U.S. and Canada is regionalized. We believe that the gas market is generally highl y fragmented and not dominated by any single producer except in the immediate area of our Virginia development operations, wher e we believe there is one dominate producer that controls a substantial portion of the market. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition wit hin our market is based primarily on price and the proximity of gas fields to customers.

Seasonality of Business

Weather conditions affect the demand for and prices of natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Governmental, State and Local Regulations

Our coalbed methane exploration and production operations are subject to significant federal, state, and local laws and regulations governing the gathering and transportation of our gas product ion across state and federal boundaries. The following is a summary of some of the existing regulations to which our operations are subject.

16 • Track Record of Success in Identifying and Exploiting Large Underdevelope d Resource Plays . We pursue those projects that leverage our CBM expertise to exploit underdeveloped res ource potential and shallow gas. We have a history of developing large scale projects in multiple basins with low finding and development costs. 

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Index to Financial Statements

Regulation by the Federal Energy Regulatory Commission (“FERC”) of Interstate Natural Gas Pipelines . We do not own any interstate natural gas pipelines, so the Federal Energy Re gulatory Commission, or the FERC, does not directly regulate any of our operations. However, the FERC’s regulation influenc es certain aspects of our business and the market for our products. In general, the FERC has authority over natural gas co mpanies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this ap proach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natura l gas transportation capacity.

Intrastate Regulation of Natural Gas Transportation Pipelines . We own a pipeline in Alabama that provides intrastate natural gas transportation as defined by the Alabama Public Service Commission (APSC). The APSC regulates gas pipelines that transport gas on an intrastate basis in situations where t he gas has been cleaned and pressurized to the point that it is ready for sale. All pipeline systems in Alabama must be constructed, operated and maintained to be in compliance with the defined federal minimum safety standards. The APSC has not enacted its own regulations relating to pipeline safety. Instead, it enforces the U.S. Department of Transportation Office of Pipeli ne Safety Regulations, including as to reporting, design, construction, and operating requirements of the pipeline. We are inspe cted annually by the APSC to ensure we are in compliance with the regulations.

Gathering Pipeline Regulation . Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. We own an intrastate natural gas pipel ine that we believe would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not s ubject to the FERC’s jurisdiction. However, the distinction betw een the FERC-regulated transmission services and federally unreg ulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.

In the states in which we operate, regulation of intrastate gathe ring facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take re quirement and complaint based rate regulation. For example, we are subject to state ratable take and common purchas er statutes. Ratable take statutes generally require gathere rs to take, without undue discrimination, natural gas production that m ay be tendered to the gatherer for handling. In certain circumstances, such laws will apply even to gatherers like us t hat do not provide third party, fee-based gathering service and may require us to provide such third party service at a regulate d rate. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of suppl y or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of ga thering facilities to decide with whom we contract to purchase or transport natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that the FERC has taken a less stringent approach to regulation of the gathering activit ies of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unr egulated

17 • the certification and construction of new facilities;

• the extension or abandonment of services and facilities;

• the maintenance of accounts and records;

• the acquisition and disposition of facilities;

• the initiation and discontinuation of services; and

• various other matters. 

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Index to Financial Statements

affiliates. Our gathering operations could be adversely affecte d should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering opera tions also may be or become subject to safety and operational regulations relating to the design, installation, testing, construct ion, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to thes e matters are considered or adopted from time to time. We c annot predict what effect, if any, such changes might have on our operations , but the industry could be required to incur additional capital expenditures and increased costs depending on future legislati ve and regulatory changes.

Sales of Natural Gas . The price at which we sell natural gas currently is not subj ect to federal regulation and, for the most part, is not subject to state regulation. Our natural gas sal es are affected by the availability, terms, and cost of pipe line transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas tra nsmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrasta te transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote com petition among the various sectors of the natural gas industry, and these initiatives generally reflect more light hande d regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas operations, and we note that some o f the FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transpor tation service on interstate pipelines. We do not believe that we will be affected by any such FERC action materially differentl y than other sellers of natural gas with whom we compete.

Virginia Regulation. The Virginia Supreme Court has stated that the grant of coal ri ghts only does not include rights to coalbed methane absent an express grant of coalbed methane, natur al gases, or minerals in general. The situation may be different if there is any expression in the severance deed indica ting more than mere coal is conveyed. Virginia courts have also found that the owner of the coalbed methane did not have the right to fra cture the coal in order to retrieve the coalbed methane and that the coal operator had the right to ventilate the coalbed met hane in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties. In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of coalbed methane by an operator in those instances where the owner of the coalbed meth ane has not leased it to the operator or in situations where there are conflicting claims of ownership of the coalbed methane. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The V irginia Gas and Oil Board does not make ownership

decisions.

West Virginia Regulation . The West Virginia’s Supreme Court has held that, in a conventi onal oil and gas lease executed prior to the inception of widespread public knowledge regarding coalbed me thane operations, the oil and gas lessee did not acquire the right to produce coalbed methane. As of December 31, 200 8, the West Virginia courts have not clarified who owns coalbed methane in West Virginia. Therefore, the ownership of coalbe d methane is an open question in West Virginia. West Virginia has enacted a law, the Coalbed Methane Wells and Unit s Act (the “West Virginia Act”), regulating the commercia l recovery and marketing of coalbed methane. Although the West Virginia Act does not specify who owns, or has the right to exploit, coalbed methane in West Virginia and instead refers owners hip disputes to judicial resolution, it contains provisions similar to Virginia’s pooling law. Under the pooling provisions of the W est Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia Coalbed Methane Review Board to obtain authority to produce coalbed methane from pooled acreage. Owners and claimants of coalbed methane interests who have not consented to the drilling are afforded certain elective forms of participat ion in the drilling (e.g., royalty or owner) but their consent is not required to obtain a pooling order authorizing the production of coalbed met hane by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where ti tle to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in differen t persons, the operator of a coalbed methane well permitted, drilled and

18 

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Index to Financial Statements

completed under color of title to the coalbed methane from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass rela ting to the drilling and commercial production of coalbed methane

from that well.

Alabama Regulation . In 1983 the State Oil & Gas Board of Alabama, in cooperation w ith the coalbed methane operator’s group, established the first rules for coalbed methane drilling, deve lopment and production operations. The evolution of Alabama coalbed methane permits is a continuing process. The coalbe d methane industry in Alabama has a long history of working closely with Alabama Department of Environmental Management and other government agencies on the continual improvement of coalbed methane permits.

Canadian Governmental Regulation. Our operations in Canada are subject to regulation by the National Ener gy Board (“NEB”) and provincial agencies in Canada. These agencies have j urisdiction similar to the FERC for regulation. Business in Western Canada is regulated by the NEB pursuant to a framework for l ight-handed regulation under which the NEB acts on a complaints basis. However, the natural gas industry in Canada rema ins subject to extensive controls and regulations imposable by various levels of government. We do not expect that any of these control s or regulations will affect our operations in a manner materially different than they would affect other natural gas industry participants of similar size.

In addition to federal regulation, each province has legislation and r egulations that govern land tenure, royalties, production rates, environmental protection and other matters. The r oyalty regime is a significant factor in the profitability natural gas production. Royalties payable on production from lands other th an government lands are determined by negotiations between the mineral owner and the lessee. Royalties on government land are determined by government regulation and are generally calculated as a percentage of the val ue of gross production, and the rate of royalties payable generally depends upon prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

NAFTA . The North American Free Trade Agreement among the governments of Canada, the U.S. and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada-U.S. Free Trade Agreement. Subject to the General Agreement on Tarif fs and Trade, Canada continues to remain free to determine whether exports of energy resources to the U.S. or Mexico will be allowed, so long as any export restrictions do not reduce the proportion of energy resources exported relative to total supply (based upon the proportion prevailing in the most recent 36- month period or another representative period agreed upon by the parties ), impose an export price higher than the domestic price (subject to an exception that applies to some measures th at only restrict the value of exports), or disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, with some limited exceptions.

Environmental Regulations

Our coalbed methane exploration and production operations are subject to significant federal, state, local, and Canadian environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, q uantities, and concentrations of various substances that can be released into the environment as a result of natural gas dril ling, production, and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from historic al and on- going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface st rata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their law s, regulations and permits, and violations are subject to injunction, as well as administrative, civil and even criminal pe nalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future could have a material adverse impact on our operations.

19 

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We believe that we are in substantial compliance with existin g applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations. As a general matte r, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue . To date, we have not been required to expend extraordinary resources in order to satisfy existing applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material . Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area or in substantial liabilities to third parties. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilit ies or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the existing environmental la ws, rules and regulations to which our operations in the U.S. are subject. Our operations in Canada are subject to similar Canadian requirements.

Comprehensive Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superf und law, imposes strict, joint and several liability without regard to fault or legality of conduct, on persons who are conside red to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or opera tor of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous subs tance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous subst ances that have been released into the environment, for damages to natural resources, and for the costs of certain heal th studies. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury a nd property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA current ly excludes “petroleum” and “natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel” fr om the definition of “hazardous substance,” our operations may generate materials that are subject to regulation as hazar dous substances under CERCLA.

CERCLA may require payment for cleanup of certain abandoned waste di sposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicabl e at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its pr oportional share of cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the U.S. Environmental Protection Agency and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of f inancial liability under these laws involves inherent

uncertainties.

Resource Conservation and Recovery Act . The Resource Conservation and Recovery Act, or RCRA, and compar able state programs regulate the management, treatment, storage, and di sposal of hazardous and non-hazardous solid wastes. Our operations generate wastes, including hazardous wastes that are s ubject to RCRA and comparable state laws. We believe that these operations are currently complying in all material respe cts with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil exploration and product ion wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the fut ure, which could have a significant impact on us as well as on the oil and natural gas industry, in general.

Water Discharges . Our operations are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulatio ns impose detailed requirements and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the U.S., including wetlands. Under the CWA and OPA, any unpermitted release of pol lutants from operations could cause us to become subject to the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, i n the event that spills or releases of produced water from CBM production operations were

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to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spil l response plans may also have to be prepared.

Our CBM exploration and production operations produce substantial volum es of water that must be disposed of in compliance with requirements of the CWA, Safe Drinking Water A ct, or SDWA, or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to surface streams, or in evaporation ponds. Discharge of produced water to surface stream s and other bodies of water must be authorized in advance pursuant to permits issued under the CWA, and disposal of produced wat er in underground injection wells must be authorized in advance pursuant to permits issued under the SDWA. To date, we be lieve that all necessary surface discharge or disposal well permits have been obtained and that the produced water has be en disposed in substantial compliance with such permits and applicable laws.

Air Emissions . The Clean Air Act, or CAA, and comparable state laws and re gulations govern emissions of various air pollutants through the issuance of permits and the imposition of other r equirements. Air emissions from some equipment used in our operations, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regula ted by permits issued by state regulatory agencies. To date, we

believe that no unusual difficulties have been encountered in obtai ning air permits, and we believe that our operations are in substantial compliance with the CAA and analogous state and local la ws and regulations. However, in the future, we may be required to incur capital expenditures or increased operating costs to comply with air emission-related requirements.

Other Laws and Regulations . Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Fur thermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land r esources occasioned by drilling and production operations and the products derived therefrom, and are often based on negligence, trespass, nuisance, strict liability or fraud.

In addition, our operations may in the future be subject to the regulat ion of greenhouse gas emissions. Numerous countries, including Canada but not the U.S., are participants in the Kyoto Protocol to the United Nations Framework Convention on Climate Change. Participating countries are required t o implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases that a re suspected of contributing to global warming. Although the U.S. is not participating in the Protocol, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have alre ady adopted legislation addressing greenhouse gas emissions from certain greenhouse gas emission sources, primarily power pla nts. The oil and gas exploration and production industry is a direct source of certain greenhouse gas emissions, namely carbon di oxide and methane, and future restrictions on such emissions could impact our future operations. Our operations in the U .S. currently are not adversely impacted by current state and local climate change initiatives. Our Canadian operations are subject to the Protocol, but implementation of the Protocol’s greenhouse gas emission reduction requirements in British Columbia ar e not presently expected to have a material adverse effect on our operations. However, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions may impact our business.

Canadian Environmental Regulation. The natural gas industry is governed by environmental regulation under C anadian federal and provincial laws, rules and regulations, which restr ict and prohibit the release or emission and regulate the storage and transportation of various substances produced or utilized in associ ation with natural gas industry operations. In addition, applicable environmental laws require that well and facility site s be abandoned and reclaimed, to the satisfaction of provincial
authorities, in order to remediate these sites to near natural conditions. Also, environmental laws may impose upon “responsible persons” remediation obligations on property designated as a contaminated site. Responsible persons include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any

present or past

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owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures. A breach of environmental laws may result in the imposition of fi nes and penalties and suspension of production, in addition

to the costs of abandonment and reclamation.

Industry Segment and Geographic Information

We operate in one industry, which is the exploration, development and p roduction of natural gas. Our operational activities are conducted in the U.S. and Canada with only the U. S. currently having revenue generating operating results.

Employees

At December 31, 2008, we had 89 full-time employees and two full-t ime contractors. None of our employees are represented by a labor union or covered by any collective bargaining agre ement. We believe that our relations with our employees are satisfactory.

Corporate Offices

Our corporate headquarters are located at 909 Fannin, Suite 1850, Hous ton, Texas 77010. Our technical and operational headquarters are located at 5336 Stadium Trace Parkway, Suite 20 6, Birmingham, Alabama 35244.

Access to Company Reports

We file periodic reports, proxy statements and other information wi th the SEC in accordance with the requirements of the Exchange Act of 1934, as amended, or the Securities Exchange Act of 1934, as amended. We make our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to such reports available free of charge through our corporate website at www.geometinc.com as soon as reasonably practicable after we file any such report with the SEC. In addition, information related to the following it ems, among other information, can be found on our website: our press releases, our corporate governance guidelines, our corporate code of business ethics and conduct, our audit committee charter, our compensation committee charter and our nomi nating, corporate governance and ethics committee charter. You may also read and copy any document we file with the S EC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operati on of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. In addition, the SEC maintains an internet sit e that contains our reports, proxy and information statements, and our other filings which are also available to the public over the internet at the SEC’s website at www.sec.gov

.

Item 1A. Risk Factors

If any of the following risks develop into actual events, our business, financial condition, results of operations, cash flows, strategies and prospects could be materially adversel y affected.

Natural gas prices are volatile, and a decline primarily in n atural gas prices would significantly affect our financial res ults and impede our growth.

Our revenue, profitability, and cash flow depend upon the prices and dema nd for natural gas. The market for natural gas is very volatile and even relatively modest drops in prices can signi ficantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our c ontrol, such as:

22 • the domestic and foreign supply of natural gas;

• the price of foreign imports; 

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Many of these factors are beyond our control. Because all of our est imated proved reserves as of December 31, 2008 were natural gas reserves, our financial results are sensit ive to movements in natural gas prices. Recent natural gas price s have been extremely volatile and we expect this volatility to continue. For example, from January 1, 2008 to February, 10, 2009, the NYMEX natural gas spot price ranged from a high of $13.54 per MMBtu t o a low of $4.48 per MMBtu.

The results of higher investment in the exploration for and production of gas and oil and other factors, such as global economic and financial conditions discussed below, may cause the pric e of gas to fall. Lower natural gas prices may not only decrease our revenues on a per Mcf basis, but also may reduce the amount of natural gas that we can produce economically. This may result in substantial downward adjustments to our estima ted proved reserves and could have a material adverse effect on our financial condition, results of operations and cash flow. If there are substantial downward adjustments to our estimated proved reserves or if our estimates of development costs increas e, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non -cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairme nt tests on our assets whenever events or changes in

circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the car ry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

If natural gas prices decline significantly for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive
terms, all of which can affect the value of our common stock.

The deterioration of global economic and financial conditions and an prolonged decline in the price of natural gas may materially and adversely affect our business, financial condition and results of operations.

Our business, financial condition and results of operations are a ffected by conditions in the capital markets and the economy generally. The recent global financial crisis and worldwide economic slowdown could lead to prolonged national or global recession, which would likely reduce domestic and foreign demand f or natural gas and result in lower natural gas prices. Substantial decreases in natural gas prices could have a material adverse effect on our business, financial condition and results of operations, could limit our access to liquidity and cre dit and could hinder our ability to fund our development program, which would limit our ability to grow or replace our proved reserves, and, eventually, our production levels.

If credit and capital markets worsen, then we may not be able to obtain funding under our current revolving credit facility or fund on acceptable terms. The inability to obtain funding coul d deter us from meeting our future capital needs to fund our development program.

Capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, th e availability of funds from those markets has diminished substantially. Further, arising from concerns about the stabilit y of financial markets

23 • overall domestic and global economic conditions;

• the consumption pattern of industrial consumers, electricity gener ators, and residential users;

• weather conditions;

• technological advances affecting energy consumption;

• domestic and foreign governmental regulations;

• proximity and capacity of gas pipelines and other transportation fac ilities; and

• the price and availability of alternative fuels. 

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generally and the solvency of counterparties specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rate spreads, enacted tighter lendi ng standards or altogether ceased to provide funding to borrowers. Additionally, even if lenders continue and are able to provide funding to borrowers, interest rates may rise in the future and therefore increase the cost of outstanding borrowings that w e may incur under our revolving credit facility.

Moreover, we may be unable to obtain adequate funding under our current cre dit facility. First, our lenders may be unwilling or unable to meet their funding commitments. Second, our borr owing base under our credit facility is redetermined semiannually. Our lenders completed their latest redetermination on March 12, 2009 and set our borrowing base at $140 million. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points . Our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors. If natura l gas prices significantly decline for an extended period of time, our lenders could redetermine our borrowing base by evaluating our reserves in light of such lower natural gas prices. Such determination could result in a negative revision to the value of our proved reserves and a reduction of our borrowing

base.

As a result of these capital and credit market conditions, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not a vailable when needed, or is available only on unfavorable terms, we may not be able to meet our obligations as they come due or be requi red to post collateral to support our obligations, or we may not be able to implement our development program, grow our existing bus iness through acquisitions, or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

Changes in tax laws may impair our results of operations and adve rsely impact the value of our common stock.

Under current federal tax laws, we are entitled to certain d eductions relating to our operations, including deductions for intangible drilling costs, manufacturing tax deductions and percentag e depletion deductions. The President’s budget for the fiscal year 2010 outlines proposals to eliminate several oil and gas federal income tax incentives, including the repeal of t he manufacturing tax deduction and percentage depletion allowance for oil and natural gas and expensing of intangible drilling costs. It is not possible at this time to predict how legislat ion or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regul ations could adversely affect the amount of our taxable income or loss and could have a negative impact on the value of our common stock.

We may incur substantial costs to comply with, and demand f or our products may be reduced by, climate change legislation and regulatory initiatives.

The United States Congress is considering legislation to reduce em issions of greenhouse gases and more than one- third of the states, either individually or through multi-state initiative s, already have begun implementing legal measures to reduce emissions of greenhouse gases. In addition, the Environmental Protect ion Agency has announced possible future regulation of greenhouse gas emissions under the Clean Air Act. Depending on the na ture of potential regulations and legislation, such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on our business or demand for the natural gas we produce

.

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We face uncertainties in estimating proved gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our re serves.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. In addition, in the early stages of a coalbed methane project, it is difficult to pr edict the production curve of a coalbed methane field. The estimated production profile of a field in the early stage of opera tions may vary significantly from the actual production profile as the field matures. As a result, quantities of estimated p roved reserves, projections of future production rates, and the ti ming of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Al so, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimate s of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the c lassifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over t ime to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve

estimates.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base th e estimated discounted future net cash flows from our estimated proved reserves on current prices and costs. However, actual fut ure net cash flows from our gas properties also will be affec ted by factors such as:

The timing of both our production and our incurrence of expenses in connecti on with the development and production of natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we u se when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in ef fect from time to time and risks associated with us or the natural gas industry in general.

Our results of operations could be adversely affected as a resul t of non-cash impairments.

At December 31, 2008, we recorded a full cost ceiling impairmen t of approximately $50.7 million. The full cost ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. Future adverse changes to any of these factors could lead to an impairment of all or a p ortion of our full cost pool in future periods which could significantly reduce earnings during the period in which the impairme nt occurs, and would result in a corresponding reduction to the full cost pool and stockholders’ equity.

Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations, and cash fl ows.

Producing natural gas reservoirs are typically characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production gener ally declines at a shallow rate after initial increases i n production which result as a consequence of the pressuring process. The rate of decline from our existing wells may change in
a manner different than we have estimated. Thus, our future natura l gas

25 • geological conditions;

• changes in governmental regulations and taxation;

• assumptions governing future prices;

• the amount and timing of actual production;

• future gas prices and operating costs; and

• capital costs of drilling new wells. 

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reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or ac quiring additional recoverable reserves. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs.

Currently the vast majority of our producing properties are locat ed in two counties in Alabama, one county in West Virginia, and one county in Virginia, making us vulnerable t o risks associated with having our production concentrated in a few areas.

The vast majority of our producing properties are geographically concentr ated in two counties in Alabama, one county in West Virginia, and one county in Virginia. As a result of this conc entration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disaster s, interruption of transportation of natural gas produced from the wells in these basins, or other events which impact these areas.

Our ability to sell the gas we produce depends in substantial part on the availability and capacity of pipeline systems owned and operated by third parties. Operational impediments on these pi peline systems may hinder our access to natural gas markets or delay our production.

The availability of a ready market for our natural gas production de pends on a number of factors, including the proximity of our reserves to pipelines, capacity constraints on pipelines, and disruption of transportation of natural gas through pipelines. We transport the natural gas we produce principally through pipelines o wned by third parties. If we cannot access these thirdparty pipelines, or if transportation of gas through any of these pipeli nes is disrupted, we may be required to shut in or curtail production from some of our wells or seek alternate methods of tra nsportation of our production. If any of these were to occur,
our revenues would be reduced, which would in turn have a material adve rse effect on our financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

As of December 31, 2008, we own leasehold interests in approximate ly 72,000 net acres in areas we believe are prospective for the Chattanooga Shale. A large portion of the acreag e is not currently held by production. Unless production in paying quantities is established on units containing these leases duri ng their terms, these leases will expire. If our leases e xpire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, inc luding drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, ava ilability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

We may be unable to obtain adequate acreage to develop additional large-s cale projects.

To achieve economies of scale and produce gas economically, we need to acquire large acreage positions to reduce our per unit costs. There are a limited number of coalbed formations in North America that we believe are favorable for CBM development. We face competition when acquiring additional acreage, a nd we may be unable to find or acquire additional acreage at prices that are acceptable to us.

Our exploration and development activities may not be commercia lly successful.

The exploration for and production of natural gas involves numerous high risks. The cost of drilling, completing, and operating wells for coalbed methane or other gas is often uncerta in, and a number of factors can delay or prevent drilling operations or production, including:

26 • unexpected drilling conditions; 

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Our future drilling activities may not be successful, and our drilli ng success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding reser ves and revenues.

We will require additional capital to fund our future activit ies. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a declin e in reserves and production.

Historically, we have financed our business plan and operations prima rily with internally generated cash flow, bank borrowings, and issuances of common stock. If our revenues decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we m ay have limited ability to obtain the capital necessary to sust ain our operations at current levels. We may, from time to time, ne ed to seek additional financing. Our revolving credit facility contains covenants prohibiting our ability to incur additional indebtedness w ithout the consent of the lenders. There can be no assurance that our lenders will provide this consent or as to the avai lability or terms of any additional financing. If we incur additional debt, the related risks that we now face could intensify . A higher level of debt also increases the risk that we may default on our debt obligations. Our level of debt affects our opera tions in several important ways, including the following:

Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could resul t in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible los s of properties and a decline in our natural gas

reserves.

27 • title problems;

• pressure or irregularities in geologic formations;

• equipment failures or repairs;

• fires or other accidents;

• adverse weather conditions;

• reductions in natural gas prices;

• pipeline ruptures;

• regulatory permitting problems;

• inability to dispose of produced water;

• legal issues; and

• unavailability or high cost of drilling rigs, other field service s, and equipment.

• a portion of our cash flow from operations is used to pay interest on borrowings;

• a high level of debt may impair our ability to obtain additional financi ng in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

• a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and

• any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to

increases in interest rates. 

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Our revolving credit facility contains a number of financial an d other covenants, and our obligations under the revolving credit facility are secured by substantially all of our assets . If we are unable to comply with these covenants, our lende rs could accelerate the repayment of our indebtedness.

Our revolving credit facility subjects us to a number of covenants that impose restrictions on us, including our ability to
incur indebtedness and liens, make loans and investments, sell ass ets, engage in mergers, consolidations and acquisitions, enter into transactions with affiliates, or pay dividends. We are als o required by the terms of our revolving credit facility to comply with certain financial ratios. Our revolving credit facility a lso provides for periodic redeterminations of our borrowing base, which may affect our borrowing capacity. Our revolving credit fa cility is secured by a lien on substantially all of our assets, including equity interests in our subsidiaries.

A breach of any of the covenants imposed on us by the terms of our r evolving credit facility, including the financial
covenants, could result in a default under such indebtedness. In the event of a default, the lenders could terminate their commitments to us, and they could accelerate the repayment of all of our indebtedness. In such case, we may not have sufficient funds to pay the total amount of accelerated obligations , and our lenders could proceed against the collateral securing the revolving credit facility. Any acceleration in the re payment of our indebtedness or related foreclosure could adversely affect our business.

In addition, the borrowing base under our revolving credit facility is r edetermined semi-annually and may be redetermined at other times upon request by the lenders under certa in circumstances. Redeterminations are based upon a number of factors, including natural gas prices and reserve levels

.

Our revolving credit facility expires in January 2011.

We operate in a highly competitive environment and many of our competitors have greater resources than we do.

The gas industry is intensely competitive and we compete with c ompanies from various regions of the U.S. and Canada and may compete with foreign suppliers for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our operating r esults and financial position may be adversely

affected.

In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our abilit y to acquire additional properties and to discover new reserves also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

Our ability to produce natural gas may be hampered by the water present in the formation, which could affect our profitability.

Unlike conventional natural gas production, coalbeds and shales frequently conta in brine water that must be removed in order for the gas to desorb from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of

water from the coal seam will determine whether or not we ca n produce gas in commercial quantities. The cost of water disposal may affect our profitability.

We may face unanticipated water disposal costs.

Where water produced from our projects fails to meet the quality r equirements of applicable regulatory agencies or our wells produce water in excess of the applicable volumetric permi t limit, we may have to shut in wells, reduce drilling activities, or upgrade facilities. The costs to dispose of this produced water may increase if any of the following occur:

28 • we cannot obtain future permits from applicable regulatory agencies ; 

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Obtaining production from our additional drilling locations could take five years or longer, making them susceptible to uncertainties that could alter the occurrence of their drilling.

The additional drilling locations on our existing acreage represent a significant part of our growth strategy. Our ability to drill and produce these locations depends on a number of uncertainties , including, but not limited to, natural gas prices, permitting and the availability of capital. Furthermore, the addit ional drilling locations on acreage in our two early-stage CBM development projects and our Chattanooga Shale exploration prospect face additional uncertainties regarding the economic returns achievable in these areas where only a few wells have been drilled to date.

Our operations in British Columbia present unique risks and uncertainties, different from or in addition to those we face in our domestic operations.

We conduct our operations in British Columbia through a wholly owned subsi diary, Hudson’s Hope Gas Ltd. Our operations in British Columbia may be adversely affected by curr ency fluctuations. The expenses of such operations are payable in Canadian dollars. As a result, our Canadian operations are subject to risk of fluctuations in the relative value of the Canadian and U.S. dollars. Other risks of operations in Canada inc lude, among other things, increases in taxes and governmental royalties and changes in laws and policies governing opera tions of foreign-based companies. Laws and policies of the U.S. affecting foreign trade and taxation may also adversel y affect our operations in British Columbia.

We may be unable to retain our existing senior management team an d/or other key personnel that have expertise in coalbed methane extraction and our failure to continue to attract qualified new personnel could adversely affect our

business.

Our business requires disciplined execution at all levels of our orga nization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requi res an experienced and talented management and operations team. If we were to lose the benefit of the experience, effort s and abilities of any of our key executives or the members of our team that have developed substantial expertise in coalbed methane ext raction, our business could be adversely affected. We have not entered into employment agreements or non-competition agreements with any of our key employees, other than J. Darby Seré, our President and Chief Executive Officer, and Willia m C. Rankin, our Executive Vice President and Chief Financial Officer. We do not maintain key person life insurance on any of our personnel. Our ability to manage our growth, if any, will require us to continue to train, motivate, and manage our e mployees and to attract, motivate, and retain additional qualified managerial and operations personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating, and retaining the personne l required to grow and operate our business profitably.

Government laws, regulations, and other legal requirements rel ating to protection of the environment, health and safety matters and others that govern our business increase our cos ts and may restrict our operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state, local, and foreign authorities, relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the manage ment and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availabilit y, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is compl eted, control of surface subsidence from underground mining, and work practices related to employee

29 • water of lesser quality is produced;

• our wells produce excess water; or

• new laws and regulations require water to be disposed of in a diffe rent manner. 

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health and safety. Complying with these requirements, including the t erms of our permits, has had, and will continue to have, a significant effect on our respective costs of operations and com petitive position. In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions, and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a res ult of violations of or liabilities under environmental and health and safety laws.

Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the cost of production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas pr operties, environmental matters, safety standards, market sharing, and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

We must obtain governmental permits and approvals for drilling oper ations, which can be a costly and time consuming process and result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the ti ming and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required t o prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed expl oration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. In some cases, consents from third part ies may be required before a permit is issued. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

We depend on technology owned by others.

We rely on the technological expertise of the independent contractors that we retain for our operations. We have no longterm agreements with these contractors, and thus we cannot be s ure that we will continue to have access to this expertise.

We may incur additional costs to produce gas because our confirmation of title for gas rights for some of our properties may be inadequate or incomplete.

We generally obtain title opinions on significant properties that we drill or acquire. However, we cannot be sure that we will not suffer a monetary loss from title defects or failure . In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas withou t perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we control and these costs may be material and vary depending upon the state in which we operate.

The availability or high cost of drilling rigs, equipment, suppl ies, personnel, and field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical, and from time to time there is a s hortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs , equipment, and supplies are substantially greater. As a result of historically strong prices of gas, the demand for field services has risen, and the costs of these services are increasing. If the availability or high cost of drilling rigs, equipment, suppl ies, or qualified personnel were particularly severe in the are as where we operate, we could be materially and adversely affecte d.

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Hedging transactions may limit our potential gains.

In order to manage our interest rate exposure and natural gas price r isks, we have entered into interest rate swaps and natural gas price hedging arrangements with respect to a portion of ou r expected production. We will most likely enter into additional hedging transactions in the future. While intended to reduce the effects of volatile interest rates and natural gas prices, such transactions may limit our potential gains or incr ease our potential losses.

We do not insure against all potential risks. We may incur subst antial losses and be subject to substantial liability claims as a result of our natural gas operations.

We maintain insurance for some, but not all, of the potential r isks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of ava ilable insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certa in insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or availa ble only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion ri sks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proce eds could have a material adverse effect on our financial condition and results of operations.

Risks Related to Our Capital Stock

Our common stock has experienced, and may continue to experienc e, price volatility and a low trading volume.

The trading price of our common stock has been and may continue to be subject to large fluctuations, which may result in losses to investors. Our stock price may increase or decreas e in response to a number of events and factors, including:

This volatility may adversely affect the price of our common stock regardless of our operating performance.

Shares eligible for future sale may cause the market price f or our common stock to drop significantly, even if our business is doing well.

If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantl y. In such case, our ability to raise

31 • results of our drilling or the results of drilling by offset operator s;

• global economic recession;

• trends in our industry and the markets in which we operate;

• changes in the market price of the natural gas we sell;

• changes in financial estimates and recommendations by securiti es analysts;

• acquisitions and financings;

• quarterly variations in operating results;

• operating and stock price performance of other companies that inves tors may deem comparable to us; and

• issuances, purchases or sales of blocks of our common stock. 

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additional capital in the financial markets at a time and pric e favorable to us might be impaired. In addition, our board of directors has the authority to issue additional shares of our authoriz ed but unissued common stock without the approval of our shareholders, subject to certain limitations under the rules of the exchange on which our common stock is listed. Additional issuances of our common stock would dilute the ownership percentage of e xisting shareholders and may dilute the earnings per share of our common stock.

We have not previously paid dividends on our common stock and w e do not anticipate doing so in the foreseeable future.

We have not in the recent past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Our outstanding revolving bank credit agreement contains covenants t hat restrict our ability to pay dividends on our common stock. Additionally, any future decision to pay a dividend and the am ount of any dividend paid, if permitted, will be

made at the discretion of our board of directors.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

CNX Surface Use Disputes

Buchanan County Dispute. On September 12, 2008, the Virginia Supreme Court issued its decision in this matter in favor of us and PMC, reversing and remanding the matter to the Buchanan Circ uit Court for further action consistent with the decision. The Court held that CNX Gas Company LLC (“CNX”) does not have the exclusive right to transport gas across the Pocahontas Mining Limited Liability Company (“PMC”) property and may not prevent uses of the PMC property that do not conflict with the exercise of CNX’s rights under its CBM lease with PMC. The effect of this ruling is that our pipeline right of way with PMC is valid.

Tazewell County Dispute. On January 19, 2007, CNX obtained a tempor ary injunction against our construction of the same 12-mile pipeline across 1,450 feet of a 32-acre tract in Tazewell County, Virginia. The tract of land in dispute has been owned by a large number of extended family members, from whom we ha ve obtained approximately 81% control of the tract, either through purchases of undivided surface interests in the tra ct or by entering into surface use and right-of-way easement agreements. During our pipeline construction process, CNX purchased a m inority undivided surface interest in the property and filed a lawsuit seeking to enjoin the construction of our Pond Cree k gathering line across the property. We and CNX have since reached a resolution of this dispute. The settlement had no ma terial impact on our financial position, results of operations, or cash flows presented herein.

CNX Antitrust Action

We filed a complaint against CNX and Island Creek Coal Company (“ Island Creek”), an affiliate of CNX, in the Circuit Court of Tazewell County, Virginia on February 14, 2007, in which we s ought damages arising from alleged violations of the Virginia Antitrust Act, tortious interference with contractua l relations with third parties and statutory and common law conspiracy. The suit sought compensatory and consequential damages for all eged violations of the Virginia Antitrust Act, including alleged anticompetitive efforts of CNX to dominate and maintain its control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in Bucha nan County, Virginia and for CNX’ s alleged efforts to conspire and act in concert with

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Island Creek and others to dominate and maintain control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in violation of the Virginia A ntitrust Act and Virginia statutory and common law. The suit also alleged CNX’s intentional interference with our exis ting and prospective third-party business relationships in an attempt to harm us and improve CNX’s position and corporate and fina ncial interests. In accordance with an opinion issued by
the Tazewell Circuit Court in December 2007, we have filed an a mended petition that restates with specificity our claims against CNX and Island Creek, names Cardinal States Gathering Company and CONSOL Energy Inc., the ultimate parent of
the other defendants, as additional defendants, and seeks actual da mages of $385.6 million. We are seeking treble damages for the alleged violations of the Virginia Antitrust Act, as well as injunctive relief to prevent CNX and other parties from continuing these alleged anticompetitive activities.

Environmental and Regulatory

As of December 31, 2008, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us

.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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PART II

Common Stock

Our common stock is listed on the NASDAQ Global Market under the symbol “GMET”. The table below shows the high and low closing prices of our common stock for the periods indicated.

Approximately 1,500 stockholders of record as of December 31, 2008 held our common stock. In many instances, a registered stockholder is a broker or other entity holding shares in s treet name for one or more customers who beneficially own

the shares. Holders of our common stock are entitled to recei ve dividends if, as and when such dividends are declared by our board out of assets legally available therefore after payment of divi dends required to be paid on shares of preferred stock, if any. We have not declared or paid any dividends on our shares of common s tock and do not currently anticipate paying any dividends on our shares of common stock in the future. Currently our plan is to retain any future earnings for use in the operations and expansion of our natural gas exploration business. Our revolvin g credit facility prohibits us from paying any

cash dividends.

Changes in Securities, Use of Proceeds and Issuer Purcha ses of Equity Securities

We did not purchase any of our equity securities during the fourth quarter of 2008. In addition, we did not sell any of our equity securities which were not registered under the Securities A ct of 1933, as amended, during the fourth quarter of 2008.

Equity Compensation Plan Information

The following table summarizes information regarding the number of s hares of our common stock that are available for issuance under all of our existing equity compensation plans as of Dec ember 31, 2008.

34 Item 5. Market for Registrant ’ s Common Equity, Related Stockholder Matters and Issuer Purch ases of Equity Securities.

High Low
Fiscal Year 2006: Quarter ended September 30, 2006 $ 11.71 $ 9.40 Quarter ended December 31, 2006 $ 11.25 $ 8.66

Fiscal Year 2007: Quarter ended March 31, 2007 $ 10.34 $ 7.73 Quarter ended June 30, 2007 $ 9.67 $ 7.26 Quarter ended September 30, 2007 $ 7.75 $ 5.09 Quarter ended December 31, 2007 $ 5.49 $ 4.86

Fiscal Year 2008: Quarter ended March 31, 2008 $ 7.28 $ 4.21 Quarter ended June 30, 2008 $ 9.52 $ 6.38 Quarter ended September 30, 2008 $ 9.40 $ 5.04 Quarter ended December 31, 2008 $ 5.32 $ 1.36

Plan Category Number of securities to be issued upon

exercise of outstanding options Weighted

- average exercise price of outstanding options, warrants and rights Number of securities remaining available

for future issuance under equity compensation plans (excluding securities reflected in column) Equity compensation plans approved by security holders 1,757,256 $ 5.01 1,209,891 (1) Equity compensation plans not approved by security holders

— — — Total 1,757,256 $ 5.01 1,209,891 

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Performance Graph

The following performance graph and related information shall not be deeme d “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference int o any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate the performance graph by reference into such filing.

The following graph compares the cumulative total stockholder return on our common stock from July 28, 2006, the date our common stock was listed on the Nasdaq Global Market, through Decem ber 31, 2008 and compares it with the cumulative total return on the Russell 2000 and the S&P Oil and Gas Explorati on and Production Index. The comparison assumes $100 was invested on July 28, 2006 and assumes reinvestment of dividends, if a ny. The comparisons in this table are required by the SEC and are not intended to forecast or be indicative of possible f uture performance of our stock.

COMPARISON OF CUMULATIVE TOTAL RETURN

35 (1) In 2006, our board of directors and stockholders approved the GeoMet, Inc. 2006 Long-Term Incentive Plan under which 2,000,000 shares of our common stock were reserved for awards to be gra nted. In conjunction with the approval of the 2006 Plan, no additional awards have been or will be granted under our 2005 Plan; however, we will continue to issue shares of our common stock upon exercise of awards that we have pr eviously granted. The 1,209,891 of securities remaining available for future issuance includes 242,448 shares that w ere reserved but not granted under our 2005 Plan.

7/28/06 12/31/06 12/31/07 12/31/08 GeoMet, Inc. 100.00 94.80 47.40 15.68

Russell 2000 Index 100.00 112.52 109.43 71.35

S&P Oil & Gas 100.00 97.01 132.82 75.92 

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Item 6. Selected Financial Data

The following table shows our selected historical consolidated financi al and operating data as of and for each of the last five years ended December 31, 2008. The selected historical audited consolidated financial and operating data for the three years ended December 31, 2008 are derived from our audited financial statements included herein. The selected historical audited consolidated financial and operating data for the two years ended December 31, 2004 was derived from our audited

financial statements which are not included herein. The table re flects a four-for-one common stock split in 2006 and prior periods have been adjusted for the stock split. You should read the follow ing data in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condit ion” and our consolidated financial statements and related notes included elsewhere in this annual report where t here is additional disclosure regarding the information in the following table. Our historical results are not necessarily i ndicative of the results that may be expected in future periods.

36 2008 2007 2006 2005 2004
STATEMENT OF OPERATIONS (in thousands):

Total revenues $ 69,094 $ 50,984 $ 44,947 $ 41,980 $ 20,924 Realized (gain) losses on derivative contracts $ 500 $ (3,895 ) $ (1,118 ) $ 7,473 $ 815 Unrealized (gains) losses from the change in market value of open derivative contracts $ (4,993) $ 3,007 $ (16,877) $ 12,059 $ (542) Impairment of gas properties $ 50,734 —

— — — Total operating expenses $ 87,590 $ 37,852 $ 13,678 $ 41,149 $ 13,272 Operating (loss) income from continuing operations $ (18,496) $ 13,132 $ 31,269 $ 831 $ 7,652 Interest expense, net of amounts capitalized $ (4,783) $ (5,130) $ (3,130) $ (3,895) $ (986) (Loss) income before income taxes, minority interes t, discontinued operations and cumulative effect of change in accounting principle $ (23,199 ) $ 7,983 $ 28,162 $ (3,008 ) $ 6,732 Income tax expense (benefit) $ (712) $ 2,988 $ 10,866 $ (993) $ 2,312 (Loss) income before minority interest, discontinue d operations and cumulative effect of change in accounting principle, net of income tax $ (22,487) $ 4,995 $ 17,296 $ (2,015) $ 4,420 Discontinued operations, net of income tax — $ 174 $ 23 — — Minority interest, net of income tax

— — $ (23) $ 442 $ (584) Income (loss) from discontinued operations

— $ 174

— $ 442 $ (584 ) (Loss) income from continuing operations before cum ulative effect of change in accounting principle,

net of income tax $ (22,487) $ 5,169 $ 17,296 $ (1,573) $ 3,836 Cumulative effect of change in accounting principle , net of income tax

— — — — — Net (loss) income $ (22,487) $ 5,169 $ 17,296 $ (1,573) $ 3,836

EARNINGS PER COMMON SHARE (in dollars): (Loss) Income from continuing operations

Basic $ (0.58) $ 0.13 $ 0.49 $ (0.07) $ 0.17

Diluted $ (0.58) $ 0.13 $ 0.48 $ (0.07) $ 0.17 Discontinued operations

Basic

— — — $ 0.02

— Diluted

— — — $ 0.02

— Net (loss) income per common share

Basic $ (0.58) $ 0.13 $ 0.49 $ (0.06) $ 0.17

Diluted $ (0.58) $ 0.13 $ 0.48 $ (0.06) $ 0.17

BALANCE SHEET DATA (in thousands, at period end): Working (deficit) capital(1) $ (1,441) $ (2,063) $ (1,625) $ (7,368) $ (1,251) Total assets (including impairment of gas propertie s) $377,600 $378,677 $335,195 $247,909 $ 142,090 Long-term debt $117,118 $ 96,730 $ 60,832 $ 99,926 $ 51,513 Stockholders’ equity $192,432 $218,676 $210,007 $ 95,422 $ 65,692

Cash flow data (in thousands): Net cash provided by operating activities $ 32,958 $ 17,487 $ 21,472 $ 12,433 $ 10,580 Net cash used in investing activities $ (52,719) $ (53,832) $ (78,669) $ (59,661) $ (66,193) Net cash provided by financing activities $ 20,493 $ 36,191 $ 58,086 $ 44,906 $ 50,192 Capital expenditures $ 52,797 $ 54,026 $ 79,061 $ 59,817 $ 86,189

OTHER DATA: Net sales volume (Bcf) 7.5 7.1 6.2 4.6 3.2 Average natural gas sales price ($ per Mcf)(2) $ 9.17 $ 6.97 $ 7.19 $ 9.06 $ 6.12 Average natural gas sales price ($ per Mcf) realize d(3) $ 9.10 $ 7.52 $ 7.37 $ 7.43 $ 5.87 Total production expenses ($ per Mcf) $ 2.87 $ 2.86 $ 2.75 $ 2.81 $ 2.36 Depletion of gas properties($ per Mcf) $ 1.35 $ 1.24 $ 1.26 $ 1.06 $ 0.84 Estimated proved reserves (Bcf)(4) 319.5 350.2 325.7 262.5 209.9

Standardized measure of discounted future net cash flows ($ millions) $ 310.3 $ 495.9 $ 359.5 $ 632.7 $ 349.8

Non

- GAAP Measures:(5) PV-10 ($ millions) $ 351.9 $ 662.8 $ 525.6 $ 880.2 $ 481.8 

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Reconciliation of Non-GAAP Financial Measures

The following table shows our reconciliation of our PV-10 to our standardi zed measure of discounted future net cash flows (the most directly comparable measure calculated and pres ented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved natur al gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The

estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our CBM gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to inv estors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas compa nies. Because there are many unique factors that can impact an individual company when estimating the amount of future inc ome taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate

PV-10 on the same basis. PV-10 should not be considered as an alter native to the standardized measure of discounted future net cash flows as computed under GAAP.

37 (1) Working capital (deficit) is defined as current assets less current liabilities and is unaudited. (2) Our natural gas sales price at December 31, 2008 was $5.84 per Mcf. (3) Average realized price includes the effects of r ealized gains on derivative contracts. (4) Based on the reserve reports prepared by DeGolye r and MacNaughton, independent petroleum engineers, at each period end. Natural gas prices are volatil e and may fluctuate widely affecting significantly the ca lculation of estimated net cash flows. Refer to “Ri sk Factors” for a more complete discussion. (5) See reconciliation of non-GAAP financial measure s.

As of December 31,

2008 2007 2006 2005 2004
(In thousands) Future cash inflows $ 1,865,131 $ 2,654,214 $ 1,858,104 $ 2,536,279 $ 1,302,830 Less: Future production costs 734,911 725,272 501,956 463,416 290,425 Less: Future development costs 105,737 106,356 101,777 76,297 38,242

Future net cash flows 1,024,483 1,822,586 1,254,371 1,996,566 974,163

Less: 10% discount factor 672,534 1,159,780 728,739 1,116,413 (492,339 )

PV

- 10 351,949 662,806 525,632 880,153 481,824

Less: Undiscounted income taxes (423,795 ) (724,399 ) (410,391 ) (579,689 ) (274,975 )

Plus: 10% discount factor 382,193 557,461 244,245 332,201 142,906

Discounted income taxes (41,602 ) (166,938 ) (166,146 ) (247,488 ) (132,069 )

Standardized measure of discounted future net cash

flows $ 310,347 $ 495,868 $ 359,486 $ 632,665 $ 349,755 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and result s of operations should be read in conjunction with the financial statements and the related notes and other information i ncluded elsewhere in this report.

Overview

GeoMet, Inc. is an independent energy company primarily engaged in the e xploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM ”) and non-conventional shallow gas. We were originally founded as a consulting company to the coalbed methane industry i n 1985 and have been active as an operator and developer of coalbed methane properties since 1993. Our principal operati ons and producing properties are located in the Cahaba Basin in Alabama and the central Appalachian Basin in We st 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 December 31, 2008, we control a total of approximately 213,000 net acres of coalbed methane and oil and gas development rights.

Our proved natural gas reserves as of December 31, 2008 as estimat ed by DeGolyer and MacNaughton, independent petroleum engineers, totaled approximately 320 Bcf, a decrease of 8.6% from the approximate 350 Bcf of proved natural gas reserves at year-end 2007. Proved reserve estimates for the curr ent year were calculated using an unescalated natural gas price of $5.71 per MMBtu, adjusted for regional price differentials, as c ompared to an unescalated natural gas price in the prior year of $7.46 per MMBtu.

Our proved reserves were 100% from unconventional reservoirs, were 99% from coalbed methane and were 77% developed. The present value of proved reserves discounted at ten per cent was approximately $352 million at December 31, 2008 as compared to $663 million at year-end 2007. Although reserves dec lined from year-end 2007, before downward revisions and a property conveyance the Company replaced approximately 296% of its production in 2008. Downward revisions totaled approximately 42 Bcf of which approximately 13 Bc f resulted from lower natural gas prices. The remaining downward revisions were primarily in the Gurnee field in Alabama , resulting from production performance issues in certain

sectors of the field.

Approximately 57% of total year-end 2008 proved reserves are in the Gur nee field in Alabama and 41% are in the Pond Creek and Lasher fields in West Virginia and Virginia. The Pe ace River project is the first commercial coalbed methane project in British Columbia, Canada and there are no other similar producing analogies in the region. As a result, initia l proved developed reserves of only 4 Bcf were booked in 2008. Similarly, our Gar den City project it is the first commercial Chattanooga Shale project in Alabama, and only 2 Bcf of initial pro ved reserves were booked in 2008.

Impact of Current Credit Market Conditions—We believe that we are well-positioned for the current credit market environment. We have a healthy balance sheet with over $2 million i n cash and a debt-to-book capital ratio of 38%. The borrowing base on our revolving credit facility was set at $140 mill ion on March 12, 2009. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. If not extended, our credit facility will mature in January 2011. As of December 31, 2008, we were in compliance with all of the covenants in the credit agreement. All of our lenders are currently funding our borrowing requests.

Impact of Decreasing Natural Gas Prices—We account for our gas properties using the full cost method and are required to impair a full cost pool when the net capitalized costs in t he pool exceed the discounted future net revenues of the proved reserves associated with the pool. Based upon the lower natural gas prices at December 31, 2008, we have reported a non-cash impairment to our U.S. full cost pool of $20 million, net of income t ax. Due to limited initial proved reserve bookings in the Peace River project we also reported a non-cash

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impairment to our Canadian full cost pool of $19 million, net of incom e tax. If natural gas prices at March 31, 2009 are below those prices that existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’ s natural gas properties for the quarter then ended.

Trends

Our business is influenced by trends that affect the natural gas in dustry. In particular, recent declines in natural gas prices and recent economic trends could adversely affect our business, liqui dity, results of operations and financial condition.

Our business is increasingly subject to the adverse trends that hav e taken place in the global capital markets recently. The recent events in the credit and stock markets indicate a high like lihood of a continuation of, and probable further expansion of, the economic weakness in the U.S. economy that began over one year ago. The spillover of deepening fears about our banking system may adversely impact investor confidence in us, our banking re lationships, and the liquidity and financial condition of third parties with whom we conduct operations.

We expect to face the continuing challenges of weakness in the U. S. real estate market and increased mortgage delinquencies, investor anxiety over the U.S. economy, rating agency dow ngrades of various financial issuers, unresolved issues with structured investment vehicles, deleveraging of financ ial institutions and hedge funds and dislocation in the interbank market. If significant, continued volatility, changes in intere st rates, defaults, market liquidity, declines in equity prices

, and the strengthening or weakening of foreign currencies against the U. S. dollar, individually or in tandem, could have a material adverse effect on our liquidity, results of operations, f inancial condition or cash flows through realized losses, and impairments.

Although we expect to experience a reduction in the level of our capit al spending in 2009, we believe the steps we have taken to date in response to the global slowdown in the natural gas in dustry will positively impact our ability to follow through with our business strategy without being forced to implement additional significant countermeasures, such as work force layoffs. Other potential steps that could be implemented in light of the current recession, if we deem it necessary, could include selling assets or entering into more joint venture agreeme nts with industry partners to reduce our costs.

The natural gas industry is capital intensive. We make, and antic ipate that we will continue to make, substantial capital expenditures in the exploration for, development and acquisition of natur al gas reserves. Historically, our capital expenditures have been financed primarily with internally generated cash from operations, proceeds from bank borrowings, and industry joint venture arrangements. The continued availability of these capit al sources depends upon a number of variables, including our proved reserves, the volumes of natural gas we produce from exi sting wells, the prices at which we sell natural gas, our ability to acquire, locate and produce new reserves, and events oc curring within the global capital markets. Except for the existing revolving credit facility we have with our bank lenders, we do not currently have any agreements for any future financing and there can be no assurance as to the availability or te rms of any such future financing.

Natural Gas Price Trends

Changes in natural gas prices significantly affect our revenues, financial condition, cash flows and borrowing capacity. Markets for natural gas have historically been volatile and we expect this trend to continue. Prices for natural gas typically fluctuate in response to relatively minor changes in supply and dema nd, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the pr ices we receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices may materially adversely affect our financial condition, liquidity, abil ity to obtain financing and operating results. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. A decline in natural gas prices could have a ma terial adverse effect on the estimated value and estimated quantities of our

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natural gas reserves, our ability to fund our operations and our financia l condition, cash flow, results of operations and access to capital. Our capital expenditure budgets are highly dependent on future natural gas prices.

Operational Developments

Pond Creek—We connected 26 new infill wells to sales in 2008 giving us a total of 242 productive wells in the Pond Creek field. Net gas sales increased to 13.7 MMcf per day for the year ended December 31, 2008, as compared to 12.3 MMcf per day for the year ended December 31, 2007.

Lasher—Initial gas sales commenced on October 28, 2008. We connect ed a total of 18 wells to sales in 2008. Net gas sales averaged 0.1 MMcf per day for the period of October 28, 2008 t hrough December 31, 2008.

Gurnee—We connected 11 new infill wells to sales in 2008 giving us a total of 246 productive wells in the Gurnee field. Net gas sales were unchanged at 6.1 MMcf per day for the years ended December 31, 2008 and 2007.

Garden City—In this Chattanooga shale prospect two vertical well s were re- stimulated and a horizontal well drilled in the second quarter was completed in the third quarter. These three well s were connected to sales in the third quarter with net gas sales averaging 0.1 MMcf per day through December 31, 2008. Two vertic al test wells drilled in the western portion of the prospect are currently shut-in awaiting the identification of a dequate water disposal and connection into a gas sales line. We are still evaluating potential water disposal solutions.

Peace River—On December 31, 2008, we commenced gas deliveries from eight wells at Peace River. We own a 50% working interest and operate the project which covers over 50,000 acres of Crown tenure. Four coreholes and twelve production wells have been drilled, targeting the Lower Cretaceous G ething coals. Average coal thickness over the acreage is 52 feet, and the average gas content is 400 cubic feet per ton.

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 di spute arose as to whether the preferential right to purchase applied to all the interests we owned in this property or j ust the working interests. We filed a declaratory judgment action asserting that the preferential right to purchase applied onl y to the working interests, and that we were entitled to retain all remaining interests we owned in the property. Following a par tial agreement with the other party, we assigned all our remaining interests in the property to that party, effective July 1, 2008. 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. We have subsequently reached a settlement with the other party in the amount of $475,000, w hich has been accrued as a liability as of December 31, 2008. The proved reserves conveyed represented less than 1% of our total proved reserves and the related production was approximately 900 Mcf per day.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of oper ations are based upon our consolidated financial statements that have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of asse ts and liabilities and disclosure of contingent assets and

liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experiences and va rious other assumptions that we believe are reasonable; however, actual results may differ. Our significant accounting policies are described in Note 2 to our consolidated financial

statements included

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elsewhere in this annual report. We believe the following critic al accounting policies involve significant judgments, estimates, and a high degree of uncertainty in the preparation of our financial s tatements:

Reserves. Our most significant financial estimates are based on estimat es of proved gas reserves. Proved gas reserves represent estimated quantities of gas that geological and engineer ing data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and oper ating conditions existing at the time the estimates

were made. There are numerous uncertainties inherent in estimat ing quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of avail able geologic, geophysical, engineering, and production data and, the accuracy of reserve estimates is a function of t he quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, natural gas prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unev aluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling lim itation. Our reserves are fully engineered on an annual basis by DeGolyer and MacNaughton, independent petroleum engineers.

Gas Properties

— The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the ful l cost method of accounting for gas properties as prescribed by the United States Securities and Exchange Commission ( “SEC”). Under this method, all direct costs and certain indire ct costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into

U.S. and Canadian cost centers.

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estim ated proved gas reserves.

Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reser ves, which would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are li mited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is imposed se parately for our U.S. and Canadian cost centers. If capitalize d costs (net of accumulated depreciation, depletion and amortization ) less related deferred taxes are greater than the discounte d future net revenues or ceiling limitation, a write-down or impair ment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduc es earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a

write-down is not reversible at a later date.

The ceiling limitation test is calculated using natural gas pr ices in effect as of the balance sheet date and adjusted for
“basis” or location differential, held constant over the life of the reserves. In addition, subsequent to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143 ”), the future cash outflows associated with settling asset retirement obligations are not included in the computation of the di scounted present value of future net revenues for the purposes of the ceiling limitation test calculation.

At December 31, 2008, the carrying value of the Company’s gas propertie s in the U.S. exceeded the full cost ceiling limitation by $19,959,547, net of income tax of $12,087,937, based upon a natural gas price of

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Index to Financial Statements

approximately $5.84 per Mcf in effect at that date. A decline in pri ces received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of our gas properties in a future period. In the year ended December 31, 2008, w e recognized an impairment of our gas properties of $19,959,547, net of income tax of $12,087,937.

At December 31, 2008, the carrying value of the Company’s gas propertie s in Canada exceeded the full cost ceiling limitation by $18,686,273 (no income tax effect as Canadian income taxes are fully valued), based upon a natural gas price of approximately $5.20 per Mcf in effect at that date. A decline in pri ces received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of our gas properties in a future period. In the year ended December 31, 2008, w e recognized an impairment of our gas properties of $18,686,273.

If natural gas prices at March 31, 2009 are below those prices tha t existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas proper ties for the quarter then ended.

Unevaluated Properties

— The costs directly associated with unevaluated properties and properti es under development are not initially included in the amortization base and relate t o unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination of proved r eserves together with overhead and interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to

the amortization base with the associated leasehold costs on a s pecific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortizat ion base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the

amortization base.

Asset Retirement Liability —We adopted SFAS 143

, effective January 1, 2003. It establishes accounting and report ing standards for retirement obligations associated with tangible long -lived assets that result from the legal obligation to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed or developed. It requires that the fair value of the liability for asset retirement obligations be recogniz ed in the period in which it is incurred. Upon initial recognition of the asset retirement liability, the asset reti rement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. The liabil ity is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the re lated asset.

Income Taxes— We record our income taxes using an asset and liability approach in accordance with the provisions of
the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”) as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes

— an Interpretation of FASB Statement No. 109 (“FIN 48”). This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities using enacte d tax rates at the end of the period. Under SFAS 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management , it is more likely than not that some portion or all of

the deferred tax assets will not be realized.

Estimating the amount of valuation allowance is dependent on estim ates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger l imits on use of net operating losses under Internal Revenue Code Section 382. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOL’s”).

The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 clari fies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,

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“Accounting for Income Taxes”, and prescribes a consistent thre shold and measurement attribute for financial statement recognition and disclosure of tax positions taken, or expected to be t aken, on a tax return. The adoption of this pronouncement did not have a significant impact on the Company’s consolidated financia l statements.

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 wher eby revenues, net of royalties, are recognized as the production is sold to purchaser. The amount of gas sold may differ fr om 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 proper ties. A ready market for natural gas allows us to sell our natural gas shortly after production at various pipeline re ceipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our nom inations 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 a nd 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 s tatements are generated. Differences are reflected in the accounting period during which payments are received from the purchaser.

Derivative Instruments and Hedging Activities. Our hedging activities consist of derivative instruments entered into to hedge against changes in natural gas prices and changes in interest r ates related to outstanding debt under our credit facility primarily through the use of fixed price swap agreements, basis swa p agreements, three-way collars, and traditional collars. Consistent with our hedging policy, we entered into a series of deri vative instruments to hedge a significant portion of our expected natural gas production through 2009 and 2010. We also entered int o interest rate swap agreements to hedge interest rates associated with a portion of our variable rate debt through 2010. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. These transactions are

recorded in our financial statements in accordance with SFAS l33. Although not risk free, we believe this policy will reduce our exposure to natural gas price fluctuations and changes in interest rates and thereby achieve a more predictable cash flow. As a result, our derivative instruments are cash flow hedge tra nsactions in which we are hedging the variability of cash flow

related to a forecasted transaction. We do not enter into derivat ive instruments for trading or other speculative purposes.

In accordance with SFAS 133, as amended, all our derivative instrume nts are recorded on the balance sheet at fair market value and changes in the fair market value of the derivatives are re corded each period in current earnings for the natural gas derivatives or other comprehensive income (loss) for our interest rate swaps. The natural gas derivatives have not been designated as hedge transactions while the interest rate swaps qualify and have been designated as cash flow hedges in

accordance with SFAS 133.

At the inception of a derivative contract, we may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, we document the relationship between the derivative instrument and the hedged items as well as the risk management objective for entering into the derivati ve instrument. To be designated as a cash flow hedge transaction, the relationship between the derivative and hedge item s must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the de rivative and on an ongoing basis.

Stock-Based Compensation

— We follow the fair value recognition provisions of SFAS No. 123(R)

, Share-Based Payment (“SFAS 123(R)”), using the prospective transition method. The a pplication of SFAS 123(R) requires the use of an option pricing model, such as the Black Scholes model, to measure the estimated fair value of the options and as a result various assumptions must be made by management that require judgment a nd the

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assumptions could be highly uncertain. For share-based awards outstanding p rior to the adoption of SFAS 123(R), we will continue using the accounting principles originally applied to those awar ds before adoption. Therefore, we do not recognize any equity compensation cost on these prior awards in the future unle ss such awards are modified, repurchased or cancelled.

Fair Value Measurement— In September 2006, the FASB issued SFAS No. 157, “Fair Value Mea surements ” (“SFAS 157”). SFAS 157 is effective for fiscal years beginning after November 15, 2007. Effective January 1, 2008, we adopted SFAS 157, which provides a framework for measuring fair value under GAA P. SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liabil ity (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. SFAS 157 also establishe s a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three l evels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identi cal assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs other than quote d prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quot ed prices for similar assets or liabilities; quoted prices i n markets that are not active; or other inputs that are observable or can be corr oborated by observable market data for substantially the full term of the assets or liabilities. Level 3 inputs are derive d from unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the asse ts or liabilities. See disclosure related to the implementa tion of SFAS 157 in Note 6—Derivative Instruments and Hedging Activities. The FASB has also issued Staff Position FAS 157-2 (“FSP 157-2”), which delays the effective date of SFAS 157 for nonfina ncial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statem ents on a recurring basis (at least annually), until fiscal ye ars beginning after November 15, 2008. We have elected to defer the applicat ion of SFAS 157 thereof to nonfinancial assets and

liabilities in accordance with FSP 157-2. Non- recurring nonfinancial assets and nonfinancial liabilities for which the Company has not applied the provisions of SFAS 157 include those measured at f air value in goodwill impairment testing, asset retirement obligations initially measured at fair value, and thos e initially measured at fair value in a business combination. O n October 10, 2008, the FASB issued Staff Position No. FAS 157-3 (“ FSP 157-3”). FSP 157-3 clarifies the application of SFAS 157 in a market that is not active and provides an example to illustr ate key considerations in determining the fair value of a

financial asset when the market for that financial asset is not active. On January 1, 2009, we will adopt SFAS 157 as it relat es to nonfinancial assets and liabilities, including nonfinancial asse ts and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and ini tial recognition of asset retirement obligations. There has been no significant impact to our consolidated financial stateme nts related to the implementation of SFAS 157 for our existing non-financial assets and liabilities.

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Natural Gas Production—Producing Fields Operations Summary

The table below presents information on gas revenues, sales volume s, production expenses and per Mcf data for the years
ended December 31, 2008, 2007 and 2006. This table should be read with the di scussion of the results of operations for the periods presented below.

45 Year Ended December 31,

2008 2007 2006
Gas sales $ 68,314 $ 49,694 $ 44,806

Lease operating expenses $ 14,757 $ 13,981 $ 11,579 Compression and transportation expenses 4,498 5,209 4,499

Production taxes 2,137 1,164 1,037
Total production expenses $ 21,392 $ 20,354 $ 17,115

Net sales volumes (Consolidated) (MMcf) 7,453 7,125 6,228 Pond Creek field (MMcf) 5,003 4,494 3,844 Gurnee field (MMcf) 2,241 2,235 1,950 Per Mcf data ($/Mcf): Average natural gas sales price (Consolidated) $ 9.17 $ 6.97 $ 7.19

Pond Creek field $ 9.17 $ 6.96 $ 7.26

Gurnee field $ 9.15 $ 6.94 $ 7.05 Average natural gas sales price realized (Consolidated)(1) $ 9.10 $ 7.52 $ 7.37 Lease operating expenses (Consolidated) $ 1.98 $ 1.96 $ 1.86

Pond Creek field $ 1.54 $ 1.60 $ 1.54

Gurnee field $ 2.98 $ 3.05 $ 2.90 Compression and transportation expenses (Consolidated) $ 0.60 $ 0.73 $ 0.72

Pond Creek field $ 0.68 $ 0.92 $ 0.98

Gurnee field $ 0.49 $ 0.47 $ 0.38 Production taxes (Consolidated) $ 0.29 $ 0.17 $ 0.17

Pond Creek field $ 0.15 $ 0.01 $ 0.02

Gurnee field $ 0.55 $ 0.41 $ 0.41 Total production expenses (Consolidated) $ 2.87 $ 2.86 $ 2.75

Pond Creek field $ 2.37 $ 2.53 $ 2.54

Gurnee field $ 4.02 $ 3.93 $ 3.68 Depletion (Consolidated) $ 1.35 $ 1.24 $ 1.26

(1) Average realized price includes the effects of realized gai ns and losses on derivative contracts. 

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Results of Operations

Year Ended December 31, 2008 compared with Year Ended December 31, 2007

The following are selected items derived from our Consolidated Sta tement of Operations and their percentage changes from the comparable period are presented below.

NM-Not Meaningful

Gas sales. Gas sales increased by $18.6 million, or 37%, to $68.3 million compa red to the prior year. The increase in gas sales was a result of both increased gas prices and production. Pr oduction increased 5% and average gas prices, excluding hedging transactions, increased 32%. The $18.6 million increase i n gas sales consisted of a $2.3 million increase in production and a $16.3 million increase in average prices. The increase in product ion was principally attributable to the continued development activities at our Pond Creek and Gurnee fields.

Lease operating expenses. Lease operating expenses increased by $0.8 million, or 6%, to $14. 8 million compared to the prior year. The $0.8 million increase in lease operating expenses con sisted of $0.6 million increase in production and $0.2

million increase in costs.

Compression expense. Compression expense increased by $0.5 million, or 19%, to $3.1 million c ompared to the same period in the prior year. The increase in compression expense consi sted of a $0.1 million increase in production and a $0.4
million increase in costs. The $0.4 million increase in costs w as primarily due to an increase in repair and maintenance expenses for the compressors in our Pond Creek field.

Transportation expense. Transportation expense decreased by $1.2 million, or 46%, to $1.4 million compared to the prior year period. The decrease was primarily due to lower transporta tion expenses resulting from the commencement of transportation on our own system from the Pond Creek field and the tempora ry release of a portion of our firm capacity

commitments related to our Pond Creek field.

Production taxes. Production taxes increased by $1.0 million, or 84%, to $2.1 million compare d to the prior year period. The increase in production taxes was due to the phase-in of state taxes on production of natural gas in our Pond Creek field, higher gas prices and increased production.

46 Year Ended December 31,

2008 2007 Change

(in thousands) Gas sales $ 68,314 $ 49,694 37 % Lease operating expenses $ 14,757 $ 13,981 6 % Compression expense $ 3,054 $ 2,557 19 % Transportation expense $ 1,444 $ 2,652

- 46 %

Production taxes $ 2,137 $ 1,164 84 % Depreciation, depletion and amortization $ 10,589 $ 9,092 16 % Impairment of gas properties $ 50,734 $

— NM

General and administrative $ 9,368 $ 9,294 1 % Realized losses (gains) on derivative contracts $ 500 $ (3,895 ) NM Unrealized (gains) losses from the change in market value of open de rivative

contracts $ (4,993 ) $ 3,007 NM Interest expense, net of amounts capitalized $ (4,783 ) $ (5,130 )

- 7 % Income tax (benefit) expense $ (712 ) $ 2,987 NM Discontinued operations $

— $ 174 NM 

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Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.5 million, or 16%, to $10.6 million compared to the prior year period. The depreciation, depleti on and amortization increase consisted of a $0.4 million increase in production and a $1.1 million increase in the depl etion rate.

Impairment of gas properties. At December 31, 2008, the carrying value of the Company’s oil and gas pr operties exceeded the full cost ceiling limitation by approximately $50.7 mil lion. For the year ended December 31, 2007, no such

write-down was recorded.

General and administrative. General and administrative expenses increased by $0.1 million, or 1%, to $9.4 million compared to the prior year period. The primary driver for the increas ed general and administrative expenses was increased office expense, share based awards and investor relation expense, of fset by a decrease in employee bonuses.

Realized losses (gains) on derivative contracts. Realized losses on derivative contracts were $0.5 million in the current year period as compared to $3.9 million of realized gains in the pr ior year period. Realized losses represent net cash flow settlements paid to the counterparty while realized gains repres ent net cash flow settlement paid to us from the counterparty. Realized losses occur when natural gas prices or the derivative i ndex price exceeds the derivative ceiling price. Conversely, realized gains occur when natural gas prices go below the derivative floor price.

Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized gains on open derivative contracts were $5.0 million in the current year period a s compared to a $3.0 million in unrealized losses in the prior year period. Unrealized losses and gains are non -cash transactions that occur when the corresponding natural gas derivative contract asset or liability is marked to market at the end of ea ch reporting period.

Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) decreased by $0.3 mi llion, or 7%, to $4.8 million compared to the prior year period. Gross interes t expense for the period was $5.1 million net of $0.3 million capitalized. Gross interest expense decreased 11% from the prior year period due to lower interest rates, while capitalized interest decreased 48% from the prior year period due to the deferral of certain capital projects.

Income tax benefit. Income tax benefit was $0.7 million in the current year as compar ed to an expense of $3.0 million in the prior year period. The effective tax rate for the 2008 w as 3.1% as compared to 37.4% for 2007. The decrease in the

effective tax rate was due to the full valuation of the deferr ed income tax benefit of $6.6 million related to our Canadian impairment of gas properties recorded in 2008.

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

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Results of Operations

Year Ended December 31, 2007 compared with Year Ended December 31, 2006

NM-Not Meaningful

Gas sales. Gas sales increased by $4.9 million, or 11%, to $49.7 million com pared to the prior year. The increase in gas sales was a result of increased production, partially offset by low er average gas prices. Production increased 14% while average gas prices, excluding hedging transactions, decreased 3%. T he $4.9 million increase in gas sales consisted of a $6.5 million increase in production and a $1.6 million decrease in average prices. The increase in production was principally attributable to our Gurnee and Pond Creek development activities.

Lease operating expenses. Lease operating expenses increased by $2.4 million, or 21% to $14.0 m illion. The $2.4 million increase in lease operating expenses consisted of $1.7 million inc rease in production and $0.7 million increase in costs. The

increase in costs is related to an increase in well servic e activities from the prior year period.

Compression and transportation expenses. Compression and transportation expenses increased by $0.7 million, or 16%, to $5.2 million ($2.6 million each for both compression and transportati on). The $0.7 million increase was comprised of a $0.5 million increase in compression expenses due to increased production and a $0.2 million increase in transportation expenses due to increased production offset by a decrease in the actual per M cf transportation expenses due to the certain gas transported on our own system in 2007.

Production taxes. Production taxes increased by $0.127 million, or 12%, to $1.164 million. The production taxes increase of $0.127 million was primarily due to increased production, partiall y offset by lower average gas prices.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.2 million, or 15%, to $9.1 million. The depreciation, depletion and amortization increase of $1.2 million resulted from the increase in production. There were no significant changes in the depletion rate in 2007.

General and administrative. General and administrative expenses increased by $2.7 million, or 42%, to $9.3 million. The increase in general and administrative expenses was a result of increases in employee expenses (15%), professional services (94%), director and investor relations expenses (139%), insurance e xpense (74%) and office expenses and business taxes (6%). The largest dollar increase was in employee expenses and professi onal services that resulted from the increased audit, Sarbanes Oxley, tax and legal services. The increase

48 Year Ended December 31,

2007 2006 Change

(In thousands) Gas sales $ 49,694 $ 44,806 11 % Lease operating expenses $ 13,981 $ 11,579 21 % Compression and transportation expenses $ 5,209 $ 4,499 16 %

Production taxes $ 1,164 $ 1,037 12 % Depreciation, depletion and amortization $ 9,092 $ 7,876 15 %

General and administrative $ 9,294 $ 6,553 42 % Realized gains on derivative contracts $ 3,895 $ 1,118 NM Unrealized (gains) losses from the change in market value of open de rivative

contracts $ 3,007 $ (16,877 ) NM Interest expense (net of amounts capitalized) $ 5,130 $ 3,130 64 % Income tax expense $ 2,987 $ 10,866 NM % Discontinued operations $ 174 $

— NM % 

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in general and administrative expenses was a result of expanding the overhead structure to support our growth and increased costs of being a public company.

Realized gains on derivative contracts. Realized gains on derivative contracts increased by $2.8 million to $3.9 million compared to a gain of $1.1 million in the prior period. Realized los ses represent net cash flow settlements paid to the counterparty while realized gains represent net cash flow settlem ent paid to us from the counterparty. Realized losses occur when natural gas prices or the derivative index price exceeds th e derivative ceiling price. Conversely, realized gains occur when natural gas prices go below the derivative floor price.

Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized (gains) losses from the change in market value of open derivative contracts generated a $3.0 million loss as compared to a $16.9 million gain in the prior period. Unrealized losses and gains are non-cash trans actions that occur when the corresponding asset or liability

derivative contracts are marked to market at the end of each re porting period. Unrealized gains are recognized when the fair

values of derivative assets increase or the fair value of derivat ive liabilities decrease. Unrealized losses are recognize d when

the fair values of derivative assets decrease or the fair value of derivative liabilities increase. The $3.0 million loss was a result of increased future natural gas prices.

Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) increased by $2 mill ion, or 64%, to $5.1 million. The increase was primarily due to higher outsta nding debt and higher interest rates. Capitalized interest totaled $0.6 million and $1.0 for the years ended December 31, 2007 and 2006, respectively.

Income tax expense. Income tax expense decreased by $7.9 million to $3.0 million. The decre ase in income tax expense for the period was due to decreased pretax income compared to the prior period. In addition, the effective tax rate decreased for the year to 37% from 39% in the comparable prior period. The pri ncipal driver for the difference in the effective tax rate was due to lower state income taxes resulting from state apport ionment factor shifting.

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

Liquidity and Capital Resources

Cash Flows and Liquidity

Cash flows from operations for the year ended December 31, 2008 and 2007 were $33.0 million and $17.5 million, respectively. Cash flow provided by operations for the year ended D ecember 31, 2008 of $33.0 million combined together with $20.5 million (net) borrowed from our revolving credit facility we re sufficient to fund our cash basis capital expenditures of $52.8 million.

As of December 31, 2008, we had a working capital deficit of app roximately $1.4 million, a decrease of $0.7 million from the working capital deficit of $2.1 million at December 31 , 2007. At December 31, 2008, we had adequate cash flows from operating activities and credit availability to fund our working c apital deficits.

49 

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The following table is a summary of our capital expenditures on an accrual basis by category:

Our capital expenditure budget for 2009 will be funded from our estimated operating cash flows. If our cash flows are not sufficient to fund all of our estimated capital expenditures, we may reduce our capital budget. The amount and timing of our expenditures are subject to change based upon market conditions, res ults of expenditures and other factors. We routinely adjust our capital expenditure budget in response to changes in natural gas pric es, drilling and acquisition costs, cash flow, drilling results and borrowing base redeterminations under our revolving cre dit facility. Based on current gas price projections, we expect capital expenditures to be less than the $24.1 million capital budget we previously announced.

The development of coalbed methane fields requires substantial init ial investment before meaningful production and resulting cash flows are realized. Among the factors that can be expected to affect our cash flows and liquidity are the characteristics of the field, the amount of water produced, th e methods utilized to dispose of produced water, the transportation alternatives, and the timing and volume of initial and subsequent natura l gas production volumes.

Based upon current expectations, we believe that we will have a dequate resources from cash flows provided by operations and from proceeds from our revolving credit facility borrowi ngs to fund our 2008 capital expenditures and other working capital needs.

Currently, there is an unprecedented uncertainty in the financial m arkets. The uncertainty in the market brings additional potential risks to us. The risks include less availability and higher costs of additional credit, potential counterparty defaults, and further commercial bank failures. Although the financial inst itutions in our bank group appear to be strong, there are some

that have been and could be considered take- over candidates. Although we have no indication that any such transact ions would impact our current credit facility, the possibility does exist . Financial market disruptions may impact our ability to collec t trade receivables. We constantly monitor the credit worthiness of our cus tomers. We believe that our current group of customers are sound and represent no abnormal business risk.

If natural gas prices decrease from their current levels for an extended period, our ability to finance our planned capital expenditures could be affected negatively, consistent with our inte ntion to keep our capital expenditures in line with our estimated operating cash flows, further reduction in spending may be necessary. Furthermore, amounts available for borrowing under our revolving credit facility are largely dependent on our level of estimated proved reserves and current natural gas prices. If either our estimated proved reserves or natural gas prices decrease, amounts available to us to borrow under our revolving credit facility could be negatively affected. If our c ash flows are less than anticipated, amounts available for borrowing under our revolving credit facility are reduced or we are unabl e to sell equity at acceptable prices, we may be forced to defer planned capital expenditures.

50 Year Ended December 31,

2008 2007 2006

(In thousands) Capital expenditures: Leasehold acquisition $ 3,669 $ 7,333 $ 8,975 Exploration 405 2,999 7,626 Development 48,404 44,831 62,211 Other items (primarily capitalized overhead and interest) 5,294 4,649 2,781
Total capital expenditures $ 57,772 $ 59,812 $ 81,593 

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Natural Gas Price Risk and Related Hedging Activities.

We are exposed to natural gas price risk associated with downwar d movements in natural gas prices. Natural gas prices have experienced volatility in recent years in response to chan ges in the supply and demand for natural gas and market uncertainty. The markets and prices for natural gas depend upon factors beyond our control and changes in these prices could adversely affect our revenue and cash flows. These factors include demand for natural gas, which fluctuates with changes in market and economic conditions and other factors, including the im pact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production a nd consumption, the availability of imported natural gas, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxati on.

In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices from time to time primarily us ing derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging ar rangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

We enter into hedging transactions that increase our statist ical probability of achieving our targeted level of cash flows and at times hedge forward for periods of more than two years. We generally limit the amount of these hedges during any period to no more than 50% to 60% of the then expected gas production for s uch future periods. We have historically used swaps, costless collars and three- way costless collars in our hedging activities. Swaps exchange fl oating price risk in the future for a fixed price at the time of the hedge. Costless collar s set both a maximum ceiling (a sold ceiling) and a minimum flo or (a bought floor) future price. Three -way costless collars are similar to regular costless colla rs except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu. We have accounted for the se transactions using the mark-to-market accounting method. Generally, we incur accounting losses during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctua tions in our consolidated statement of operations.

We believe that the use of derivative instruments does not expose us to material risk. However, the use of derivative instruments may materially affect our financial position and re sults of operations as a result of changes in the estimated mar ket value of our natural gas derivatives. Nevertheless, we believe that use of these instruments will not have a material adverse

effect on our cash flows.

The following (gains) losses on our hedging instruments included in the consolidated statements of operations are as

follows:

51 2008 2007 2006 Realized losses (gains) on derivative contracts $ 500,452 $ (3,895,138 ) $ (1,118,043 ) Unrealized (gains) losses on derivative contracts (4,993,238 ) 3,006,916 (16,877,225 )
Total (gains) losses $ (4,492,786 ) $ (888,222 ) $ (17,995,268 ) 

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Commodity Price Risk and Related Hedging Activities.

At December 31, 2008, we had the following natural gas collar posit ions:

Interest Rate Risks and Related Hedging Activities

When we enter into an interest rate swap, we may designate the de rivative as a cash flow hedge, at which time we prepare the documentation required under SFAS No. 133, “Accounting for Derivat ive Instruments and Hedging Activities” (“SFAS l33”). Hedges of our interest rate are designated as cash flow hedges based on whether the interest on the underlying debt is converted to a fixed interest rate. Changes in derivative fair va lues that are designated as cash flow hedges are deferred as other comprehensive income (loss) or loss to the extent that they a re effective and then recognized in earnings when the hedged transactions occur.

We use fixed rate swaps to limit our exposure to fluctuations in i nterest rates with the objective of realizing a fixed cash
flow stream from these activities. At December 31, 2008, we had the following interest rate swaps:

For the year ended December 31, 2008, we recognized no ineffective por tion of our cash flow hedges.

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our credit agreement and the col lateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges. We do not have ri ghts to collateral from our counterparties, nor do we have rights of offset against borrowings under our credit agreement.

The application of SFAS 157 currently applies to our derivative inst ruments. Under the provisions of SFAS 157, we estimate the fair value of our natural gas hedges and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discount ed value. SFAS 157 clarifies that a fair value measurement for an asset or liability reflects its nonperfor mance risk, the risk that the obligation will not be fulfilled. Bec ause nonperformance risk includes our counterparties’ and our credit ris k, we have considered the effect of our credit risk on the

fair value of the liabilities stated below. This consideration involved discounting our counterparties’ and our liabilities based on the difference between the S&P credit rating of a comparable co mpany to ours and the 13-week Treasury bill rate, both at December 31, 2008. The following is a description of the valuation m ethodologies used for our derivative instruments

measured at fair value:

52 Period Volume (MMBtu) Sold

Ceiling Bought

Floor Sold

Floor Fair

Value January through March 2009 540,000 $ 11.00 $ 8.50 $ 6.25 $ 1,138,548 January through March 2009 540,000 $ 11.00 $ 8.84 $ 6.00 $ 1,403,907 April through October 2009 1,284,000 $ 10.00 $ 7.50 $ 5.25 $ 1,615,808 April through October 2009 1,284,000 $ 10.00 $ 8.50 $ 6.50 $ 1,864,114 November 2009 through March 2010 906,000 $ 11.20 $ 9.50 $ 7.00 $ 1,297,652

$ 7,320,029

Description Effective

date Designated

maturity date Fixed

rate(1) Notional

amount Fair Value Floating

- to

- fixed swap 12/14/2007 12/14/2010 3.86 % $ 15,000,000 $ (608,561 ) Floating

- to

- fixed swap 1/3/2008 1/4/2010 3.95 % $ 10,000,000 (243,520 ) Floating

- to

- fixed swap 3/25/2008 3/25/2010 2.38 % $ 10,000,000 (131,102 ) Floating

- to

- fixed swap 5/13/2008 5/13/2010 3.07 % $ 5,000,000 (106,209 )

$ (1,089,392 )

(1) The floating rate paid by the counterparty is the British Bankers ’ Association LIBOR rate.

• Natural Gas Hedges —In order to estimate the fair value of our natural gas hedge positions , a forward price curve and volatility estimates were compiled from sources that include NYMEX settlements and 

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Based on the use of observable market inputs, we have designated thes e types of instruments as Level 2 for SFAS 157 reporting purposes. The fair value of our derivative instruments at December 31, 2008 and 2007 were as follows:

In June 2006, we entered into a credit agreement with Bank of Amer ica, N.A., as agent, and other lenders. Availability under our credit agreement is subject to a borrowing base, which was $180 million at December 31, 2008. As of December 31, 2008, our credit agreement provided for interest to accrue at a r ate calculated, at our option, at either the adjusted base rate (which is the greater of the agent’s base rate or the federal funds rate plus one half of one percent) or the London Interbank Offered Rate (LIBOR) plus a margin of 1.00% to 2.00%, based on borrow ing base usage. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. Borrowings under our c redit agreement are secured by first priority liens on substantially all of our assets including equity interests in our su bsidiaries. All outstanding borrowings under our credit agreement become due and payable on January 6, 2011.

We are subject to financial covenants requiring maintenance of a mi nimum current ratio and a minimum interest coverage ratio. Our ratio of consolidated current assets (adjusted for unre alized (gains) losses on derivative contracts and borrowing availability) to our consolidated current liabilities is not per mitted to be less than 1 to 1 as of the end of any fiscal quarter, a nd our ratio of consolidated EBITDA for the four preceding quarters at the end of each fiscal quarter to the sum of our consolidated net interest expense for the same period plus letter of credit fees accruing during such quarter is not permitted to be less than 2.75 to 1. Consolidated EBITDA, as defined in the ame nded credit agreement, excludes other non -cash charges deducted in determining net income (loss), which would include unrea lized losses from the change in the market value of open derivative contracts. In addition, we are subject to covenants res tricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, cons olidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. A breach of any of the covenants imposed on us by the terms of our revolving credit facility, including the financial covenants, could result in a default under such indebtedness. In the event of a
default, the lenders could terminate their commitments to us,

53

observed trading activity in the Over

- the

- Counter (OTC) markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount f actors incorporating our counterparties’ and our credit standing are used to discount future cash flows.

• Interest Rate Swaps

— In order to estimate the fair value of our interest rate swa ps, we use a yield curve based on Money Market rates and Interest Rate swaps, extrapolate a fore cast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate ca sh flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap c ash flows. Curve building and discounting techniques used to establish the theoretical market value of int erest bearing securities are based on readily available Money Market rates and Interest Rate swap market data. To ext rapolate future cash flows, discount factors incorporating our counterparties ’ and our credit standing are used to discount future cash flows.

2008 2007 Interest rate swap

— asset $

— $ 10,884 Natural gas hedge

— asset 7,320,029 2,326,791

Total derivative assets $ 7,320,029 $ 2,337,675

Interest rate swap

—

liability $ 1,089,392 $

— Natural gas hedge liability

— — Total derivative liabilities $ 1,089,392 $

— 

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and they could accelerate the repayment of all of our indebtedness. In such case, we may not have sufficient funds to pay the total amount of accelerated obligations, and our lenders could procee d against the collateral securing the facility. Any acceleration in the repayment of our indebtedness or related fore closure could adversely affect our business. As of December 31, 2008, we were in compliance with all of the covenants in the credit agreement.

At December 31, 2008, we had $116.5 million outstanding under our revolvi ng credit facility. For the year ended December 31, 2008, interest on the borrowings averaged 4.56% per annum. Borrowing availability at December 31, 2008 was $63.5 million.

Contractual Commitments

We have numerous contractual commitments in the ordinary course of bu siness, debt service requirements and operating lease commitments. The following table summarizes these commi tments at December 31, 2008, beginning January 1, 2009 (in thousands):

Discontinued Operations

As of September 30, 2007, we discontinued the third party marketing business and second reportable segment which had been created in connection with the consolidation of Shamrock Energy L LC, 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 (loss) 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 ins ignificant impact on our net income (loss). As a result, we are treating our third party marketing activities a s a discontinued operation for all the periods presented.

The marketing activities of Shamrock Energy LLC have been transi tioned to GeoMet, Inc without disruption in the marketing of our gas, and we do not expect to incur significant liabil ities or sell any assets in connection with discontinuing this business. As a result, the discontinued operations have an insi gnificant impact on our cash flows.

54 2009 2010 2011 2012 2013 and

thereafter Long

- term debt and other obligations(1) $ 112 $ 122 $ 116,633 $ 92 $ 272 Interest expense on revolving credit facility(2) 2,898 2,898 48

— — Operating lease obligations 1,455 1,394 1,353 551 634 Interest rate swap contracts 715 374

— — — Asset retirement obligations 117

— — — 4,349 Firm transportation contracts 2,526 2,442 1,907 1,313 9,515 Other operating commitments 200 173

— — — FIN 48(3)

— — — — — Total commitments $ 8,023 $ 7,403 $ 119,941 $ 1,956 $ 14,770

(1) Maturities based on the June 2006 amended bank credit agreement term s, which extended the maturity date to January 6,

2011. (2) Assumes an annual rate on a 30

- day LIBOR of 0.99% plus the current 1.50% margin for a total inte rest rate of 2.49%, net of swap recoveries. (3) As of December 31, 2008, we had a liability for unrecognized tax bene fits of approximately $273K. We are unable to reliably estimate the timing and amount of any payments related to this liability because there are currently no outstanding unpaid assessments from any tax authority, and it is l ikely that assessments would be offset by existing deferred tax attributes as they arise. 

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Recent Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board (the “FA SB”) issued Statement of Financial Accounting Standards No. 141R, “Business Combinations (Revised 2007)” (“SFAS 141R” ), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines w hat information to disclose to enable users of the

financial statements to evaluate the nature and financial effect s of the business combination. SFAS 141R is to be applied prospectively to business combinations for which the acquisition date i s on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. We will evaluate the impact of SFAS 141R on our consolidated financial statements for any potential business combinations subsequent to Jan. 1, 2009.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Val ue Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB 115” (“SFAS 159”). This standard permits an entity to measure financial

instruments and certain other items at estimated fair value . Most of the provisions of SFAS 159 are elective; however, the amendment to FASB 115, “Accounting for Certain Investments in Debt and Equity Securities,” applies to all entities that own trading and available-for- sale securities. The fair value option created by SFAS 159 pe rmits an entity to measure eligible items at fair value as of specified election dates. The fair va lue option (a) may generally be applied instrument by instrument, (b) is irrevocable unless a new election date occurs, and (c) must be applied to the entire instrument and not to only a portion of the instrument. SFAS 159 is effective as of the beginning of the firs t fiscal year that begins after November 15, 2007. Effective January 1, 2008, we adopted SFAS 159. We did not elect the fair value option for any of our assets or liabilities that did not already require such treatment under other authoritative literat ure.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Intere sts in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolli ng interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated fi nancial statements. SFAS 160 requires that changes in a parent’s ownership interest in a subsidiary be reported as a n equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated fi nancial statements. SFAS 160 must be applied prospectively as of January 1, 2009, except for the presentation and discl osure requirements, which are required to be applied retrospectively for all periods presented. The adoption of SFAS 160 did no t have a material impact on our results of operations, cash flows or financial positions; however, it could i mpact future transactions entered into by us.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about D erivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS 161”). This standar d changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and relate d hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments a nd related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessin g the impact of SFAS 161 on our disclosures relating to derivative instruments and hedging activities. The statement only pr ovides for enhanced disclosure. Therefore, adoption will have no impact on our financial position or results of operations.

In May 2008, the FASB issued Statement No. 162, “The Hierarc hy of Generally Accepted Accounting Principles.” The new standard is intended to improve financial reporting by identifying a con sistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 establishes that the GAA P hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting account ing

55 

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principles for financial statements that are presented in conf ormity with GAAP. Statement 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Audi ting amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted A ccounting Principles.” We do not expect this guidance to have a significant impact on us.

In June 2008, the FASB issued FASB Staff Position No. EITF 03 -6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securitie s” (“FSP EITF 03-6-1”), which addresses whether instruments granted in share-based payment transactions are participating secur ities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share unde r the two class method prescribed under SFAS 128, “Earnings per Share”. FSP 03-6-1 is effective for financial st atements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03 -6-1 is not expected to have a material effect on the Company’s earnings per share calculations.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically t o lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) di sclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) r eport oil and gas reserves using an average price based upon the prior 12-month period rather than period- end prices. The provisions of this final ruling will become effect ive for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk . Our major commodity price risk exposure is to the prices receiv ed for our natural gas production. Realized prices received for our natural gas production are the s pot prices applicable to natural gas. Prices received for natu ral gas are volatile and unpredictable and are beyond our control. At Decem ber 31, 2008, a 10% decrease in the prices received for natural gas production would have had an approximate $2.7 million impa ct on our revenues.

Interest Rate Risk. We have long-term debt subject to the risk of loss associated wit h movements in interest rates. At December 31, 2008, we had $116.5 million outstanding under our revolving cr edit facility. For the year ended December 31, 2008, interest on the borrowings averaged 4.56% per annum. Borrowing avail ability at December 31, 2008 was $63.5 million. All of the debt outstanding under our revolving credit facility accrue s interest at floating or market rates. Fluctuations in

market interest rates will cause our interest costs to fluct uate. Based upon the balance outstanding under our revolving credit facility at December 31, 2008, a 1% increase in market inte rest rates would have increased interest expense and negatively impacted our annual cash flows by approximately $0.8 million. $40 million of the outstanding balance was excluded from our market rate analysis due to lack of interest rate exposure bas ed on the interest rate swaps we have in place.

Foreign Currency Exchange Rate Risk. We have operations in Canada and do not have operations in any other foreign countries. We do not hedge our foreign currency risk and are exposed to f oreign currency exchange rate risk in the Canadian dollar. The effect of changes in the exchange rate may impact our revenues or expenses, as well as the costs of our proved properties. We continue to monitor the foreign currency exchange rat e in Canada and may implement measures to protect against the foreign currency exchange rate risk in the future.

56 

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Index to Financial Statements

Item 8. Financial Statements and Supplementary Data

GEOMET, INC. AND SUBSIDIARIES

Index To Financial Statements

57 Page
CONSOLIDATED AUDITED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm 58
Consolidated Balance Sheets as of December 31, 2008 and 2007 59 Consolidated Statements of Operations for the years ended Dece mber 31, 2008, 2007 and 2006 60

Consolidated Statements of Stockholders ’ Equity and Comprehensive Income (Loss) for the years ended December
31, 2008, 2007 and 2006 61 Consolidated Statements of Cash Flows for the years ended Dec ember 31, 2008, 2007 and 2006 62

Notes to Consolidated Audited Financial Statements 63

SUPPLEMENTARY INFORMATION (UNAUDITED)

— Supplemental Financial and Operating Information on Gas Exploration, Development and Production Activities (Unaudited) for the years ended December 31, 2008, 2007 and 2006 87 Quarterly Results of operations (unaudited) by quarter for the year s ended December 31, 2008 and 2007 90 

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Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of GeoMet, Inc.
Houston, TX

We have audited the accompanying consolidated balance sheets of GeoMet , Inc. and subsidiaries (the “Company”) as of
December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years i n the period ended December 31, 2008. We also have audited the Company’s internal control over financial reporting as of Decembe r 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring O rganizations of the Treadway Commission . The Company's management is responsible for these financial stateme nts, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of interna l control over financial reporting, included in the accompanying Management ’s Report on Internal Control Over Financial Reporting . Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Publi c Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial

statements are free of material misstatement and whether effective internal control over financial reporting was mainta ined in all material respects. Our audits of the financial statem ents included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presenta tion. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial repor ting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectivenes s of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered neces sary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a proces s designed by, or under the supervision of, the company’s principal executive and principal financial officers, or pe rsons performing similar functions, and effected by the company’s board of directors, management, and other personnel to pr ovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial repor ting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable det ail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with gener ally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authoriz ations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or tim ely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material eff ect on the financial statements.

Because of the inherent limitations of internal control over fi nancial reporting, including the possibility of collusion or improper management override of controls, material misstatement s due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effe ctiveness of the internal control over financial reporting to fut ure periods are subject to the risk that the controls may become i nadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoMet, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective inter nal control over financial reporting as of December 31, 2008,

based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission

.

As discussed in Note 1 to the consolidated financial statem ents, the Company adopted Financial Accounting Standards Board Interpretations No. 48, “Accounting for Uncertainty in Income Taxe s—an Interpretation of FASB Statement No. 109” on January 1, 2007.

/s/ DELOITTE & TOUCHE LLP

Houston, TX March 12, 2009 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31,

2008 2007 ASSETS

Current Assets: Cash and cash equivalents $ 2,096,561 $ 1,540,516 Accounts receivable, net of allowance of $60,848 and $0, respectively. 5,364,456 4,881,397 Inventory 3,339,228 2,355,595

Derivative asset 6,596,360 2,247,248

Other current assets 541,311 484,341

Total current assets 17,937,916 11,509,097
Gas properties

—

utilizing the full cost method of accounting: Proved gas properties 447,968,536 370,404,336 Unevaluated gas properties, not subject to amortization 5,017 25,174,764 Other property and equipment 3,429,890 2,536,619
Total property and equipment 451,403,443 398,115,719 Less accumulated depreciation, depletion, amortization and impairme nt of gas properties (93,104,323 ) (31,886,633 )
Property and equipment

— net 358,299,120 366,229,086

Other noncurrent assets:

Derivative asset 723,669 90,427

Other 639,648 848,816

Total other noncurrent assets 1,363,317 939,243

TOTAL ASSETS $ 377,600,353 $ 378,677,426

LIABILITIES AND STOCKHOLDERS ’ EQUITY

Current Liabilities: Accounts payable $ 13,384,675 $ 7,536,274

Accrued liabilities 2,623,640 5,087,871

Deferred income taxes 2,426,798 770,675 Derivative liability 714,903 Asset retirement liability 117,423 74,387 Current portion of long

- term debt 111,767 102,586

Total current liabilities 19,379,206 13,571,793

Long

- term debt 117,117,955 96,729,722 Asset retirement liability 4,348,938 2,915,855 Other long

- term accrued liabilities 105,890 138,471 Derivative liability 374,489

Deferred income taxes 43,841,950 46,645,879

TOTAL LIABILITIES 185,168,428 160,001,720
Commitments and contingencies (Note 15)

Stockholders ’ Equity: Preferred stock, $0.001 par value

— authorized 10,000,000, none issued

— — Common stock, $0.001 par value

— authorized 125,000,000 shares; issued and outstanding 39,305,152 and 38,962,359 at December 31, 2008 and December 31, 2007, respectively 39,050 38,962 Treasury stock

— 10,432 shares and 7,828 (93,811 ) (70,452 )

Paid

- in capital 188,692,242 187,620,936 Accumulated other comprehensive (loss) income (2,399,992 ) 2,394,001 Retained earnings 6,422,772 28,909,363

Less notes receivable (228,336 ) (217,104 )

Total stockholders ’ equity 192,431,925 218,675,706 

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59 TOTAL LIABILITIES AND STOCKHOLDERS ’ EQUITY $ 377,600,353 $ 378,677,426 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31,

See accompanying Notes to Consolidated Audited Financial Stat ements. 2008 2007 2006
Revenues:

Gas sales $ 68,313,948 $ 49,694,489 $ 44,805,876 Operating fees and other 780,267 1,289,575 140,922

Total revenues 69,094,215 50,984,064 44,946,798

Expenses: Lease operating expense 14,756,521 13,981,093 11,579,112 Compression and transportation expense 4,498,243 5,209,206 4,498,850

Production taxes 2,136,963 1,164,159 1,037,401 Depreciation, depletion and amortization 10,589,490 9,091,610 7,876,212 Impairment of gas properties 50,733,757

— — General and administrative 9,368,279 9,294,279 6,682,032 Realized losses (gains) on derivative contracts 500,452 (3,895,138 ) (1,118,043 ) Unrealized (gains) losses from the change in market value of open

derivative contracts (4,993,238 ) 3,006,916 (16,877,225 )
Total operating expenses 87,590,467 37,852,125 13,678,339
Operating (loss) income from continuing operations (18,496,252 ) 13,131,939 31,268,459

Other income (expense):

Interest income 43,876 39,341 33,149 Interest expense (net of amounts capitalized) (4,783,076 ) (5,129,847 ) (3,130,005 )

Other 36,961 (58,589 ) (9,773 )
Total other income (expense): (4,702,239 ) (5,149,095 ) (3,106,629 )
(Loss) income before income taxes, minority interest & discontinued operations (23,198,491 ) 7,982,844 28,161,830 Income tax (benefit) expense (711,900 ) 2,987,407 10,865,614
(Loss) income before minority interest & discontinued operations (22,486,591 ) 4,995,437 17,296,216

Discontinued operations: Discontinued operations, net of income tax

— 173,782 22,535 Minority interest, net of income tax

— — ( 22,535 )
Income from discontinued operations

— 173,782

— Net (loss) income $ (22,486,591 ) $ 5,169,219 $ 17,296,216

(Loss) earnings per share: (Loss) income from continuing operations

Basic $ (0.58 ) $ 0.13 $ 0.49

Diluted $ (0.58 ) $ 0.13 $ 0.48

Discontinued operations

Basic $

— $

— $

—
Diluted $

— $

— $

— Net (loss) income per common share

Basic $ (0.58 ) $ 0.13 $ 0.49

Diluted $ (0.58 ) $ 0.13 $ 0.48

Weighted average number of common shares:

Basic 38,856,841 38,822,671 35,018,122

Diluted 38,856,841 39,699,694 35,964,301 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

See accompanying Notes to Consolidated Audited Financial Stat ements.

61 Common

Stock

Par Value $0.001
(shares outstanding) Common

Stock

Par

Value $0.001 Treasury

Stock Paid

- in

Capital Accumulated

Other Comprehensive Income (Loss) Retained

Earnings Notes

Receivable Total

Stockholders’ Equity
Balance at January 1, 2006 29,974,664 $ 29,975 $ — $106,408,915 $ 56,310 $ 6,443,928 $(17,516,8 52) $ 95,422,276

Sale of common stock, 144A and IPO 8,067,023 8,067 81,479,741 81,487,808 Exercise of stock options 637,026 637 1,122,255 1,122,892 Offering costs (2,996,890) (2,996,890) Stock-based compensation 1,328,784 1,328,784 Payments on notes receivable 17,184,357 17,184,357

Accrued interest on notes receivable (489,953) (97,786) (587,739) Comprehensive income:

Net income 17,296,216 17,296,216 Foreign currency translation adjustment, net of income tax of $0 (250,198) (250,198)

Total comprehensive income 17,046,018

Balance at December 31, 2006 38,678,713 $ 38,679 $ — $186,852,852 $ (193,888) $ 23,740,144 $ (430,2 81) $ 210,007,506

Restricted stock awards 178,081 178 (178) — Exercise of stock options 105,565 105 224,660 224,765

Stock

- based compensation 526,575 526,575 Purchase of treasury stock (7,828 shares) (70,452 ) 66,070 (4,382 ) Payments on notes receivable 164,134 164,134

Accrued interest on notes receivable 17,027 (17,027) — Comprehensive income:

Net income 5,169,219 5,169,219 Gain on interest rate swap, net of
income tax of $0 10,884 10,884 Foreign currency translation adjustment, net of income tax of $0 2,577,005 2,577,005

Total comprehensive income 7,757,108

Balance at December 31, 2007 38,962,359 $ 38,962 $ (70,452) $187,620,936 $ 2,394,001 $ 28,909,363 $ (217,104) $ 218,675,706

Exercise of stock options 68,605 69 118,377 118,446 Stock-based compensation 18,720 19 941,697 941,716 Purchase of treasury stock (2,604 shares) (23,359 ) (23,359 )

Accrued interest on notes receivable 11,232 (11,232) — Comprehensive loss:

Net loss (22,486,591) (22,486,591) Loss on interest rate swap, net of income taxes of $410,906 (689,370) (689,370) Foreign currency translation adjustment, net of income taxes of $0 (4,104,623) (4,104,623)

Total comprehensive income (27,280,584)

Balance at December 31, 2008 39,049,684 $ 39,050 $ (93,811) $188,692,242 $ (2,399,992) $ 6,422,772 $ (228,336) $ 192,431,925 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31,

2008 2007 2006 Cash flows provided by operating activities: Net (loss) income $ (22,486,591 ) $ 5,169,219 $ 17,296,216 Adjustments to reconcile net (loss) income to net cash flows provided by operating activities: Depreciation, depletion and amortization 10,589,490 9,265,167 8,033,265 Impairment of gas properties 50,733,757

— — Amortization of debt issuance costs 172,935 146,280 136,394 Deferred income tax (benefit) expense (736,900 ) 3,066,333 10,737,531 Unrealized (gains) losses from the change in market value of open derivative contracts (including premium amortization) (4,993,238 ) 3,006,916 (16,877,225 )

Stock

- based compensation 566,416 311,482 317,298 (Gain) loss on sale of other assets 41,521 (64,834 ) (7,861 ) Accretion expense 365,103 209,850 157,342

Allowance for doubtful accounts 60,848

— — Changes in operating assets and liabilities:

Accounts receivable (595,689 ) 6,111,907 (5,323,795 )

Other current assets (1,058,790 ) (2,348,588 ) (233,821 ) Accounts payable 3,130,996 244,892 5,836,535 Accrued income tax payable

— ( 6,709,656 )

— Other accrued liabilities (2,831,465 ) (922,101 ) 1,400,201
Net cash provided by operating activities 32,958,393 17,486,867 21,472,080
Cash flows used in investing activities: Capital expenditures (including lease acquisitions) (52,797,122 ) (54,026,382 ) (79,060,608 )

Proceeds from sale of assets 43,084 126,285 204,917

Other assets 35,161 67,927 186,553
Net cash used in investing activities (52,718,877 ) (53,832,170 ) (78,669,138 )
Cash flows provided by financing activities:

Debt issuance costs

— ( 100,000 ) (341,730 ) Proceeds from exercise of stock options 118,446 224,765 1,122,892 Equity offering costs

— — ( 2,280,447 )

Proceeds from sales of common stock

— — 81,487,808 Proceeds from revolver borrowings 115,000,000 83,000,000 125,000,000 Payments on revolver (94,500,000 ) (47,000,000 ) (164,000,000 ) Treasury stock (23,359 ) (4,382 )

— Proceeds from notes receivable and accrued interest

— 164,134 17,184,357 Payments on other debt (102,586 ) (93,979 ) (86,563 )
Net cash provided by financing activities 20,492,501 36,190,538 58,086,317 Effect of exchange rate changes on cash and cash equivalents (175,972 ) 280,805 (90,589 )
Increase (decrease) in cash and cash equivalents 556,045 126,040 798,670 Cash and cash equivalents at beginning of year 1,540,516 1,414,476 615,806

Cash and cash equivalents at end of year $ 2,096,561 $ 1,540,516 $ 1,414,476

Supplemental disclosure of cash flow information: Cash paid during the year for: Interest expense $ 4,891,199 $ 5,672,771 $ 3,858,895

Income taxes $ 36,192 $ 25,000 $ 55,000

Significant noncash investing and financing activities: Accrued capital expenditures $ 5,556,897 $ 1,994,186 $ 2,176,475 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS

Note 1—Organization and Our Business

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly G eoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are an indepe ndent natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coal bed methane) and non-conventional shallow gas. Our principal operations and producing properties are located in Alabama, West Virginia, Virginia and Canada.

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation

— The accompanying Consolidated Financial Statements are presented in conformity with accounting principles generally accepted in the United States of Ame rica (“GAAP”) and include our accounts and the accounts of our wholly-owned subsidiaries, GeoMet Operating Company, Inc., Ge oMet Gathering Company LLC, GeoMet Gathering Virginia, Inc., Hudson’s Hope Gas, Ltd and Shamrock Energy LLC. All inter-company accounts and transactions have been

eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

— The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and a ssumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the report ed amounts of revenues and expenses during the reporting period. Our most significant financial estimates are based on remaining proved gas reserves. Estimates of proved gas reserves are key c omponents of our depletion rate for natural gas properties, our unevaluated properties and our full cost ceiling test limitation. I n addition, other significant estimates include estimates used in computing taxes, stock-based compensation, asset retirement obligat ions, fair value of derivative contracts and accrued receivables and payables. Actual results could differ from these estimates.

Gas Properties

— The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the ful l cost method of accounting for gas properties as prescribed by the United States Securities and Exchange Commission ( “SEC”). Under this method, all direct costs and certain indire ct costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into United States of America (“U.S.”) and Canadian cost centers.

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estim ated proved gas reserves.

Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during future reporting periods. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, whi ch would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are li mited to a ceiling equal to the present value of estimated future net revenues, discounted at 10% per annum, plus cost of propert ies not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test t o evaluate whether the net book value of our full cost pool exceeds the cei ling limitation. The ceiling test is performed separately for our U.S. and Canadian cost centers. If capitalized costs (ne t of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairmen t of the full cost pool is required.

63 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

A write-down of the carrying value of the full cost pool is a non-c ash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower de preciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a la ter date.

The ceiling test is calculated using natural gas prices in eff ect as of the balance sheet date and adjusted for “basis” or
location differential, held constant over the life of the rese rves, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test

calculation.

Unevaluated Properties

— The costs directly associated with unevaluated properties and properti es under development are not initially included in the amortization base and relate t o unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination of proved r eserves together with overhead and interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to

the amortization base with the associated leasehold costs on a s pecific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortizat ion base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the

amortization base.

Asset Retirement Liability

— We adopted SFAS 143

, effective January 1, 2003. It establishes accounting and report ing standards for retirement obligations associated with tangible long -lived assets that result from the legal obligation to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed or developed. It requires that the fair value of the liability for asset retirement obligations be recogniz ed in the period in which it is incurred. Upon initial recognition of the asset retirement liability, the asset reti rement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. The liabil ity is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the re lated asset.

Other Property and Equipment

— The cost of other property and equipment is depreciated over the est imated useful lives of the related assets. The cost of leasehold improvements is depreciated over the lesser of the length of the related leases or the estimated useful lives of the assets. Depreciation is computed on the straight-line basis over the following estimated useful lives which range from three to seven years.

Cash and Cash Equivalents

— For purposes of these statements, short-term investments, which ha ve an original maturity of three months or less, are considered cash equivalents.

Inventory

— Inventory consists primarily of materials and supplies used in the de velopment and production of coal bed

methane and is recorded at the lower of cost or market value usi ng the specific identification costing method.

64 Furniture and fixtures 7 years

Automobiles 3 years Machinery and equipment 5 years Software and computer equipment 3 years 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Notes Receivable Included in Stockholders’ Equity

— We have loaned money to officers and employees to purchase our common stock. Such amounts, including accrued interest, are recorded as Notes Receivable, and are included as a component of Stockholders’ Equity. The balances at December 31, 2008 and 2007 are s olely attributable to employees as all notes due from executive officers were paid in January 2006 in accordance wit h the rules and regulations of the SEC. See Note 12 for additional information regarding repayment.

Income Taxes— We record our income taxes using an asset and liability approach in accordance with the provisions of
the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”) as clarified by Financial Accounting Standards Boar d (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes

— an Interpretation of FASB Statement No. 109 (“FIN 48”). This results in the recognition of deferred tax asset s and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under SFAS 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognize d in the year of the enacted change. Deferred tax assets are reduce d by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Estimating the amount of valuation allowance is dependent on estim ates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger l imits on use of net operating losses under Internal Revenue Code Section 382. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOL’s”).

The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 clari fies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS 109, and prescribes a consistent

threshold and measurement attribute for financial statement rec ognition and disclosure of tax positions taken, or expected to be taken, on a tax return. The adoption of this pronouncement did not have a sig nificant impact on the Company’s consolidated

financial statements

Revenue Recognition and Gas Balancing

— We derive revenue primarily from the sale of produced natural gas. W e use the sales method of accounting for the recognition of gas revenue wher eby revenues, net of royalties, are recognized as the production is sold to purchaser. The amount of gas sold may differ fr om 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 proper ties. A ready market for natural gas allows us to sell our natural gas shortly after production at various pipeline re ceipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our nom inations 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 a nd 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 s tatements are generated. Differences are reflected in the accounting period during which payments are received from the purchaser.

Industry Segment and Geographic Information

— We operate in one industry, which is the exploration, development and production of natural gas. Our operational activities are conducted i n the U.S. and Canada with only the U.S. currently having revenue generating operating results.

Concentrations of Market Risk

— Our future results will be affected by the market price of natur al gas. The availability of a ready market for natural gas will depend on numerous factors be yond our control, including

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

weather, production of natural gas, imports, marketing, competiti ve fuels, proximity of natural gas pipelines and other transportation facilities, any oversupply or undersupply of natural ga s, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.

Concentration of Credit Risk

— Financial instruments, which subject us to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative assets. We place our cash investments with highly qualified financial institutions. Risks with respect to receivables as of December 31, 2008 and 2007 arise substantially from the sales of natural gas and joint interest billings. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasona bly estimated. At December 31, 2008, we have recorded an allowance for doubtful accounts receivable of $60,848 related to other revenue and not a purchaser of our natural gas. At
December 31, 2007, we did not record an allowance for doubtful accounts receivable as management had assessed accounts receivable to be recoverable. Risks with respect to derivative assets as of December 31, 2008 arise from cash settlements due to us from our derivative counterparties. We have primarily one purc haser of our natural gas production. We have not experienced any significant losses from uncollectible accounts. We do not believe the loss of our purchaser would materially affect our ability to sell the natural gas we produce as we be lieve other purchasers are available in our area of operations.

Fair Value of Financial Instruments

— The fair value of cash and cash equivalents, current receivables and payables, approximate book value because of the short maturity of these accounts. The outstanding note receivable in Other Non- Current

Assets and certain Other Debt carries a fixed interest rat e. See Notes 5 and 9 for the fair values of the receivable and de bt.

Operating Fees and Other

— Operating fees and other for the years ended December 31, 2008 and 2007 include produced water disposal fees. Operating fees and other for the years e nded December 31, 2006 include fees from operating coal bed methane gas fields from other owners.

Capitalized General and Administrative Expenses

— Under the full cost method of accounting, a portion of our general and administrative expenses that are directly attributable to our a cquisition, exploration and development activities are capitalized as part of our natural gas properties. These capital ized costs include salaries, employee benefits, costs of consult ing services and other costs directly associated with those activi ties. We capitalized general and administrative costs relat ed to our acquisition, exploration and development activities, during the periods e nded December 31, 2008, 2007 and 2006 of $2,329,748, $1,991,760, and $1,174,149, respectively.

Capitalized Interest Costs

— We capitalize interest based on the cost of major development pro jects which are excluded from current depreciation, depletion and amortization calculation s. For the years ended December 31, 2008, 2007 and 2006, we capitalized $304,342, $587,884 and $1,037,576 of interest, respectively. S ee Unevaluated Properties above for additional information on the criteria for including costs in unevaluated propert ies.

Derivative Instruments and Hedging Activities. Our hedging activities consist of derivative instruments entered into to hedge against changes in natural gas prices and changes in interest r ates related to outstanding debt under our credit facility primarily through the use of fixed price swap agreements, basis swa p agreements, three-way collars, and traditional collars. Consistent with our hedging policy, we entered into a series of deri vative instruments to hedge a significant portion of our expected natural gas production through 2009 and 2010. We also entered int o an interest rate swap agreement to hedge interest rates associated with a portion of our variable rate debt through 2010. Typically, these derivative instruments require payments to (receipts from)

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

counterparties based on specific indices as required by the derivat ive agreements. These transactions are recorded in our financial statements in accordance with SFAS No. 133, “Accounting f or Derivative Instruments and Hedging Activities” (“SFAS l33”). Although not risk free, we believe this policy will reduce our exposure to natural gas price fluctuations and changes in interest rates and thereby achieve a m ore predictable cash flow. As a result, our derivative instruments are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. We do not enter into derivative instruments for trading or other speculative purposes.

In accordance with SFAS 133, as amended, all our derivative instrume nts are recorded on the balance sheet at fair value and changes in the fair value of the derivatives are recorded eac h period in current earnings for the natural gas derivatives or other comprehensive income (loss) for our interest rate swaps. The natural gas derivatives have not been designated as hedge transactions while the interest rate swaps qualify and have been designated as such in accordance with SFAS 133.

At the inception of a derivative contract, we may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, we document the relationship between the derivative instrument and the hedged items as well as the risk management objective for entering into the derivati ve instrument. To be designated as a cash flow hedge transaction, the relationship between the derivative and hedge item s must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the de rivative and on an ongoing basis.

Foreign Currency Translation

— For subsidiaries whose functional currency is deemed to be other t han the U.S. dollar, asset and liability accounts are translated at period end excha nge rates and revenue and expenses are translated at average exchange rates prevailing during the period. Translation adjustments ar e included in the Accumulated Other Comprehensive Income (Loss). Any gains or losses on transactions or monetary asset s or liabilities in currencies other than the functional currency are included in net (loss) income in the current period. Our only foreign subsidiary is our Canadian subsidiary, Hudson’s Hope Gas, Ltd.

Stock-Based Compensation

— Prior to January 1, 2006, stock-based employee compensation was accounted for under the intrinsic value method of Accounting Principles Bulletin No. 25, Accounting for Stock Issued to Employees (“APB 25”). The exercise price of the options granted was equal to the estimated m arket value of our common stock at grant date, and therefore, no compensation costs have been recognized. We used the income method on a semi- annual basis to estimate the market value of our common stock at grant date.

Effective January 1, 2006, we adopted the fair value recognition provis ions of SFAS No. 123(R), Share-Based Payment (“SFAS 123(R)”), using the prospective transition method. The applica tion of SFAS 123(R) requires the use of an option pricing model, such as the Black Scholes model, to measure the es timated fair value of the options and as a result various assumptions must be made by management that require judgment and the a ssumptions could be highly uncertain. For sharebased awards outstanding as of January 1, 2006, we will continue using the accounting principles originally applied to those awards before adoption. Therefore, we will not recognize any equit y compensation cost on these prior awards in the future unless such awards are modified, repurchased or cancelled.

Discontinued Operations

— We use the criteria in SFAS No. 144, Accounting for the Impairment or Disposal of LongLived Assets (“SFAS 144”) and EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations (EITF 03-13), to determine whether our components that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS 144, the component being disposed of must have clearly distinguishable operations and cash flows.

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Additionally, pursuant to EITF 03- 13, we must not have significant continuing involvement in the operations after the disposal (i.e. we must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from GeoMet ’s ongoing operations (i.e. we do not expect to generate significant direct cash flows from activities involving t he disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the relate d results of operations for the current and prior periods, including any related impairments, are reflected as Income From Discontinued Operations, net of income tax, in the Consolidated Statements of Operations.

Fair Value Measurement— In September 2006, the FASB issued SFAS No. 157, “Fair Value Mea surements ” (“SFAS 157”). SFAS 157 is effective for fiscal years beginning after November 15, 2007. Effective January 1, 2008, we adopted SFAS 157, which provides a framework for measuring fair value under GAA P. SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liabil ity (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. SFAS 157 also establishe s a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three l evels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identi cal assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs other than quote d prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quot ed prices for similar assets or liabilities; quoted prices i n markets that are not active; or other inputs that are observable or can be corr oborated by observable market data for substantially the full term of the assets or liabilities. Level 3 inputs are derive d from unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the asse ts or liabilities. See disclosure related to the implementa tion of SFAS 157 in Note 6 — Derivative Instruments and Hedging Activities. The FASB has also issued Staff Position FAS 157-2 (“FSP 157-2”), which delays the effective date of SFAS 157 for nonfina ncial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statem ents on a recurring basis (at least annually), until fiscal ye ars beginning after November 15, 2008. We have elected to defer the applicat ion of SFAS 157 thereof to nonfinancial assets and

liabilities in accordance with FSP 157-2. Non- recurring nonfinancial assets and nonfinancial liabilities for which the Company has not applied the provisions of SFAS 157 include those measured at f air value in goodwill impairment testing, asset retirement obligations initially measured at fair value, and thos e initially measured at fair value in a business combination. O n October 10, 2008, the FASB issued Staff Position No. FAS 157-3 (“ FSP 157-3”). FSP 157-3 clarifies the application of SFAS 157 in a market that is not active and provides an example to illustr ate key considerations in determining the fair value of a

financial asset when the market for that financial asset is not active. On January 1, 2009, we will adopt SFAS 157 as it relat es to nonfinancial assets and liabilities, including nonfinancial asse ts and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and ini tial recognition of asset retirement obligations. There has been no significant impact to our consolidated financial stateme nts related to the implementation of SFAS 157 for our existing non-financial assets and liabilities.

Note 3—Recent Accounting Pronouncements

In December 2007, the Financial Accounting Standards Board (the “FA SB”) issued Statement of Financial Accounting Standards No. 141R, “Business Combinations (Revised 2007)” (“SFAS 141R” ), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines w hat information to disclose to enable users of the

financial statements to evaluate the nature and financial effect s of the business combination. SFAS 141R is to be applied prospectively to business combinations

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

for which the acquisition date is on or after the beginning of an enti ty’s fiscal year that begins on or after Dec. 15, 2008. We will apply SFAS 141R in our consolidated financial statements for any business combinations subsequent to Jan. 1, 2009.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Val ue Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB 115” (“SFAS 159”). This standard permits an entity to measure financial

instruments and certain other items at estimated fair value . Most of the provisions of SFAS 159 are elective; however, the amendment to FASB 115, “Accounting for Certain Investments in Debt and Equity Securities,” applies to all entities that own trading and available-for- sale securities. The fair value option created by SFAS 159 pe rmits an entity to measure eligible items at fair value as of specified election dates. The fair va lue option (a) may generally be applied instrument by instrument, (b) is irrevocable unless a new election date occurs, and (c) must be applied to the entire instrument and not to only a portion of the instrument. SFAS 159 is effective as of the beginning of the firs t fiscal year that begins after November 15, 2007. Effective January 1, 2008, we adopted SFAS 159. We did not elect the fair value option for any of our assets or liabilities that did not already require such treatment under other authoritative literat ure.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Intere sts in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolli ng interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated fi nancial statements. SFAS 160 requires that changes in a parent’s ownership interest in a subsidiary be reported as a n equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated fi nancial statements. SFAS 160 must be applied prospectively as of January 1, 2009, except for the presentation and discl osure requirements, which are required to be applied retrospectively for all periods presented. The adoption of SFAS 160 did no t have a material impact on our results of operations, cash flows or financial positions; however, it could i mpact future transactions entered into by us.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about D erivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS 161”). This standar d changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and relate d hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments a nd related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessin g the impact of SFAS 161 on our disclosures relating to derivative instruments and hedging activities. The statement only pr ovides for enhanced disclosure. Therefore, adoption did not have any impact on our financial position or results of operations.

In May 2008, the FASB issued Statement No. 162, “The Hierarc hy of Generally Accepted Accounting Principles.” The new standard is intended to improve financial reporting by identifying a con sistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 establishes that the GAA P hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting account ing principles for financial statements that are presented in conformity with GAAP. Statement 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect this guidance to have a significant impact on us.

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

In June 2008, the FASB issued FASB Staff Position No. EITF 03 -6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securitie s” (“FSP EITF 03-6-1”), which addresses whether instruments granted in share-based payment transactions are participating secur ities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share unde r the two class method prescribed under SFAS 128, “Earnings per Share”. FSP 03-6-1 is effective for financial st atements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03 -6-1 is not expected to have a material effect on the Company’s earnings per share calculations.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically t o lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) di sclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) r eport oil and gas reserves using an average price based upon the prior 12-month period rather than period- end prices. The provisions of this final ruling will become effect ive for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Note 4—Net (Loss) Income Per Share

Net (Loss) Income Per Share of Common Stock

— Basic (loss) income per share is calculated by dividing net (l oss) income by the weighted average number of shares of common stock out standing during the period. No dilution for any potentially dilutive securities is included. Fully diluted net ( loss) income per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net (loss) income by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Dilutive ( loss) income per share considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares

would have an anti-dilutive effect. A reconciliation of the numera tor and denominator is as follows:

Diluted net loss per share for the year ended December 31, 2008 exc luded the effect of outstanding options to purchase 1,757,256 shares and 401,075 restricted shares because we reported a net l oss which caused options to be anti- dilutive. Diluted net income per share for the year ended December 31, 2007 excluded the ef fect of outstanding options to purchase 640,477 shares because the average market price at December 31, 2007 was less than the exercise price. Diluted net income per share for the year ended December 31, 2006 excluded the effect of outstandi ng options to purchase 245,405 shares because the average market price at December 31, 2006 was less than the exerci se price.

71 2008 2007 2006 (Loss) income from continuing operations

Basic $ (0.58 ) $ 0.13 $ 0.49

Diluted $ (0.58 ) $ 0.13 $ 0.48

Discontinued operations

Basic $

— $

— $

—
Diluted $

— $

— $

— Net (loss) income per common share

Basic $ (0.58 ) $ 0.13 $ 0.49

Diluted $ (0.58 ) $ 0.13 $ 0.48

Numerator Net (loss) income available to common stockholders $ (22,486,591 ) $ 5,169,219 $ 17,296,216

Denominator: Weighted average shares outstanding

- basic 38,856,841 38,822,671 35,018,122 Add potentially dilutive securities:

Stock options

— 877,023 946,179

Dilutive securities 38,856,841 39,699,694 35,964,301 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Note 5—Note Receivable

We have an unsecured note receivable of $271,736 and $298,936 as of December 31, 2008 and 2007, respectively, from a third party included in other non-current assets. The note requires payment on a semi-monthly basis, including interest at 8.25%, of $2,168. The fair value of the receivable was $224,700 and $338,000 a t December 31, 2008 and 2007, respectively.

Scheduled maturities of the note receivable are detailed in the table below.

Note 6—Gas Properties

The method of accounting for gas properties determines what costs ar e capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties as prescribed by the SEC.
Under the full cost method, all direct costs and certain indire ct costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated in to U.S. and Canadian cost centers.

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estim ated proved gas reserves.

Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reser ves, which would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are li mited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling limi tation test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling limitation test is imposed separately for our U.S. and Canadian cost centers. If capitalized costs (net of accumulated depreciation, depletion a nd amortization) less related deferred taxes are greater t han the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write- down of the carrying value of the full cost pool is a non-cash charge t hat reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciatio n, depletion and amortization expense in future periods. Once
incurred, a write-down is not reversible at a later date.

The ceiling limitation test is calculated using natural gas pr ices in effect as of the balance sheet date and adjusted for

“basis” or location differential, held constant over the life of the rese rves. In addition, subsequent to the adoption of SFAS 143, the future cash outflows associated with settling asset reti rement obligations are not included in the computation of the discounted present value of future net revenues for the purposes of the c eiling limitation test calculation.

72 2009 $ 29,662

2010 32,346

2011 35,273

2012 38,466

2013 41,947

Thereafter 94,042

Total note receivable 271,736 Less current portion of note receivable 29,662

Non

- current note receivable $ 242,074 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

At December 31, 2008, the carrying value of the Company’s gas propertie s in the U.S. exceeded the full cost ceiling limitation by $19,959,547, net of income tax of $12,087,937, based upon a natural gas price of approximately $5.84 per Mcf in effect at that date. A decline in prices received for gas s ales or an increase in operating costs or reductions in estimate d economically recoverable quantities could result in the recogni tion of an impairment of gas properties in a future period. In the year ended December 31, 2008, the Company recognized an impairment of ga s properties of $19,959,547, net of income tax of $12,087,937. There was no impairment of gas properties recognized in 20 07 and 2006.

At December 31, 2008, the carrying value of the Company’s gas propertie s in Canada exceeded the full cost ceiling limitation by $18,686,273 (no income tax effect as Canadian income taxes are offset by a full valuation allowance), based upon a natural gas price of approximately $5.20 per Mcf in effect at that date. A decline in prices received for gas sales or an increase in operating costs or reductions in estimated economical ly recoverable quantities could result in the recognition of an impairment of gas properties in a future period. In the year ende d December 31, 2008, the Company recognized an impairment of gas properties of $18,686,273. There was no impairment of gas propertie s recognized in 2007 and 2006.

If natural gas prices at March 31, 2009 are below those prices tha t existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas proper ties for the quarter then ended.

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 di spute arose as to whether the preferential right to purchase applied to all the interests we owned in this property or j ust the working interests. We filed a declaratory judgment action asserting that the preferential right to purchase applied onl y to the working interests, and that we were entitled to retain all remaining interests we owned in the property. Following a par tial agreement with the other party, we assigned all our remaining interests in the property to that party, effective July 1, 2008. 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. We have subsequently reached a settlement with the other party in the amount of $475,000, w hich has been accrued as a liability as of December 31, 2008. The proved reserves conveyed represented less than 1% of our total proved reserves.

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

The following table provides a summary of the capitalized cost of our gas properties as of December 31, 2008 and 2007, by the year in which the costs were incurred.

Note 7—Asset Retirement Liability

We record an asset retirement obligation (“ARO”) on the consolida ted balance sheet and capitalize the asset retirement costs in gas properties in the period in which the retirement obli gation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satis fy the obligation using current prices that are escalated by an as sumed inflation factor up to the estimated settlement date, which is then discounted back to the date the abandonment obligation was incurred using an assumed cost of funds for GeoMet. Once the ARO i s recorded, it is then accreted to its estimated future value using the same assumed cost of funds.

The following table describes the changes to our asset retirement liability for the years ending December 31, 2008 and

2007.

Revisions in estimates of our asset retirement liability tot aling $1,040,014 were due primarily to specific lease agreement requirements related to plugging and abandonment of certain wells a nd were capitalized in the full cost pool of our gas properties.

74 2008 2007 Subject to depletion $ 447,968,536 $ 370,404,336 Not subject to depletion: Acquisition costs 5,017 6,182,214 Exploration costs

— 6,695,569

Total 2008 5,017

— Total 2007

— 12,877,783 Total 2006 and prior

— 12,296,981
Total not subject to depletion 5,017 25,174,764
Gross gas properties 447,973,553 395,579,100 Less impairment of gas properties (50,733,757 )

— Less accumulated depletion (40,695,806 ) (30,661,249 )
Net gas properties $ 356,543,990 $ 364,917,851

2008 2007 Asset retirement obligation at beginning of year $ 2,990,242 $ 2,553,801

Liabilities incurred 237,657 247,379

Liabilities settled (124,415 ) (83,385 ) Accretion expense 365,103 241,083

Revisions in estimates 1,040,014

— Currency translation adjustment (42,240 ) 31,364
Asset retirement obligation at end of year 4,466,361 2,990,242 Less: current portion of obligation 117,423 74,387
Long

- term asset retirement obligation $ 4,348,938 $ 2,915,855 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Note 8—Derivative Instruments and Hedging Activities

The energy markets have historically been very volatile, and ther e can be no assurance that natural gas prices will not be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices from time to time primarily using derivative instruments in the form of three-way collars, traditional colla rs and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits fut ure gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for spec ulative positions.

We enter into hedging transactions that increase our statist ical probability of achieving our targeted level of cash flows and at times hedge forward for periods of more than two years. We generally limit the amount of these hedges during any period to no more than 50% to 60% of the then expected gas production for s uch future periods. Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) an d a minimum floor (a bought floor) future price. Three-way costless c ollars are similar to regular costless collars except that , in order to increase the ceiling price, we agree to limit the am ount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting l osses on derivatives during periods where prices are rising and gains during periods where prices are falling which may ca use significant fluctuations in our consolidated statement of operations.

We believe that the use of derivative instruments does not expose us to material risk. However, the use of derivative instruments may materially affect our financial position and re sults of operations as a result of changes in the estimated mar ket value of our natural gas derivatives. Nevertheless, we believe that use of these instruments will not have a material adverse

effect on our cash flows.

The following (gains) losses on our hedging instruments included in the consolidated statements of operations are as

follows:

Commodity Price Risk and Related Hedging Activities.

At December 31, 2008, we had the following natural gas collar posit ions:

75 2008 2007 2006 Realized losses (gains) on derivative contracts $ 500,452 $ (3,895,138 ) $ (1,118,043 ) Unrealized (gains) losses on derivative contracts (4,993,238 ) 3,006,916 (16,877,225 )
Total (gains) $ (4,492,786 ) $ (888,222 ) $ (17,995,268 )

Period Volume (MMBtu) Sold

Ceiling Bought

Floor Sold

Floor Fair

Value January through March 2009 540,000 $ 11.00 $ 8.50 $ 6.25 $ 1,138,548 January through March 2009 540,000 $ 11.00 $ 8.84 $ 6.00 $ 1,403,907 April through October 2009 1,284,000 $ 10.00 $ 7.50 $ 5.25 $ 1,615,808 April through October 2009 1,284,000 $ 10.00 $ 8.50 $ 6.50 $ 1,864,114 November 2009 through March 2010 906,000 $ 11.20 $ 9.50 $ 7.00 $ 1,297,652

Total $ 7,320,029 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Interest Rate Risks and Related Hedging Activities

When we enter into an interest rate swap, we may designate the de rivative as a cash flow hedge, at which time we prepare the documentation required under SFAS 133. Hedges of our interest r ate are designated as cash flow hedges based on whether the interest on the underlying debt is converted to a fixed interes t rate. Changes in derivative fair values that are designated as cash flow hedges are deferred as other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur.

We use fixed rate swaps to limit our exposure to fluctuations in i nterest rates with the objective of realizing a fixed cash
flow stream from these activities. At December 31, 2008, we had the following interest rate swaps:

For the year ended December 31, 2008, there was no ineffective porti on of our cash flow hedges.

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our credit agreement and the col lateral for the outstanding borrowings under our credit agreement is used as collateral for our hedges. We do not have ri ghts to collateral from our counterparties, nor do we have rights of offset against borrowings under our credit agreement.

The application of SFAS 157 currently applies to our derivative inst ruments. Under the provisions of SFAS 157, we estimate the fair value of our natural gas hedges and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discount ed value. SFAS 157 clarifies that a fair value measurement for an asset or liability reflects its nonperfor mance risk, the risk that the obligation will not be fulfilled. Bec ause nonperformance risk includes our counterparties’ and our credit ris k, we have considered the effect of our credit risk on the

fair value of the liabilities stated below. This consideration involved discounting our counterparties’ and our liabilities based on the difference between the S&P credit rating of a comparable co mpany to ours and the 13-week Treasury bill rate, both at December 31, 2008. The following is a description of the valuation m ethodologies used for our derivative instruments

measured at fair value:

76 Description Effective

date Designated

maturity date Fixed rate(1) Notional

amount Fair

Value Floating

- to

- fixed swap 12/14/2007 12/14/2010 3.86 % $ 15,000,000 $ (608,561 ) Floating

- to

- fixed swap 1/3/2008 1/4/2010 3.95 % $ 10,000,000 (243,520 ) Floating

- to

- fixed swap 3/25/2008 3/25/2010 2.38 % $ 10,000,000 (131,102 ) Floating

- to

- fixed swap 5/13/2008 5/13/2010 3.07 % $ 5,000,000 (106,209 )

Total $ (1,089,392 )

(1) The floating rate paid by the counterparty is the British Bankers ’ Association LIBOR rate.

• Natural Gas Hedges

— In order to estimate the fair value of our natural gas hedge positions , a forward price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter (OTC) markets. Pricing estimates f or the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-s ection of industry participants. To extrapolate future cash flows, discount factors incorporating our count erparties’ and our credit standing are used to

discount future cash flows.

• Interest Rate Swaps

— In order to estimate the fair value of our interest rate swa ps, we use a yield curve based on Money Market rates and Interest Rate swaps, extrapolate a fore cast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate ca sh flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap c ash flows. Curve building and discounting techniques used to establish the theoretical market value of 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Based on the use of observable market inputs, we have designated thes e types of instruments as Level 2 for SFAS 157 reporting purposes. The fair value of our derivative instruments at December 31, 2008 and 2007 were as follows:

Note 9—Long-Term Debt

At December 31, 2008, we had a borrowing base of $180 million, matur ing January 6, 2011. On March 12, 2009, the Company’s bank syndicate approved a borrowing base of $140 million after c ompleting its year-end borrowing base determination. The next regular borrowing base determination, which wil l be based on a June 30, 2009 reserve report prepared by the Company, is scheduled to be complete on or before December 16, 2009. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. Our revolving credit facility permi ts us to borrow and repay amounts as needed based on the available borrowing base as determined in the credit agreement. The revolving credit facility is secured by substantially all of our gas properties and the capital stock of our subsidiaries. The bor rowing base under the revolving credit facility is based upon the reserve valuation of our gas properties as of June 30 and Decembe r 31 of each year and other factors deemed relevant by the lenders, including Bank of America as agent. The lenders may a lso request one additional borrowing base re

determination in any fiscal year.

As of December 31, 2008, we had $116.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $63.5 million under our $180 million bor rowing base. For the years ended December 31, 2008 and 2007 we borrowed $115 million and $83 million, respectively, and made payme nts of $94.5 million and $47 million, respectively, under the revolving credit facility. The outstanding ba lances on the revolving credit facility bear interest at the

bank ’s adjusted base rate, which is the bank’s base rate of at least the Federal Funds Rate plus 0.5%, or the adjusted LIBOR rate, plus a margin of 1.00% to 2.00%, based on borrowing base usage. T he rates at December 31, 2008 and 2007, excluding the effect of our interest rate swaps, were 2.49% and 6.29%, respectively.

77 interest bearing securities are based on readily available Mon ey Market rates and Interest Rate swap market data. To extrapolate future cash flows, discount factors incorporating our count erparties’ and our credit standing are used to

discount future cash flows.

2008 2007 Interest rate swap

— asset $

— $ 10,884 Natural gas hedge

— asset 7,320,029 2,326,791

Total derivative assets $ 7,320,029 $ 2,337,675

Interest rate swap

—

liability $ 1,089,392 $

— Natural gas hedge liability

— — Total derivative liabilities $ 1,089,392 $

— 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

The following is a summary of our long-term debt at December 31, 20 08 and 2007:

We are subject to certain restrictive financial and non-financi al covenants under the credit agreement, including a minimum current ratio, adjusted for unrealized (gains) losses on der ivative contracts and borrowing availability, of 1.0 to 1.0, and a rate of consolidated EBITDA to interest expense of up to 2.75 to 1. 0, both as defined in the credit agreement. As of December 31, 2008, we were in compliance with all of the financia l covenants in the credit agreement.

The following were maturities of long-term debt for each of the ne xt five years at December 31, 2008:

The fair value of long-term debt at December 31, 2008 and 2007 is approxim ately $92,485,449 and $83,384,209, respectively. SFAS 157 clarifies that a fair value measure ment for an asset or liability reflects its nonperformance ri sk, the risk that the obligation will not be fulfilled. Because nonperformanc e risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This conside ration involved discounting our long- term debt based on the difference between the S&P credit rating of a comparable company to ours and the stated interest rates of the debt instruments included our long-term debt, both at December 31, 2008.

Note 10—Discontinued Operations

As of September 30, 2007, we discontinued the third-party marketing b usiness and second reportable segment which had been created in connection with the consolidation of Shamrock Energy L LC, a variable interest entity under FIN 46(R) on August 1, 2006. The consolidation of the variable interest entity had no impact

78 December 31,

2008 December 31,

2007 Borrowings under revolving credit facility $ 116,500,000 $ 96,000,000 Note payable to a third party, annual installments of $53,000 through January
2011, interest

- bearing at 8.25% annually, unsecured 135,972 174,570 Note payable to an individual, semi

- monthly installments of $644, through September 2015, interest

- bearing at 12.6% annually, unsecured 118,735 129,240 Salary continuation payable to an individual, semi

- monthly installments of $3,958, through December 2015, non-interest-bearing (less amortization discount of $572,074, with an effective rate of 8.25%), unsecured 475,015 528,498

Total debt 117,229,722 96,832,308

Less current maturities included in current liabilities (111,767 ) (102,586 )
Total long

- term debt $ 117,117,955 $ 96,729,722

Year Amount
2009 $ 111,767

2010 121,792

2011 116,632,744

2012 91,757

2013 100,467

Thereafter 171,195

Total Debt $ 117,229,722 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

on our net income (loss) due to the 100% minority interest to Shamrock E nergy LLC. On January 1, 2007, we exercised our purchase option and acquired 100% of Shamrock Energy LLC, our discontinued gas marketing subsidiary. Over 99% of the net assets acquired were current, approximated their fair val ue and were equal to zero. Shamrock Energy LLC was a low margin business and as a result it did not have a significant impa ct on our results of operations. The acquisition was accounted for as a purchase in accordance with SFAS 141, whereby the purchase price of the net assets acquired was allocated to those

net assets based on their fair value. Goodwill was not recorded bec ause the purchase price approximated the fair value of the net assets acquired.

As a result of exiting the third- party marketing business, we are treating these activities as a discontinued operation for all the periods presented. Results for activities reported as disconti nued operations were as follows:

Statement of Operations Data (for the year ended December 31):

Balance Sheet Data:

Note 11—Income Taxes

We record our income taxes using an asset and liability approach in a ccordance with the provisions of the FASB
Statement No. 109, Accounting for Income Taxes, as clarified by FIN 48. This results in the recognition of defe rred tax assets and liabilities using estimated effective tax rates for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. Under FASB 109, the effect of a change in tax rates of deferred ta x assets and liabilities is recognized in the year of the enac ted change.

79 2008 2007 2006 Gas marketing revenues $

— $ 21,873,248 $ 13,043,598 Purchased gas expense

— ( 21,595,540 ) (12,898,973 ) General and administrative expense

— — ( 254,086 ) Elimination of intercompany profit

— — 146,151 Income from discontinued operations before tax

— 277,708 36,690 Income tax expense

— ( 103,926 ) (14,155 ) Minority interest

— — ( 22,535 )
Income from discontinued operations $

— $ 173,782 $

—

December 31,

2008 December 31,

2007
Assets: Cash and cash equivalents $

— $ 175,398

Accounts receivable

— 15,530

Other

— 14,945

Total assets $

— $ 205,873

Liabilities: Accounts payable $

— $ 86,510

Stockholder ’ s equity

— 119,363

Total liabilities and stockholder ’ s equity $

— $ 205,873 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Estimating the amount of valuation allowance is dependent on estimates of future taxable income, alternative m inimum tax income, and changes in stockholder ownership that could trigger limits on use of net operating losses under Section 382 o f the Internal Revenue Code. We have a significant deferred tax asset associated with net operating loss carryforwar ds (NOL’s). It is more likely than not that we will use the

NOL’s in the U.S. to offset current tax liabilities in fut ure years.

Our effective tax rate differs from the federal statutory rate primarily due to losses in Canada that we are unable to bene fit
from and state income taxes. The Canadian losses, as well as c ertain state losses, are fully reserved because it is more likely

than not that we will not use those NOL’s to offset current t ax liabilities in future years.

Uncertain Tax Positions

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we identified $269,900 of unrecognized tax benefits, largely related to depletion methods used in years prior to 2006 from net deferred tax assets. There was no cumulative effect adjustment to retai ned earnings, our financial condition or results of operations as a result of implementing FIN 48 principally due to the size of our NOL’s. The amount of unrecognized tax benefits has not materially changed and as of December 31, 2008 and 2007 was $272,600.

It is expected that the amount of unrecognized tax benefits may chan ge in the next twelve months; however we do not expect the change to have a significant impact on our results of operat ions or the financial position.

We file a consolidated federal income tax return in the U.S. a nd various combined and separate filings in Canada and several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. federal, state and local, or nonU.S. income tax examinations by tax authorities for years before 2002.

Our continuing practice is to recognize estimated interest rel ated to potential underpayment on any unrecognized tax benefits as a component of interest expense in the consolidated sta tement of operations. Penalties, if incurred, would be recognized as a component of penalty expense. As of the date of adopti on of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the years ended
December 31, 2008 and 2007.

We do not anticipate that total unrecognized tax benefits will signi ficantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2009.

For tax reporting purposes, we have federal and state NOL’s of a pproximately $78,075,499 and $5,890,879, respectively,
at December 31, 2008 that are available to reduce future taxable income. If not utilized, the federal carryforwards would begin to expire in 2022. Certain immaterial portions of the state NOL’s will expire prior to 2022. Our long-term deferred tax asset does not include $7.2 million in deferred tax asset related to our Canadian operations and gas properties as it has been fully

valued in accordance with SFAS 109.

80 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

An analysis of our deferred taxes follows:

Federal income tax expense from continuing operations for each of the year s ended December 31, 2008, 2007, and 2006 was different than the amount computed using the Federal statutory ra te for the following reasons:

The effective tax rate in 2008 of 3.07% was due to the full valuation of the deferred income tax benefit of $6,565,447 related to our Canadian impairment of gas properties recorded in 2008.

The following components of the federal income tax expense for the years ended December 31, 2008, 2007 and 2006 are

as follows:

81 2008 2007
Current deferred tax asset: Compensation expense and other $ 93,012 $ 83,616

Total current deferred tax asset 93,012 83,616 Current deferred tax liability:

Book basis in excess of tax basis of derivative contracts (2,519,810 ) (854,291 )
Net current deferred tax liability $ (2,426,798 ) $ (770,675 )

Long

- term deferred tax asset: Net operating loss carryforward $ 30,937,418 $ 28,972,421 Compensation expense and other 240,993 240,158 Accrued asset retirement obligations 1,051,917 966,442 Alternative minimum tax credit carryforward 115,907 115,907
Total long

- term deferred tax assets 32,346,235 30,294,928 Long

- term deferred tax liabilities:

Book basis in excess of tax basis of derivative contracts (276,442 ) (34,543 ) Book basis of gas properties in excess of tax basis (75,911,743 ) (76,906,264 )
Total long

- term deferred tax liabilities (76,188,185 ) (76,940,807 )
Net long

- term deferred tax liability $ (43,841,950 ) $ (46,645,879 )

2008 % 2007 % 2006 % Amount computed using statutory rates $ (7,887,487 ) 34.00 % $ 2,714,167 34.00 % $ 9,575,022 34.00 %

State income taxes

— net of federal benefit (147,556 ) 0.64 % (84,618 )

- 1.06 % 980,032 3.48 %

Valuation Allowance 7,071,215

- 30.48 % 296,722 3.72 % 204,550 0.73 %

Nondeductible items and other 251,928

- 1.09 % 61,136 0.77 % 106,010 0.38 %
Income tax (benefit) provision $ (711,900 ) 3.07 % $ 2,987,407 37.42 % $ 10,865,614 38.58 %

Years Ended December 31,

2008 2007 2006
Current:

State $ 25,000 $ 25,000 $ 142,238

Federal

— — — Deferred:

State (106,231 ) (109,618 ) 837,794

Federal (630,669 ) 3,072,025 9,885,582
Income tax provision $ (711,900 ) $ 2,987,407 $ 10,865,614 

### Page 86 of 104 Form 10

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Note 12—Common Stock

At December 31, 2008 and 2007, there were 39,049,684 shares and 38,962,359 shares, respectively, of common stock outstanding, including 10,432 shares and 7,828 shares, respectively, of tr easury stock held by the Company. For the years ended December 31, 2008 and 2007, a total of 68,605 and 105,565 shares, respec tively, of common stock were issued upon the exercise of stock options granted under our 2005 Stock Option Plan. In Ma rch 2008, we issued 253,806 shares of restricted stock to key employees, as well as 5 executive officers and two o ther officers, of the Company and 18,720 shares of common stock to our independent directors, representing 50% of their annual retai ner. In September 2008, we issued 46,694 shares of restricted stock to key employees of the Company. The shares of common stock for our independent directors and the restricted stock were issued pursuant to our 2006 Long-Term Incentive Plan. Additionally, for the years ended December 31, 2008 and 2007, 45,032 shares and 31,500 shares of restricted stock, res pectively, were forfeited. No shares of restricted stock were forfeited for the year ended December 31, 2006. For the year ended December 31, 2006, a total of 637,026 shares of common stock were issued upon the exercise of stock options.

Effective January 24, 2006, our board of directors approved a four-for-one common stock split and increased our authorized capital stock from 40,000,000 shares of common stock at Ja nuary 1, 2006 to 135,000,000 shares of capital stock, consisting of 125,000,000 shares of common stock and 10,000,000 shares of preferred stock. Prior periods have been adjusted for the stock split.

On January 30, 2006 and February 7, 2006, we completed private equity offerings of an aggregate 10,250,000 shares of our common stock, consisting of 2,317,023 shares issued by us and 7,932,977 share s sold by certain of our existing stockholders, to qualified institutional buyers exempt from registra tion under the Securities Act. We received aggregate consideration of approximately $28.0 million, or $12.09 per share. We did not receive any proceeds from the shares sold by certain of our existing stockholders. In addition, we received approxi mately $17.5 million from certain of the selling stockholders for repayment of loans from us, including accrued and unpaid i nterest thereon. We used the net proceeds from this private equity offering, together with the proceeds from th e repayment of certain of the selling stockholders’ loans, to repay a portion of the borrowings under our revolving credit facility a nd for general corporate purposes.

On July 27, 2006, we registered for re-sale with the SEC the 10,250, 000 shares of common stock issued in the private equity offering discussed above. Also on July 27, 2006, we sold 5,750,000 sh ares of our common stock under an underwritten initial public offering. Our initial public offering closed on August 2, 2006, and the price per share was $10.00. We received net proceeds of approximately $52.6 million from our initial public offeri ng after deducting estimated offering expenses and underwriting discounts and commissions. We used the net proceeds fr om the initial public offering to reduce outstanding borrowings under our revolving credit facility.

Note 13—Share-Based Awards

Effective January 1, 2006, we adopted the fair value recognition provis ions of Statement of Financial Accounting Standards No. 123(R), “ Share-Based Payment”, using the prospective transition method. For sha re-based awards outstanding as of January 1, 2006, we will continue using the accounting principles originally applied to those awards before adoption. Therefore, we will not recognize any equity compensation cost on the se prior awards in the future unless such awards are modified, repurchased or cancelled.

As of December 31, 2008, we have two stock-based award plans authori zed, our 2005 Stock Option Plan and our 2006 Long-Term Incentive Plan. However, we will not grant any additional awards under our 2005 Stock Option Plan now that we have adopted our 2006 Long-Term Incentive Plan, although we will continue to issue shares of our common stock upon exercise of awards previously granted under the 2005 Stock Option Plan.

82 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Our 2006 Long-Term Incentive Plan authorized the granting of incentive st ock options, non- qualified stock options, stock appreciation rights, stock awards, restricted stock, restricte d stock units and performance awards. A maximum of 2,000,000 shares is available for grant under this plan. The 2006 Long-Term Inc entive Plan is available to our employees and independent directors and is designed to attract and retain employees and independent directors, to further align the interests of our employees and independent directors with the interests of our stoc kholders, and to closely link compensation with our performance. The exercise price of stock options granted under this pla n may not be less than the fair market value of the common stock on the date of grant. The options generally have a term of seven years and vest evenly over three years, except performance based awards and options issued to directors. Performance based awards granted under the 2006 Long-Term Incentive Plan vest once the performance criteria have been met. Options issued to our directors vest immediately.

In March 2007, we granted 168,975 share-based stock option awards and in June 2007 we granted 138,000 restricted stock awards to certain of our non-executive employees with time ves ting criteria. In September 2007 we granted 219,279 share-based stock option awards and we also granted 30,145 restricted st ock awards, including 20,145 with performance- based vesting to our named executive officers and two other officers. I n November 2007 we granted 19,841 incentive stock options, 20,000 restricted stock awards and 40,159 non-qualified stock options to a n officer that vest on March 15, 2010. In March 2008, we granted 164,604 restricted stock awards with time vesting criteria to certain key employees, including our four executive officers. Additionally, we granted 89,202 restricted stock awards with performance vesting criteria to our four executive officers and two other officers. We also granted 18,720 sha res of common stock to our independent directors, representing 50% of their annual retainer. In September 2008, we gra nted 46,694 restricted stock awards with time vesting criteria to certain key employees.

During 2007, we recorded a compensation expense accrual of $526,576 which w as allocated among lease operating expenses ($118,830), general and administrative expenses ($118,830), and c apitalized to unevaluated gas properties ($215,093). During 2008, we recorded a compensation expense accrual of $941,697 w hich was allocated among lease operating expenses ($53,737), general and administrative expenses ($512,680) , and capitalized to unevaluated gas properties ($375,280). The future compensation cost of all the outstanding awards i s $ 1,714,327 which will be amortized over the vesting period of such stock options and restricted stock. The weight ed average remaining useful life of the future compensation cost is 1.41 years.

For the year ended December 31, 2008, no stock options were granted. For t he year ended December 31, 2007, the significant assumptions used in determining the compensation costs inc luded a dividend yield of 0%, expected volatility of 40.20%, risk-free interest rate of 4.02%, an expected term of 4.5 ye ars, forfeiture rates from 5% to 15%, and no expected dividends. For the year ended December 31, 2006, the significant assump tions used in determining the compensation costs included a dividend yield of 0%, expected volatility of 36.95%, ri sk-free interest rate of 4.87%, an expected term of 4.5 year s, forfeiture rates from 5% to 15%, and no expected dividends.

83 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

Incentive Stock Options

The table below summarizes incentive stock option activity for t he year ended December 31, 2008:

During the year ended December 31, 2008, no incentive stock options were granted. The weighted average grant- date fair value of incentive stock options granted during the years 2007 and 2006 was $2.32 and $4.85, respectively. The total intrinsic value of incentive stock options exercised during the years ended Decembe r 31, 2008, 2007, and 2006 was $0.6 million, $0.5 million and $5.2 million, respectively.

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the year ended December 31, 2008:

During the years ended December 31, 2008 and 2007, no non- qualified stock options were granted or exercised. The total

intrinsic value of non- qualified stock options exercised during the year ended December 31, 2006 was $1.7 million. During the year ended December 31, 2008, no non -qualified stock options were granted. The weighted average grant-dat e fair value of non-qualified stock options granted during the years 2007 and 2006 was $1.18 an d $4.96, respectively.

Restricted Stock Awards

The table below summarizes non-vested restricted stock awards a ctivity for the year ended December 31, 2008:

84 Number of

Options Weighted

Average

Exercise

Price Average

Remaining

Contractual

Life Aggregate

Intrinsic

Value Outstanding at December 31, 2007 682,277 $ 6.96

Forfeited (136,503 ) $ 5.63

Exercised (68,605 ) $ 1.72
Outstanding at December 31, 2008 477,169 $ 8.09 4.43 $ 4,008

Options exercisable at December 31, 2008 279,126 $ 7.84 3.83 $ 4,008

Number of Options Weighted

Average

Exercise

Price Average

Remaining

Contractual

Life Aggregate

Intrinsic

Value Outstanding at December 31, 2007 1,311,055 $ 4.02

Forfeited (30,968 ) $ 10.22
Outstanding at December 31, 2008 1,280,087 $ 3.87 4.32 $

— Options exercisable at December 31, 2008 1,156,313 $ 3.33 4.20 $

—

Number of Options Weighted

Average Value at

Grant Date

Non

- vested restricted stock at December 31, 2007 173,998 $ 7.21

Granted 300,500 $ 6.34

Forfeited (45,032 ) $ 6.84

Vested (28,391 ) $ 7.23

Non

- vested restricted stock at December 31, 2008 401,075 $ 6.60 

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GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

On April 18, 2007, 4,083 shares of restricted stock vested. The fa ir value of the shares that vested on that date was $35,604. On June 15, 2008, 20,800 shares of restricted stock vested. The fai r value of the shares that vested on that date was $186,576. On September 20, 2008, 5,591 shares of restricted stock vested. T he fair value of the shares that vested on that date was $33,266. On September 24, 2008, 2,000 shares of restricted stock ves ted. The fair value of the shares that vested on that date was $11,760. There has been no vesting of restricted stock other than described above.

Note 14—Profit Sharing Plan

Substantially all of the employees are covered by our profit s haring plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make contributions to the plan by elect ing to defer some of their compensation. We are required to match 100 percent of total contributions up to a total of five percent of their annual compensation. Our matching contribution vests evenly over three years. Our contributions to the Pla n for the years ended December 31, 2008, 2007 and 2006 were $264,305, $170,062 and $137,357, respectively.

Note 15—Commitments and Contingencies

Litigation

—

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with ce rtainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flow s, if any, will be material.

CNX Surface Use Disputes

Buchanan County Dispute. On September 12, 2008, the Virginia Supreme Court issued its decision in this matter in favor of us and PMC, reversing and remanding the matter to the Buchanan Circ uit Court for further action consistent with the decision. The Court held that CNX Gas Company LLC (“CNX”) does not have the exclusive right to transport gas across the Pocahontas Mining Limited Liability Company (“PMC”) property and may not prevent uses of the PMC property that do not conflict with the exercise of CNX’s rights under its CBM lease with PMC. The effect of this ruling is that our pipeline right of way with PMC is valid.

Tazewell County Dispute. On January 19, 2007, CNX obtained a tempor ary injunction against our construction of the same 12-mile pipeline across 1,450 feet of a 32-acre tract in Tazewell County, Virginia. The tract of land in dispute has been owned by a large number of extended family members, from whom we ha ve obtained approximately 81% control of the tract, either through purchases of undivided surface interests in the tra ct or by entering into surface use and right-of-way easement agreements. During our pipeline construction process, CNX purchased a m inority undivided surface interest in the property and filed a lawsuit seeking to enjoin the construction of our Pond Cree k gathering line across the property. We and CNX have since reached a resolution of this dispute. The settlement had no ma terial impact on our financial position, results of operations, or cash flows presented herein.

CNX Antitrust Action

We filed a complaint against CNX and Island Creek Coal Company (“ Island Creek”), an affiliate of CNX, in the Circuit Court of Tazewell County, Virginia on February 14, 2007, in which we s ought damages arising from alleged violations of the Virginia Antitrust Act, tortious interference with contractua l relations with third parties and statutory and common law conspiracy. The suit sought compensatory and consequential damages for all eged violations of the Virginia Antitrust Act, including alleged anticompetitive efforts of CNX to dominate

85 

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Index to Financial Statements

GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—( Continued)

and maintain its control over the market for the production and trans portation of coalbed methane gas from the Oakwood Field in Buchanan County, Virginia and for CNX’s alleged efforts to conspi re and act in concert with Island Creek and others to dominate and maintain control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in violation of the Virginia Antitrust Act and Virgini a statutory and common law. The suit also alleged CNX’s intentional interference with our existing and prospective third-party business relationships in an attempt to harm us and improve CNX’s position and corporate and financial interests. In a ccordance with an opinion issued by the Tazewell Circuit Court in December 2007, we have filed an amended petition that res tates with specificity our claims against CNX and Island Creek, names Cardinal States Gathering Company and CONSOL Energy Inc., the ultimate parent of the other defendants, as additional defendants, and seeks actual damages of $385.6 million. We are seeking treble damages for the alleged violations of the Virginia Antitrust Act, as well as injunctive relief to prevent CNX and other parties from continuing these alleged anticompetitive activities.

Environmental and Regulatory

As of December 31, 2008, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us

.

Operating Lease Commitments

— We have operating leases for office space, office equipment and field compressors expiring in various years through 2014. Future minimum lease commitments as of December 31, 2008 under non-cancelable operating leases having remaining terms in excess of one year ar e as follows:

Total rental expenses under operating leases were approximately $2 ,005,994, $1,542,660 and $1,591,027 for the years ended December 31, 2008, 2007 and 2006, respectively.

Transportation Contracts

— As of December 31, 2008, under the following firm transportation cont racts, we can transport maximum daily volumes of (1) 7,000 MMBtu’s continuing until Oct ober 31, 2010, (2) 10,000 MMBtu’s continuing until October 31, 2011, (3) 15,000 MMBtu’s continuing until April 1, 2022, and (4) 10,000 MMBtu’ s continuing until April 1, 2017. We have a right to extend each of these contracts, in five-ye ar increments, at the maximum tariff rate. As of December 31, 2008, the maximum commitment remaining under the trans portation contracts is approximately $17.7 million.

86 Year Ended December 31, Amount
2009 $ 1,454,665

2010 1,393,872

2011 1,353,290

2012 551,458

2013 311,334

Thereafter 322,380

Total future minimum lease commitments $ 5,386,999 

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Index to Financial Statements

SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION O N GAS

EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This supplemental schedule provides unaudited information pursuant to SF AS No. 69, Disclosures About Oil and Natural Gas Producing Activities , (“SFAS 69”) and certain other information.

Capitalized Costs

— Capitalized costs and accumulated depreciation, depletion, amortiz ation and impairment of gas properties relating to our gas producing activities, all of whic h are conducted within the continental U.S. and Canada, at
December 31, 2008, 2007 and 2006 are summarized below.

We capitalize certain payroll and other internal costs directl y attributable to acquisition, exploration and development activities as part of our investment in natural gas properties ove r the periods benefited by these activities. During the years ended December 31, 2008, 2007 and 2006, these capitalized costs amounted to $2,329,748, $1,991,760 and $1,174,148, respectively. Capitalized costs do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs in 2007 include a $3.0 million purchase price adj ustment for a 2004 acquisition. For the years ended December 31, 2008, 2007 and 2006, interest costs of $304,342, $587,884 and $1,037,576, respectively, were capitalized.

Capitalized Costs Incurred

The following table discloses costs incurred in gas property acquisi tion, exploration and development activities for the years ended December 31, 2008, 2007 and 2006.

87 For the Years Ended December 31,

2008 2007 2006 Unevaluated properties

— U.S. $ 5,017 $ 6,651,594 $ 13,680,374 Unevaluated properties

— Canada

— 18,523,170 12,717,608 Properties subject to amortization

— U.S. 447,968,536 370,404,336 310,011,154
Capitalized costs

— consolidated 447,973,553 395,579,100 336,409,136 Accumulated depreciation, depletion, amortization and impairment of gas properties

— U.S. (91,429,563 ) (30,661,248 ) (21,836,904 )
Net capitalized costs

— consolidated 356,543,990 364,917,852 314,572,232
Net capitalized costs

— Canada 3,844,991 18,523,170 12,717,608 Net capitalized costs

—

U.S. 352,698,999 343,394,682 301,854,624
Net capitalized costs

— consolidated $ 356,543,990 $ 364,917,852 $ 314,572,232

For the Years Ended December 31,

2008 2007 2006 Acquisition costs:

Proved

— U.S. $ 3,153,568 $ 3,827,641 $ 428,729 Unproved

—

U.S. 2,779,865 4,883,982 9,113,502 Exploration costs

— U.S. 6,055,041 1,937,858 2,559,745 Development costs

— U.S. 34,670,459 42,561,606 62,654,438

Total costs incurred

— U.S. 46,658,933 53,211,087 74,756,414 Acquisition costs

- proved

— Canada 65,251

— — Acquisition costs

- unproved

— Canada

— 435,133 1,717,097 Exploration costs incurred

— Canada 51,542 5,523,744 5,119,289 Development costs incurred

— Canada 5,618,726

— — Total costs incurred

— Canada 5,735,519 5,958,877 6,836,386

Total costs incurred

— consolidated $ 52,394,452 $ 59,169,964 $ 81,592,800 

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Index to Financial Statements

Reserves

— The following table summarizes our net ownership interests in es timated quantities of proved gas reserves and changes in net proved reserves, all of which are located in the continental U.S. Reserve estimates for natural gas contained below were prepared by DeGolyer and MacNaughton, independent petroleum engineers.

Users of this information should be aware that the process of est imating quantities of “proved,” “proved developed” and “proved undeveloped” natural gas reserves is very complex, requiri ng significant subjective decisions in the evaluation of all available geological, engineering and economic data for each rese rvoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of product ion under varying economic conditions. Consequently, material revisions (upward or downward) to existing res erve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estima tes reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connect ion with financial statement disclosures.

The following table presents the standardized measure of future net cash flows related to proved gas reserves in accordance with SFAS 69. All components of the standardized measure are from proved reserves, all of which are located entirely within the continental U.S. and Canada. As prescribed by th is statement, the amounts shown are based on prices and
costs at December 31, 2008, 2007 and 2006, and assume continuation of exis ting economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax credits. A discount factor of 10 percent was used to reflect the timi ng of future net cash flows. Extensive judgments are involved in estimati ng the timing of future production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net revenues from proved reserves and the present value thereof may not be materially correct w hen judged against actual subsequent results. Further, since price s and costs do

88 2008 2007 2006 Natural Gas Reserves (Mcf)

— U.S. Proved reserves at beginning of year 350,176,000 325,663,000 262,512,000 Revisions of previous estimates (42,708,000 ) (15,343,000 ) 28,417,000

Extensions and discoveries 17,613,000 46,982,000 39,138,000 Acquisition

— — 1,824,000 Disposition (1,917,000 )

— — Production (7,453,000 ) (7,126,000 ) (6,228,000 )
Proved reserves at end of year 315,711,000 350,176,000 325,663,000
Proved developed reserves at beginning of year 266,943,000 242,918,000 195,139,000

Proved developed reserves at end of year 242,518,000 266,943,000 242,918,000

2008 2007 2006 Natural Gas Reserves (Mcf)

— Canada Proved reserves at beginning of year

— — — Revisions of previous estimates

— — — Extensions and discoveries 3,818,000

— — Acquisition

— — — Disposition

— — — Production

— — — Proved reserves at end of year 3,818,000

— — Proved developed reserves at beginning of year

— — — Proved developed reserves at end of year 3,818,000

— — 

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not remain static, and no price or cost changes have been considered, and future production and development costs are estimated to be incurred in developing and producing the estimated prove d gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves , and the results may not be comparable to estimates disclosed by other gas producers.

Changes in standardized measure relating to proved gas reserves for t he years ended December 31, 2008, 2007 and 2006

are summarized below:

The weighted average prices of gas used with the above tables at De cember 31, 2008, 2007 and 2006 were $5.84, $7.58 and $5.63 per Mcf, respectively.

89 Standardized Measure

— U.S. 2008 2007 2006
Future cash inflows $ 1,844,199,000 $ 2,654,214,000 $ 1,858,104,000 Future production costs (727,785,000 ) (725,272,000 ) (501,955,000 ) Future development costs (105,707,000 ) (106,356,000 ) (101,777,000 )

Future income taxes (290,341,000 ) (602,319,000 ) (410,391,000 )

Future net cash flows 720,366,000 1,220,267,000 843,981,000 10% annual discount to reflect timing of cash flows (413,859,000 ) (724,399,000 ) (484,494,000 )

Standardized measure of discounted future net cash flows $ 306,507,000 $ 495,868,000 $ 359,487,000

Standardized Measure

— Canada 2008 2007 2006
Future cash inflows $ 20,932,000

— — Future production costs (7,126,000 )

— — Future development costs (30,000 )

— — Future income taxes

— — — Future net cash flows 13,776,000

— — 10% annual discount to reflect timing of cash flows (9,936,000 )

— — Standardized measure of discounted future net cash flows $ 3,840,000

— —

Changes in Standardized Measure 2008 2007 2006 Standardized measure at beginning of year $ 495,868,000 $ 359,487,000 $ 632,665,000 Sales and transfers of oil and gas produced

— net of production

cost (46,908,000 ) (29,340,000 ) (27,705,000 ) Net changes in prices and production cost (238,413,000 ) 248,627,000 (412,865,000 )

Extensions and discoveries 17,666,000 58,936,000 63,721,000 Acquisition/disposition (net) (9,708,000 )

— 1,278,000 Net change in development cost 19,685,000 (43,181,000 ) (4,187,000 ) Revision of previous quantity estimates (55,087,000 ) (35,222,000 ) 49,362,000

Accretion of discount before income taxes 66,281,000 52,563,000 88,015,000 Net change in income taxes 125,336,000 (8,678,000 ) 81,343,000 Changes in production rates (timing) and other (64,373,000 ) (107,324,000 ) (112,140,000 )
Subtotal net change (185,521,000 ) 136,381,000 (273,178,000 )
Standardized measure at end of year $ 310,347,000 $ 495,868,000 $ 359,487,000 

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GEOMET, INC. QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Quarterly Results of Operations. The following table sets forth the results of operations by quart er for the years ended December 31, 2008 and 2007 (in thousands):

90 Quarter Ended

Mar. 31 Jun. 30 Sept. 30 Dec. 31
Fiscal Year 2008:

Total revenues $ 15,879 $ 20,904 $ 18,820 $ 13,491 Impairment of gas properties $

— $

— $

— $ ( 50,734 ) Operating (loss) income from continuing operations $ (2,074 ) $ (3,343 ) $ 29,169 $ (42,248 ) Net (loss) income $ (2,142 ) $ (3,177 ) $ 17,482 $ (34,650 ) Net (loss) income per share:

Basic $ (0.05 ) $ (0.08 ) $ 0.44 $ (0.89 )

Diluted $ (0.05 ) $ (0.08 ) $ 0.44 $ (0.89 )

Fiscal Year 2007:

Total revenues $ 12,140 $ 13,763 $ 11,644 $ 13,437 Operating (loss) income from continuing operations $ (702 ) $ 6,085 $ 3,465 $ 4,284 Net (loss) income $ (1,025 ) $ 2,998 $ 1,588 $ 1,608 Net (loss) income per share:

Basic $ (0.03 ) $ 0.08 $ 0.04 $ 0.04

Diluted $ (0.03 ) $ 0.08 $ 0.04 $ 0.04 

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure controls and procedures are controls and other procedures tha t are designed to ensure that information required to be disclosed by us in the reports we file or submit under t he Exchange Act is recorded, processed, summarized, and reported, within the time periods specified by the SEC’s rules and forms and include, without limitation, controls and procedures designed to provide reasonable assurance that information r equired to be disclosed by us is accumulated and communicated to management, including our Chief Executive Officer and C hief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedur es (as such term is defined in Rule 13a-15(e) and 15d15(e) of the Exchange Act) as of December 31, 2008, and, based upon thi s evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the

SEC’s rules and forms.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, inc luding the Chief Executive Officer and Chief
Financial Officer, we have evaluated our internal controls over f inancial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the year ende d December 31, 2008 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Management’s Annual Report On Internal Control Over Financial Reporting

Management of GeoMet, Inc. (the “Company”), including the Company’s C hief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonab le assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published f inancial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect mis statements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that cont rols may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures ma y deteriorate.

Management conducted an evaluation of the effectiveness of internal con trol over financial reporting based on the

Internal Control

—Integrated Framework

issued by the Committee of Sponsoring Organizations of the Treadway C ommission. Based on this evaluation, management concluded that the Company’s int ernal control over financial reporting was effective as
of December 31, 2008.

Houston, Texas March 12, 2009

91

/s/ J. D ARBY S ERÉ /s/ W ILLIAM C. R ANKIN
J. Darby Seré,

Chief Executive Officer William C. Rankin

Chief Financial Officer 

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Item 9B. Other Information

Certain of our non-employee directors and our largest stockholder ma y from time to time have investments in other exploration and production companies that may compete with us. Section 12 2(17) of the Delaware General Corporation Law permits a Delaware corporation, such as GeoMet, to renounce by a ction of its board of directors any interest or expectancy of the corporation in certain opportunities, effectively eliminating the ambiguity in a Delaware corporation’s ability to do so in advance arising out of prior Delaware case law. Under corpora te law concepts of fiduciary duty, our officers and directors generally have a duty to disclose to us opportunities that are relat ed to our business and are generally prohibited from pursuing those opportunities unless we determine that we are not going to pursue them.

On March 12, 2009, we entered into a Business Opportunities Agree ment with two of our non-employee directors and our largest shareholder. This agreement provides that so long as any of these persons, which we refer to as “Designated Parties,” is serving as a member of our board of directors, we renounce in advance any interest or expectancy in any business opportunity, transaction or other matter in and that involves any as pect of the oil and gas exploration, exploitation, development and production other than:

Under the terms of this Business Opportunities Agreement as approved by our board of directors, a Designated Party will not be required to inform us of a business opportunity that he becomes a ware of so long as he did not become aware of the opportunity as a consequence of serving as a member of our board of di rectors. Furthermore, the Designated Party will be permitted to pursue that opportunity even if it is competitive with o ur business. This Business Opportunities Agreement does not prohibit us from pursuing any business opportunity to which we have renounce d any interest or expectancy. It will provide the Designated Parties and their respective affiliates wit h some certainty that opportunities that they independently pursue wil l not be required to be first offered to us.

The form of Business Opportunities Agreement is attached to this For m 10-K as exhibit 10.20.

92 • any business opportunity that is brought to the attention of a Designat ed Party solely in such person ’ s capacity as a director of our company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice or otherwise identified such opportunity; or

• any business opportunity that is identified by a Designated Party solel y through the disclosure of information by or

on behalf of us. 

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by refe rence to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to Dec ember 31, 2008. Pursuant to Item 401(b) of Regulation SK, the information required by this item with respect to our exe cutive officers is set forth in Part I of this report.

Item 11. Executive Compensation

The information required by this item is incorporated herein by refe rence to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to Dec ember 31, 2008.

Item 12. Security Ownership of Certain Beneficial Owners and Managem ent and Related Stockholder Matters

The information required by this item is incorporated herein by refe rence to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to Dec ember 31, 2008.

Item 13. Certain Relationships and Related Transactions, and Director I ndependence

The information required by this item is incorporated herein by refe rence to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to Dec ember 31, 2008.

Item 14. Principal Accountant Fees and Services

The information required by this item is incorporated herein by refe rence to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to Dec ember 31, 2008.

93 

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Index to Financial Statements

PART IV

Item 15. Exhibits and Financial Statement Schedules

List of Documents Filed as Part of this Report

(1) Financial Statements

(2) Financial Statement Schedules

None.

(3) Exhibits:

The following is a list of exhibits filed as part of this Form 10-K. Where so indicated, previously filed exhibits are incorporated herein by reference. [to add “Business Opportunities Agreement”]

94 Page
CONSOLIDATED AUDITED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm 58
Consolidated Balance Sheets as of December 31, 2008 and 2007 59 Consolidated Statements of Operations for the years ended Dece mber 31, 2008, 2007 and 2006 60

Consolidated Statements of Stockholders ’ Equity and Comprehensive Income (Loss) for the years ended December
31, 2008, 2007 and 2006 61 Consolidated Statements of Cash Flows for the years ended Dec ember 31, 2008, 2007 and 2006 62

Notes to Consolidated Audited Financial Statements 63

SUPPLEMENTARY INFORMATION (UNAUDITED)

— Supplemental Financial and Operating Information on Gas Exploration, Development and Production Activities (Unaudited) for the years ended December 31, 2008, 2007 and 2006 87 Quarterly Results of operations (unaudited) by quarter for the year s ended December 31, 2008 and 2007 90

Exhibit No. Description
3.1 Form of Amended and Restated Certificate of Incorporation of GeoMet , Inc. (incorporated herein by

reference to Exhibit 3.1 to the Company’s Registration Statement o n Form S-1 filed on July 25, 2006 (Registration No. 333

- 131716)).

3.2 Amended and Restated Bylaws of GeoMet, Inc. (incorporated herei n by reference to Exhibit 3.1 to the

Company ’ s 8

- K filed on November 13, 2007 (Registration No. 000

- 52155)).

4.1 Registration Rights Agreement between GeoMet, Inc. and Banc of Am erica Securities LLC, dated as of

January 30, 2006 (incorporated herein by reference to Exhibit 4.1 to the C ompany’s Registration

Statement on Form S

- 1 filed on February 10, 2006 (Registration No. 333

- 131716)).

10.1 2005 Stock Option Plan of GeoMet Inc., dated April 15, 2005 (incorporated he rein by reference to

Exhibit 10.2 to the Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333

- 131716)).

10.2 Form of Incentive Stock Option Agreement for the 2005 Stock Option Pl an of GeoMet, Inc.

(incorporated herein by reference to Exhibit 10.3 to the Company’s R egistration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333

- 131716)). 

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95 Exhibit No. Description
10.3 Federal Income Tax Allocation Agreement among the Members of the GeoMet Resources, Inc.

Consolidated Group, dated as of January 1, 2001 (incorporated herein by r eference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 filed on February 10, 200 6 (Registration No. 333- 131716)).

10.4 Incentive Bonus Pool Plan, dated as of May 29, 2001 (incorporated herei n by reference to Exhibit 10.5 to

the Company’s Registration Statement on Form S-1 filed on Februa ry 10, 2006 (Registration No. 333- 131716)).

10.5 Employment Agreement dated as of December 7, 2000 between GeoMet Res ources, Inc. and William C.

Rankin (incorporated herein by reference to Exhibit 10.6 to the Company ’s Registration Statement on

Form S

- 1 filed on February 10, 2006 (Registration No. 333

- 131716)).

10.6 Employment Agreement dated as of December 7, 2000 between GeoMet Res ources, Inc. and J. Darby

Seré (incorporated herein by reference to Exhibit 10.7 to the Company’ s Registration Statement on Form

S

- 1 filed on February 10, 2006 (Registration No. 333

- 131716)).

10.7 Third Amended and Restated Credit Agreement dated June 9, 2006, among G eoMet, Inc., Bank of

America, N.A., as Administrative Agent, and BNP Paribas, a s Syndication Agent (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 filed on June 21, 2006 (Registration No. 333

- 131716)).

10.8 GeoMet, Inc. 2006 Long-Term Incentive Plan (incorporated herein by ref erence to Exhibit 10.9 to the Company ’ s Registration Statement on Form S

- 1 filed on May 12, 2006 (Registration No. 333

- 131716)).

10.9 Precedent Agreement dated March 28, 2006 between East Tennessee Natural Gas, LLC and GeoMet, Inc.

(incorporated herein by reference to Exhibit 10.10 to the Company’s Re gistration Statement on Form S-1 filed on May 12, 2006 (Registration No. 333-131716)) (portions of this exhi bit have been omitted and filed separately with the Securities and Exchange Commission purs uant to a request for confidential

treatment in accordance with Rule 406 under the Securities Ac t).

10.10 Option Agreement dated June 13, 2006 between Jon M. Gipson and GeoMet, Inc . (incorporated herein by

reference to Exhibit 10.11 to the Company’s Registration Statement on Form S-1 filed on June 21, 2006 (Registration No. 333

- 131716)).

10.11 Amendment No. 1 to 2006 Long

- Term Incentive Plan dated effective as of March 13, 2007 (incorporat ed

herein by reference to Exhibit 10.12 to the Company’s 10-K filed on March 20, 2007 (Registration No.

000

- 52155)).

10.12 Amendment to Employment Agreement dated March 13, 2007 between GeoMet , Inc. and J. Darby Seré

(incorporated herein by reference to Exhibit 10.13 to the Company’s 10 -K filed on March 20, 2007 (Registration No. 000

- 52155)).

10.13 Amendment to Employment Agreement dated March 13, 2007 between GeoMet , Inc. and William C.

Rankin (incorporated herein by reference to Exhibit 10.14 to the Company ’s 10- K filed on March 20, 2007 (Registration No. 000

- 52155)).

10.14* Employee Cash Bonus and Stock Award Retention Agreement dated November 9, 2007 between GeoMet, Inc. and Tony Oviedo.

10.15* Second Amendment to Employment Agreement dated effective as of D ecember 31, 2008 between

GeoMet, Inc. and J. Darby Seré.

10.16* Second Amendment to Employment Agreement dated effective as of D ecember 31, 2008 between

GeoMet, Inc. and William C. Rankin. 

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Index to Financial Statements

96 Exhibit No. Description
10.17 Stock Acquisition and Stockholders Agreement dated December 7, 2000 by a nd among GeoMet

Resources, Inc., Yorktown Energy Partners IV, L.P., J. Darby Seré, and William C. Rankin (incorporated by reference to Exhibit 4.3 of the Company ’s Registration Statement on Form S-8, File No. 333-136924 filed on August 28, 2006).

10.18* Form of Amended and Restated Non

- Qualified Stock Option Agreement dated December 2, 2008.

10.19* Form of Stock Option Award Agreement for the GeoMet, Inc. 2006 Long

- Term Incentive Plan.

10.20* Business Opportunities Agreement among GeoMet, Inc. and the other s ignatories thereto dated

March 12, 2009.

14.1* Corporate Code of Business Conduct and Ethics.

21.1* List of Subsidiaries of GeoMet, Inc.

23.1* Consent of Deloitte & Touche LLP

23.2* Consent of Independent Petroleum Engineers DeGolyer and MacNaughton.

31.1* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes

- Oxley Act of 2002.

31.2* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes

- Oxley Act of 2002.

32* Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Secti on 906 of the Sarbanes

- Oxley Act

of 2002.

* Filed herewith. 

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Index to Financial Statements

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the regis trant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 12, 2009.

In accordance with the Exchange Act, this report has been signed bel ow by the following persons on behalf of the registrants and in the capacities on March 12, 2009.

97 GEOMET, INC.

By: /s/ J. D ARBY S ERÉ

Name: J. Darby Seré

Title: President and Chief Executive Officer

Signature Capacity

/s/ J. D ARBY S ERÉ

J. Darby Seré Chairman of the Board, President, Chief Executive Officer (Principal Executive Officer)

/s/ W ILLIAM C. R ANKIN

William C. Rankin Executive Vice President, Chief Financial Officer (Principal Financial Officer)

/s/ T ONY O VIEDO
Tony Oviedo Vice President, Chief Accounting Officer and Controller

/s/ J. H ORD A RMSTRONG , III

J. Hord Armstrong, III Director

/s/ J AMES C. C RAIN

James C. Crain Director

/s/ S TANLEY L. G RAVES
Stanley L. Graves Director

/s/ C HARLES D. H AYNES
Charles D. Haynes Director

/s/ W. H OWARD K EENAN , J R

.

W. Howard Keenan, Jr. Director

/s/ P HILIP G. M ALONE
Philip G. Malone Director 

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Index to Financial Statements

INDEX TO EXHIBITS

98 Exhibit No. Description
3.1 Form of Amended and Restated Certificate of Incorporation of GeoMet , Inc. (incorporated herein by

reference to Exhibit 3.1 to the Company’s Registration Statement o n Form S-1 filed on July 25, 2006 (Registration No. 333

- 131716)).

3.2 Form Amended and Restated Bylaws of GeoMet, Inc. (incorporated her ein by reference to Exhibit 3.1 to

the Company ’ s 8

- K filed on November 13, 2007 (Registration No. 000

- 52155)).

4.1 Registration Rights Agreement between GeoMet, Inc. and Banc of Am erica Securities LLC, dated as of

January 30, 2006 (incorporated herein by reference to Exhibit 4.1 to the C ompany’s Registration Statement

on Form S

- 1 filed on February 10, 2006 (Registration No. 333

- 134070)).

10.1 2005 Stock Option Plan of GeoMet Inc., dated April 15, 2005 (incorporated he rein by reference to Exhibit

10.2 to the Company’s Registration Statement on Form S-1 filed on Febr uary 10, 2006 (Registration No.

333

- 134070)).

10.2 Form of Incentive Stock Option Agreement for the 2005 Stock Option Pl an of GeoMet, Inc. (incorporated

herein by reference to Exhibit 10.3 to the Company’s Registration St atement on Form S- 1 filed on February 10, 2006 (Registration No. 333

- 134070)).

10.3 Federal Income Tax Allocation Agreement among the Members of the GeoMet Resources, Inc.

Consolidated Group, dated as of January 1, 2001 (incorporated herein by r eference to Exhibit 10.4 to the Company’s Registration Statement on Form S-1 filed on February 10, 200 6 (Registration No. 333- 134070)).

10.4 Incentive Bonus Pool Plan, dated as of May 29, 2001 (incorporated herei n by reference to Exhibit 10.5 to

the Company’s Registration Statement on Form S-1 filed on Februa ry 10, 2006 (Registration No. 333- 134070)).

10.5 Employment Agreement dated as of December 7, 2000 between GeoMet Res ources, Inc. and William C.

Rankin (incorporated herein by reference to Exhibit 10.6 to the Company ’ s Registration Statement on Form

S

- 1 filed on February 10, 2006 (Registration No. 333

- 134070)).

10.6 Employment Agreement dated as of December 7, 2000 between GeoMet Res ources, Inc. and J. Darby Seré

(incorporated herein by reference to Exhibit 10.7 to the Company’s R egistration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333

- 134070)).

10.7 Third Amended and Restated Credit Agreement dated June 9, 2006, among G eoMet, Inc., Bank of America,

N.A., as Administrative Agent, and BNP Paribas, as Syndicati on Agent (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 file d on June 21, 2006 (Registration

No. 333

- 131716)).

10.8 GeoMet, Inc. 2006 Long

- Term Incentive Plan (incorporated herein by reference to Exhibit 10.9 to the

Company ’ s Registration Statement on Form S

- 1 filed on May 12, 2006 (Registration No. 333

- 131716)).

10.9 Precedent Agreement dated March 28, 2006 between East Tennessee Natural Gas, LLC and GeoMet, Inc.

(incorporated herein by reference to Exhibit 10.10 to the Company’s Re gistration Statement on Form S-1 filed on May 12, 2006 (Registration No. 333-131716)) (portions of this exhi bit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment in accordance with Rule 406 under the Securities Act). 

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Index to Financial Statements

99 Exhibit No. Description
10.10 Option Agreement dated June 13, 2006 between Jon M. Gipson and GeoMet, Inc . (incorporated herein

by reference to Exhibit 10.11 to the Company ’s Registration Statement on Form S-1 filed on June 21, 2006 (Registration No. 333

- 131716)).

10.11 Amendment No. 1 to 2006 Long

- Term Incentive Plan dated effective as of March 13, 2007 (incorporat ed

herein by reference to Exhibit 10.12 to the Company’s 10-K filed on March 20, 2007 (Registration No.

000

- 52155)).

10.12 Amendment to Employment Agreement dated March 13, 2007 between GeoMet , Inc. and J. Darby Seré

(incorporated herein by reference to Exhibit 10.13 to the Company’s 10 -K filed on March 20, 2007 (Registration No. 000

- 52155)).

10.13 Amendment to Employment Agreement dated March 13, 2007 between GeoMet , Inc. and William C.

Rankin (incorporated herein by reference to Exhibit 10.14 to the Company ’s 10-K filed on March 20, 2007 (Registration No. 000

- 52155)).

10.14* Employee Cash Bonus and Stock Award Retention Agreement dated November 9, 2007 between GeoMet, Inc. and Tony Oviedo.

10.15* Second Amendment to Employment Agreement dated effective as of D ecember 31, 2008 between

GeoMet, Inc. and J. Darby Seré.

10.16* Second Amendment to Employment Agreement dated effective as of D ecember 31, 2008 between

GeoMet, Inc. and William C. Rankin.

10.17 Stock Acquisition and Stockholders Agreement dated December 7, 2000 by a nd among GeoMet

Resources, Inc., Yorktown Energy Partners IV, L.P., J. Darby Seré, and William C. Rankin (incorporated by reference to Exhibit 4.3 of the Company ’s Registration Statement on Form S-8, File No. 333-136924 filed on August 28, 2006).

10.18* Form of Amended and Restated Non

- Qualified Stock Option Agreement dated December 2, 2008.

10.19* Form of Stock Option Award Agreement for the GeoMet, Inc. 2006 Long

- Term Incentive Plan.

10.20* Business Opportunities Agreement among GeoMet, Inc. and the other s ignatories thereto dated

March 12, 2009.

14.1* Corporate Code of Business Conduct and Ethics.

21.1* List of Subsidiaries of GeoMet, Inc.

23.1* Consent of Deloitte & Touche LLP

23.2* Consent of DeGolyer and MacNaughton.

31.1* Certification of chief financial officer required by Rules 13a

- 14 and 15d

- 14 under the Securities

Exchange Act of 1934.

31.2* Certification of chief executive officer required by Rules 13a

- 14 and 15d

- 14 under the Securities

Exchange Act of 1934.

32* Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Secti on 906 of the Sarbanes-Oxley Act

of 2002.

* Filed herewith. 

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