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

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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 charter) 

 

 

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 seasoned 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 reports required to be filed by Section 13 or 15(d) of the 

Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to 

file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  No 

Indicate by check mark if disclosure of delinquent filers pursuant to 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 SECURITIES EXCHANGE ACT OF 

1934 

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE 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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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a 

smaller reporting company. See the definitions of “large accelerated 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 share, held by non-affiliates (based upon the closing 

sales price on the NASDAQ Global Market on June 30, 2008), the last business 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 incorporated 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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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 Operations 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 Financial 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 STATEMENTS 

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-looking statements. The forward-looking statements may include 

projections and estimates concerning the timing and success of specific 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 largely 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 such estimates and assumptions to be reasonable, 

they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, 

management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forwardlooking statements contained in this annual report are not guarantees of future performance, and we cannot assure any reader 

that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ 

materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” 

section and elsewhere in this annual report. All forward-looking statements speak only as of the date of this annual report. 

Other than as required under the securities laws, we do not intend to publicly update or revise any forward-looking statements 

as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements 

attributable to us, or persons acting on our behalf. The risks, contingencies 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 credit markets; 

• the impairment of financial institutions; 

• changes in general economic conditions, including the performance of financial markets and interest rates, which 

may affect our ability to raise capital and generate operating cash flow; 

• hedging decisions, including whether or not to hedge; 

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

• actions of third party co-owners of interests in properties in which we also own an interest; 

• fluctuations in interest rates and availability of capital; 

• foreign currency fluctuations could negatively affect the profitability of foreign operations; 

• competition in the gas industry; 

• declines in the prices we receive for our gas affecting our operating 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 in this annual report relating to natural gas reserves and 

the estimated future net cash flows attributable to those reserves 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 rules; 

• other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease 

using those techniques or pay royalties; 

• availability of drilling and production equipment and field service providers; 

• disruptions, capacity constraints in, or other limitations on the pipeline 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 properties; and 

• our ability to retain and attract qualified personnel; 

• our joint venture arrangements; 

• the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities 

Exchange Act of 1934; 

• the effects of government regulation and permitting and other legal 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 that 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 accumulated in peat swamps. With increasing depth of 

burial, the plant material undergoes coalification, releasing volatile 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 rank, are lignite, sub-bituminous, high volatile bituminous, 

medium volatile bituminous and low volatile bituminous coals. The range of %VM associated with these coal ranks decrease 

from lignite at approximately 60%VM to low volatile bituminous coals 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 quantities 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 recoverable 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 from new wells on 

undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 

Exploratory well. A well drilled to find and produce oil or natural gas reserves not 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 reservoirs 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 company 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 reserve 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 reserve information is derived directly from line items disclosed 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 Standards (“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 volume 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 using the elapsed time the sample desorbed before its placement into 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 sample 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 varies 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 wellhead 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 sufficient 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 net 

revenues from estimated proved natural gas reserves at a date indicated after deducting estimated production and ad valorem 

taxes, future capital costs and operating expenses, but before deducting 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 future net revenues are discounted at an annual rate of 10% in 

accordance with the practice of the Securities and Exchange Commission (“SEC”), to determine their “present value.” The 

present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being 

the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating 

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

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or 

natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 

Shale. A well hardened, very fine to fine grained sedimentary rock. Shale has ultra-low permeability and is formed from 

the compaction of silt, clay, or mud. Many shales contain a mixture of organic compounds called kerogen, which liberates 

natural gas during the maturation process of the shale. Gas within 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 completed to a point that would permit the 

production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains estimated proved 

reserves. 

Working interest. The operating interest that gives the owner the right to drill, produce 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 exploration 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 in 1985 and have been active as an operator and 

developer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the 

Cahaba Basin in Alabama and the central Appalachian Basin in West Virginia and Virginia. We also control additional 

coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia. 

As of 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 (emphasizing coalbed methane) while maximizing 

stockholder value through the efficient investment of capital to increase reserves, production, cash flow and earnings. We 

believe that substantial expertise and experience is required to develop, produce, and operate coalbed methane and nonconventional shallow gas fields in an efficient manner. We believe that the inherent geologic and production characteristics of 

coalbed methane and non-conventional shallow gas offer significant operational advantages compared to conventional gas 

production. 

Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is 

subject to a variety of risks. For example, our ability to drill on our properties and fund our capital budgets depends, to a large 

extent, upon our ability to generate cash flow from operations at or above current levels and maintain borrowing capacity at or 

near current levels under our revolving credit facility, or the availability of future debt and equity financing at attractive prices. 

Our ability to fund CBM property acquisitions and compete for and retain the qualified personnel necessary to conduct our 

business is also dependent upon our financial resources. Changes in the global economy and in natural gas prices, which may 

affect both our cash flows and the value of our gas reserves, our ability to replace production through drilling activities, a 

material adverse change in our gas reserves due to factors other than gas pricing changes, our ability to transport our gas to 

markets, drilling costs, lower than expected production rates, material adverse outcomes from lawsuits and other factors, many 

of which are beyond our control, may adversely affect our ability to fund our anticipated capital expenditures, pursue property 

acquisitions, and compete for qualified personnel, among other things. 

Our proved natural gas reserves as of December 31, 2008 as estimated 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 current year were calculated using an unescalated natural gas price 

of $5.71 per MMBtu, adjusted for regional price differentials, as compared 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 percent was approximately $352 million at December 31, 

2008 as compared to $663 million at year-end 2007. Although reserves declined 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 Bcf 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 Gurnee field in Alabama and 41% are in the Pond 

Creek and Lasher fields in West Virginia and Virginia. The Peace River project is the first commercial coalbed methane 

project in British Columbia, Canada and there are no other similar producing 

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analogies in the region. As a result, initial proved developed reserves of only 4 Bcf were booked in 2008. Similarly, our 

Garden City project it is the first commercial Chattanooga Shale 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 in cash and a debt-to-book capital ratio of 38%. The 

borrowing base on our revolving credit facility was set at $140 million 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 the 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 tax. 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 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. 

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, results of expenditures and other factors. We routinely adjust 

our capital expenditure budget in response to changes in natural gas prices, drilling and acquisition costs, cash flow, drilling 

results and borrowing base redeterminations under our revolving credit 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 water. The reservoir pressure is reduced by pumping out the water, 

releasing the methane from the molecular structure, which allows 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 their major component. While conventional natural 

gas often has more complex hydrocarbon gases, coalbed methane rarely has more than 2% of the more complex hydrocarbons. 

In the eastern coal fields of the U.S., coalbed methane is generally 98% to 99% pure methane and requires only dehydration of 

the gas to remove moisture to achieve pipeline quality. In the western coal fields of the U.S., it is also sometimes necessary to 

strip out either carbon dioxide or nitrogen. Once coalbed methane has 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 desorption 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 naturally. At greater depths the networks are progressively 

squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the 

coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand proppant is 

pumped into the fractures so that the fractures remain open after 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 throughout 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 classified as proved developed. We are the operator and own a 100% 

working interest in the area. As of December 31, 2008, we had 246 productive 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 approximately 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 been 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 acreage 

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 Alabama 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 pipeline and a gas treatment and compression facility 

through which we gather, dehydrate, and compress our gas for delivery into the Southern Natural Gas pipeline system. As we 

control the gathering and delivery pipeline system, we incur no third party 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 central Alabama. At December 31, 2008, we have 

approximately 72,000 net acres of leasehold. Approximately 1% of our estimated proved reserves, or 1.7 Bcf, were located 

within the field, all of which were classified as proved developed. 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 pipeline 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 southern West Virginia and southwestern Virginia, we have 

the rights to develop approximately 33,000 net CBM acres. At December 31, 2008, approximately 37% of our estimated 

proved reserves, or 117.7 Bcf, were located within the Pond Creek field, of which approximately 77% were classified as 

proved developed. As of December 31, 2008, we are the operator and own an 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 Pocahontas 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 levels 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 dehydration and compression facility and delivered into the 

Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). In January 2007, we executed two longterm transportation agreements with ETNG which became effective 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 southern West Virginia, we have the rights to develop 

approximately 17,000 net CBM acres. At December 31, 2008, approximately 4% of our estimated proved reserves, or 14.1 

Bcf, were located within the Lasher field, of which approximately 42% were classified as proved developed. As of 

December 31, 2008, we are the operator and own a 100% working interest 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-year 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 acres along the Peace River near Hudson’s Hope, 

British Columbia. We have drilled 4 core holes targeting the medium volatile bituminous rank Lower Cretaceous Gething 

coals. Multiple, mostly thin, coal seams, with an aggregate average thickness of 52 feet, exist at depths from 1,000 to 3,000 

feet. The Peace 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, initial 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 River is delivered on a Spectra Energy Corp pipeline. There are 

two primary delivery options, namely Westcoast Station 2 in British Columbia and at Sumas, located near the U.S. and 

Canadian border. We believe we have adequate takeaway capacity to meet our future needs. 

11 

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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 the method prescribed by the SEC which requires the 

application of period-end prices and current costs held constant throughout the projected reserve life. The reserve information 

as of December 31, 2008 is based on estimates made in a reserve report 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 what is generally experienced with non-CBM wells. See “Risk 

Factors” and the notes to our consolidated financial statements included elsewhere in this annual report for a discussion of the 

risks inherent in CBM gas estimates and for certain additional information concerning the estimated proved reserves. 

The weighted average prices of gas at December 31, 2008 used to estimate U.S. and Canadian proved reserves and future 

net revenue were $5.84 per MMBtu and $5.20 per MMBtu, respectively, and was calculated using the Henry Hub NYMEX 

cash price at December 31, 2008 of $5.71 per MMBtu of gas, adjusted 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 revenues from estimated proved reserves 

before income taxes. We believe PV-10 to be an important measure for evaluating the relative significance 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 amount 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 basis. Management also uses PV-10 in evaluating 

acquisition candidates. PV-10 only differs from the standardized measure of discounted future net cash flows (“SMOG”), 

as calculated and presented in accordance with SFAS 69, in that SMOG takes into account the present value of income 

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

Measures.”

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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, developed acreage and productive wells in which we 

own a working interest as of December 31, 2008. Gross represents the total number of acres or wells in which we own a 

working interest. Net represents our proportionate working interest 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 the 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 further drilling until 2010. Otherwise, the remaining 

acreage either has expirations that occur from 2009 through 2013 or the leases 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 gains 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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Drilling Activity 

The following table sets forth the number of completed gross exploratory 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 number 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 fiscal years, the number of completed net exploratory and net 

development wells drilled by us based on our proportionate working interest in such wells. 

 

Title to Properties 

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes 

and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens 

materially interfere with our use of the properties in the operation 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 title to our properties is subject to encumbrances in certain cases, 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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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 geologic and production characteristics of coalbed methane and nonconventional shallow gas offer significant operational advantages compared 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 and reduce costs through economies of scale. 

• Maintain financial discipline. 

• Production Rates. Unlike conventional and unconventional natural gas production, which typically declines after 

initial production is established, production from CBM wells typically increases for the first few years of their 

productive lives although eventual peak rates are often lower than those 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 information 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 compared 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 significantly more gas volumetrically at shallow depths than 

conventional reservoirs. In the early stages of a CBM project development 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 natural gas industry projects. 

• Long-lived Reserves. Because CBM wells typically have inclining production rates early 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 experience 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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Changes in Global Economy 

The global financial and capital markets have been experiencing extreme volatility and disruption, including the failures 

of financial services companies and the related liquidity crisis. 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 such, rely on the credit markets for liquidity and for the 

financing of natural gas exploration. In addition, economic recessions historically result in lower market demand, resulting in 

lower prices. A prolonged period of low gas prices may have a material impact on our cash generation, although in the near 

term this would be mitigated by our hedged position of our natural gas production. 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 operations 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 economic conditions. The consequences of a prolonged 

recession could include a lower level of economic activity and uncertainty 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 financial markets, as a result of recession or otherwise, also 

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 highly fragmented and not dominated by any single producer except 

in the immediate area of our Virginia development operations, where 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 within 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 production 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 Underdeveloped Resource Plays. We pursue those 

projects that leverage our CBM expertise to exploit underdeveloped resource 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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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 Regulatory Commission, or the FERC, does not directly 

regulate any of our operations. However, the FERC’s regulation influences certain aspects of our business and the market for 

our products. In general, the FERC has authority over natural gas companies 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 approach as it considers matters such as pipeline rates and 

rules and policies that may affect rights of access to natural 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 the 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 Pipeline Safety Regulations, including as to reporting, design, 

construction, and operating requirements of the pipeline. We are inspected 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 pipeline that we believe would meet the traditional tests the FERC

has used to establish a pipeline’s status as a gatherer not subject to the FERC’s jurisdiction. However, the distinction between 

the FERC-regulated transmission services and federally unregulated 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 gathering facilities generally includes various safety, 

environmental and, in some circumstances, nondiscriminatory take requirement and complaint based rate regulation. For 

example, we are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers 

to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In certain 

circumstances, such laws will apply even to gatherers like us that do not provide third party, fee-based gathering service and 

may require us to provide such third party service at a regulated rate. Similarly, common purchaser statutes generally require 

gatherers to purchase without undue discrimination as to source of supply 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 gathering 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 activities of interstate pipeline transmission companies and a 

number of such companies have transferred gathering facilities to unregulated 

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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affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state 

or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational 

regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering 

facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot 

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 legislative and regulatory changes. 

Sales of Natural Gas. The price at which we sell natural gas currently is not subject to federal regulation and, for the most 

part, is not subject to state regulation. Our natural gas sales are affected by the availability, terms, and cost of pipeline 

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 transmission companies that remain subject to the FERC’s 

jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The 

stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas 

industry, and these initiatives generally reflect more light handed regulation. We cannot predict the ultimate impact of these 

regulatory changes to our natural gas operations, and we note that some of the FERC’s more recent proposals may adversely 

affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we 

will be affected by any such FERC action materially differently than other sellers of natural gas with whom we compete. 

Virginia Regulation. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to 

coalbed methane absent an express grant of coalbed methane, natural gases, or minerals in general. The situation may be 

different if there is any expression in the severance deed indicating more than mere coal is conveyed. Virginia courts have also 

found that the owner of the coalbed methane did not have the right to fracture the coal in order to retrieve the coalbed methane 

and that the coal operator had the right to ventilate the coalbed methane 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 methane 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 Virginia Gas and Oil Board does not make ownership 

decisions. 

West Virginia Regulation. The West Virginia’s Supreme Court has held that, in a conventional oil and gas lease executed 

prior to the inception of widespread public knowledge regarding coalbed methane operations, the oil and gas lessee did not 

acquire the right to produce coalbed methane. As of December 31, 2008, the West Virginia courts have not clarified who owns 

coalbed methane in West Virginia. Therefore, the ownership of coalbed methane is an open question in West Virginia. West 

Virginia has enacted a law, the Coalbed Methane Wells and Units Act (the “West Virginia Act”), regulating the commercial 

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 ownership disputes to judicial resolution, it contains provisions 

similar to Virginia’s pooling law. Under the pooling provisions of the West 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 participation in the drilling (e.g., royalty or owner) but their consent is not 

required to obtain a pooling order authorizing the production of coalbed methane by the operator within the boundaries of the 

drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that 

title to coal and title to natural gas are vested in different persons, the operator of a coalbed methane well permitted, drilled and 

18 

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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 relating 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 with the coalbed methane operator’s 

group, established the first rules for coalbed methane drilling, development and production operations. The evolution of 

Alabama coalbed methane permits is a continuing process. The coalbed 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 Energy Board 

(“NEB”) and provincial agencies in Canada. These agencies have jurisdiction similar to the FERC for regulation. Business in 

Western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a 

complaints basis. However, the natural gas industry in Canada remains subject to extensive controls and regulations imposable 

by various levels of government. We do not expect that any of these controls 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 regulations that govern land tenure, royalties, 

production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability 

natural gas production. Royalties payable on production from lands other than 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 value 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 Tariffs 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 that 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, quantities, and concentrations of various substances that can 

be released into the environment as a result of natural gas drilling, 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 historical and on-going operations such as the use of pits and plugging of 

abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental 

authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to 

injunction, as well as administrative, civil and even criminal penalties. 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 existing 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 matter, 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 liabilities 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 laws, 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 Superfund law, imposes strict, joint and several liability 

without regard to fault or legality of conduct, on persons who are considered to have contributed to the release of a “hazardous 

substance” into the environment. These persons include the owner or operator of the site where the release occurred and 

companies that disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such 

persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for 

damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring land 

owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous 

substances released into the environment. Although CERCLA currently excludes “petroleum” and “natural gas, natural gas 

liquids, liquefied natural gas or synthetic gas useable for fuel” from the definition of “hazardous substance,” our operations 

may generate materials that are subject to regulation as hazardous substances under CERCLA. 

CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal 

activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, 

under certain circumstances, be required to bear more than its proportional 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 financial liability under these laws involves inherent 

uncertainties. 

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, and comparable 

state programs regulate the management, treatment, storage, and disposal of hazardous and non-hazardous solid wastes. Our 

operations generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. We believe that 

these operations are currently complying in all material respects with applicable RCRA requirements. Although RCRA 

currently exempts certain natural gas and oil exploration and production wastes from the definition of hazardous waste, we 

cannot assure you that this exemption will be preserved in the future, 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 regulations 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 pollutants 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, in 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, spill response plans may also have to be prepared. 

Our CBM exploration and production operations produce substantial volumes of water that must be disposed of in 

compliance with requirements of the CWA, Safe Drinking Water Act, 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 streams and other bodies of water must be authorized in advance 

pursuant to permits issued under the CWA, and disposal of produced water in underground injection wells must be authorized 

in advance pursuant to permits issued under the SDWA. To date, we believe that all necessary surface discharge or disposal 

well permits have been obtained and that the produced water has been disposed in substantial compliance with such permits 

and applicable laws. 

Air Emissions. The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air 

pollutants through the issuance of permits and the imposition of other requirements. 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 regulated by permits issued by state regulatory agencies. To date, we 

believe that no unusual difficulties have been encountered in obtaining air permits, and we believe that our operations are in 

substantial compliance with the CAA and analogous state and local laws 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. Furthermore, 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 resources 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 regulation 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 to implement national programs to reduce emissions of 

certain gases, generally referred to as greenhouse gases that are 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 already adopted legislation addressing greenhouse gas emissions 

from certain greenhouse gas emission sources, primarily power plants. The oil and gas exploration and production industry is a 

direct source of certain greenhouse gas emissions, namely carbon dioxide 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 are 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 Canadian 

federal and provincial laws, rules and regulations, which restrict and prohibit the release or emission and regulate the storage 

and transportation of various substances produced or utilized in association with natural gas industry operations. In addition, 

applicable environmental laws require that well and facility sites 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 fines 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 production 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-time contractors. None of our employees are 

represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our 

employees are satisfactory. 

Corporate Offices 

Our corporate headquarters are located at 909 Fannin, Suite 1850, Houston, Texas 77010. Our technical and operational 

headquarters are located at 5336 Stadium Trace Parkway, Suite 206, Birmingham, Alabama 35244. 

Access to Company Reports 

We file periodic reports, proxy statements and other information with 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 items, 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 nominating, corporate governance and ethics committee 

charter. You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, 

N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the 

SEC at 1-800-SEC-0330. In addition, the SEC maintains an internet site 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 adversely affected. 

Natural gas prices are volatile, and a decline primarily in natural gas prices would significantly affect our financial results 

and impede our growth. 

Our revenue, profitability, and cash flow depend upon the prices and demand for natural gas. The market for natural gas 

is very volatile and even relatively modest drops in prices can significantly 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 control, 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 estimated proved reserves as of December 31, 2008 

were natural gas reserves, our financial results are sensitive to movements in natural gas prices. Recent natural gas prices 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 to 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 price 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 estimated 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 increase, 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 impairment 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 carry 

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 affected 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 for 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 credit 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 could 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, the availability of funds from those markets has diminished 

substantially. Further, arising from concerns about the stability of financial markets 

23 

• overall domestic and global economic conditions; 

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

• weather conditions; 

• technological advances affecting energy consumption; 

• domestic and foreign governmental regulations; 

• proximity and capacity of gas pipelines and other transportation facilities; 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 lending 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 we may incur under our revolving credit facility. 

Moreover, we may be unable to obtain adequate funding under our current credit facility. First, our lenders may be 

unwilling or unable to meet their funding commitments. Second, our borrowing 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 natural 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 available when needed, or is available only on unfavorable terms, 

we may not be able to meet our obligations as they come due or be required to post collateral to support our obligations, or we 

may not be able to implement our development program, grow our existing business 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 adversely impact the value of our common stock. 

Under current federal tax laws, we are entitled to certain deductions relating to our operations, including deductions for 

intangible drilling costs, manufacturing tax deductions and percentage 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 the 

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 legislation or new regulations that may be adopted to address these 

proposals would impact our business, but any such future laws and regulations 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 for our products may be reduced by, climate change legislation 

and regulatory initiatives. 

The United States Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of 

the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce 

emissions of greenhouse gases. In addition, the Environmental Protection Agency has announced possible future regulation of 

greenhouse gas emissions under the Clean Air Act. Depending on the nature 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. 

24 

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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 reserves. 

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 predict the production curve of a coalbed methane field. The 

estimated production profile of a field in the early stage of operations may vary significantly from the actual production profile 

as the field matures. As a result, quantities of estimated proved reserves, projections of future production rates, and the timing 

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. Also, 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 estimates of our reserves, the economically recoverable quantities of 

natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and 

estimates of the future net cash flows. Numerous changes over time 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 the estimated discounted future net cash flows from our estimated 

proved reserves on current prices and costs. However, actual future net cash flows from our gas properties also will be affected 

by factors such as: 

 

 

 

 

 

 

The timing of both our production and our incurrence of expenses in connection 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 use when calculating discounted future net cash flows may not be 

the most appropriate discount factor based on interest rates in effect 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 result of non-cash impairments. 

At December 31, 2008, we recorded a full cost ceiling impairment 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 portion of our full cost pool in future periods which could 

significantly reduce earnings during the period in which the impairment 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 flows. 

Producing natural gas reservoirs are typically characterized by declining production rates that vary depending upon 

reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in 

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 natural 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 acquiring 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 located in two counties in Alabama, one county in West 

Virginia, and one county in Virginia, making us vulnerable to risks associated with having our production concentrated in

a few areas. 

The vast majority of our producing properties are geographically concentrated in two counties in Alabama, one county in 

West Virginia, and one county in Virginia. As a result of this concentration, 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 disasters, 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 pipeline systems may hinder our access to natural gas 

markets or delay our production. 

The availability of a ready market for our natural gas production depends 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 owned by third parties. If we cannot access these thirdparty pipelines, or if transportation of gas through any of these pipelines is disrupted, we may be required to shut in or curtail 

production from some of our wells or seek alternate methods of transportation of our production. If any of these were to occur, 

our revenues would be reduced, which would in turn have a material adverse 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 approximately 72,000 net acres in areas we believe are 

prospective for the Chattanooga Shale. A large portion of the acreage is not currently held by production. Unless production in 

paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, 

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, including drilling results, oil and natural gas prices, the 

availability and cost of capital, drilling and production costs, availability 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-scale 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, and 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 commercially 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 uncertain, 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 drilling success rates could decline. Unsuccessful drilling 

activities could result in higher costs without any corresponding reserves and revenues. 

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to 

implement fully our business plan, which could lead to a decline in reserves and production. 

Historically, we have financed our business plan and operations primarily 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 may have limited ability to obtain the capital necessary to sustain 

our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility 

contains covenants prohibiting our ability to incur additional indebtedness without the consent of the lenders. There can be no 

assurance that our lenders will provide this consent or as to the availability 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 operations 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 result in a curtailment of our operations relating to exploration 

and development of our projects, which in turn could lead to a possible loss 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 services, 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 financing 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 and 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 lenders 

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 assets, engage in mergers, consolidations and acquisitions, enter 

into transactions with affiliates, or pay dividends. We are also required by the terms of our revolving credit facility to comply 

with certain financial ratios. Our revolving credit facility also provides for periodic redeterminations of our borrowing base, 

which may affect our borrowing capacity. Our revolving credit facility 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 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, 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 repayment of our indebtedness or related foreclosure could 

adversely affect our business. 

In addition, the borrowing base under our revolving credit facility is redetermined semi-annually and may be 

redetermined at other times upon request by the lenders under certain 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 companies 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 results 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 ability 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 contain 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 can 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 requirements of applicable regulatory agencies or our 

wells produce water in excess of the applicable volumetric permit 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 additional 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 subsidiary, Hudson’s Hope Gas Ltd. Our 

operations in British Columbia may be adversely affected by currency 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 include, among other things, increases in taxes and 

governmental royalties and changes in laws and policies governing operations of foreign-based companies. Laws and policies 

of the U.S. affecting foreign trade and taxation may also adversely affect our operations in British Columbia. 

We may be unable to retain our existing senior management team and/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 organization to ensure that we continually develop our 

reserves and produce gas at profitable levels. This execution requires an experienced and talented management and operations 

team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives or the members of our 

team that have developed substantial expertise in coalbed methane extraction, 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 William 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 employees 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 personnel required to grow and operate our business profitably. 

Government laws, regulations, and other legal requirements relating to protection of the environment, health and safety 

matters and others that govern our business increase our costs 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 management and disposal of hazardous substances and wastes, the 

clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration 

of mining or drilling properties after mining or drilling is completed, 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 different manner. 

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health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a 

significant effect on our respective costs of operations and competitive 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 result 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 properties, 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 operations, which can be a costly and time consuming 

process and result in restrictions on our operations. 

Regulatory authorities exercise considerable discretion in the timing 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 to prepare and present to federal, state or local 

authorities data pertaining to the effect or impact that proposed exploration 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 parties 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 sure 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 without 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, supplies, 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 shortage 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, supplies, or qualified personnel were particularly severe in the areas 

where we operate, we could be materially and adversely affected. 

30 

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Hedging transactions may limit our potential gains. 

In order to manage our interest rate exposure and natural gas price risks, we have entered into interest rate swaps and 

natural gas price hedging arrangements with respect to a portion of our 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 increase our potential losses. 

We do not insure against all potential risks. We may incur substantial 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 risks and liabilities associated with our business. For some 

risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As 

a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some 

instances, certain insurance may become unavailable or available 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 risks 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 proceeds 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 experience, 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 decrease 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 for 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 significantly. In such case, our ability to raise 

31 

• results of our drilling or the results of drilling by offset operators; 

• 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 securities analysts; 

• acquisitions and financings; 

• quarterly variations in operating results; 

• operating and stock price performance of other companies that investors 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 price favorable to us might be impaired. In addition, our board of 

directors has the authority to issue additional shares of our authorized 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 existing shareholders and may dilute the earnings 

per share of our common stock. 

We have not previously paid dividends on our common stock and we 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 that restrict our ability to pay dividends on our 

common stock. Additionally, any future decision to pay a dividend and the amount 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 Circuit 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 temporary 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 have obtained approximately 81% control of the tract, 

either through purchases of undivided surface interests in the tract or by entering into surface use and right-of-way easement 

agreements. During our pipeline construction process, CNX purchased a minority undivided surface interest in the property 

and filed a lawsuit seeking to enjoin the construction of our Pond Creek gathering line across the property. We and CNX have 

since reached a resolution of this dispute. The settlement had no material 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 sought damages arising from alleged violations of the 

Virginia Antitrust Act, tortious interference with contractual relations with third parties and statutory and common law 

conspiracy. The suit sought compensatory and consequential damages for alleged 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 Buchanan County, Virginia and for CNX’s alleged efforts to 

conspire and act in concert with 

32 

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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 Antitrust Act and Virginia 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 accordance with an opinion issued by 

the Tazewell Circuit Court in December 2007, we have filed an amended 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 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. 

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

None. 

33 

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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 street name for one or more customers who beneficially own 

the shares. Holders of our common stock are entitled to receive dividends if, as and when such dividends are declared by our 

board out of assets legally available therefore after payment of dividends required to be paid on shares of preferred stock, if 

any. We have not declared or paid any dividends on our shares of common stock 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 revolving credit facility prohibits us from paying any 

cash dividends. 

Changes in Securities, Use of Proceeds and Issuer Purchases 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 Act of 1933, as amended, during the fourth quarter of 2008. 

Equity Compensation Plan Information 

The following table summarizes information regarding the number of shares of our common stock that are available for 

issuance under all of our existing equity compensation plans as of December 31, 2008. 

 

34 

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases 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 deemed “soliciting material” or to be “filed” with 

the SEC, nor shall such information be incorporated by reference into 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 December 31, 2008 and compares it with the cumulative 

total return on the Russell 2000 and the S&P Oil and Gas Exploration and Production Index. The comparison assumes $100 

was invested on July 28, 2006 and assumes reinvestment of dividends, if any. The comparisons in this table are required by the 

SEC and are not intended to forecast or be indicative of possible future 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 granted. 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 previously granted. The 1,209,891 of securities 

remaining available for future issuance includes 242,448 shares that were 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 financial 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 reflects a four-for-one common stock split in 2006 and prior 

periods have been adjusted for the stock split. You should read the following data in conjunction with “Management’s 

Discussion and Analysis of Results of Operations and Financial Condition” and our consolidated financial statements and 

related notes included elsewhere in this annual report where there is additional disclosure regarding the information in the 

following table. Our historical results are not necessarily indicative 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 interest, 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, discontinued 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 cumulative 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 properties) $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) realized(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 standardized measure of discounted future net cash 

flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of 

the present value of future net revenues from estimated proved natural 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 investors because it is widely used by professional 

analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can 

impact an individual company when estimating the amount of future income 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 alternative 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 realized gains on derivative contracts. 

(4) Based on the reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers, at each period end. Natural gas prices are volatile and 

may fluctuate widely affecting significantly the calculation of estimated net cash flows. Refer to “Risk Factors” for a more complete discussion. 

(5) See reconciliation of non-GAAP financial measures. 

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 results of operations should be read in conjunction 

with the financial statements and the related notes and other information included elsewhere in this report. 

Overview 

GeoMet, Inc. is an independent energy company primarily engaged in the exploration for and development and 

production of natural gas from coal seams (“coalbed methane” or “CBM”) and non-conventional shallow gas. We were 

originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator and 

developer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the 

Cahaba Basin in Alabama and the central Appalachian Basin in West Virginia and Virginia. We also control additional 

coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia. 

As of 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 estimated 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 current year were calculated using an unescalated natural gas price 

of $5.71 per MMBtu, adjusted for regional price differentials, as compared 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 percent was approximately $352 million at December 31, 

2008 as compared to $663 million at year-end 2007. Although reserves declined 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 Bcf 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 Gurnee field in Alabama and 41% are in the Pond 

Creek and Lasher fields in West Virginia and Virginia. The Peace 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, initial proved 

developed reserves of only 4 Bcf were booked in 2008. Similarly, our Garden City project it is the first commercial 

Chattanooga Shale 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 in cash and a debt-to-book capital ratio of 38%. The 

borrowing base on our revolving credit facility was set at $140 million 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 the 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 tax. Due to limited initial proved reserve bookings in the 

Peace River project we also reported a non-cash 

38 

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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 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 industry. In particular, recent declines in natural gas prices 

and recent economic trends could adversely affect our business, liquidity, results of operations and financial condition. 

Our business is increasingly subject to the adverse trends that have taken place in the global capital markets recently. The 

recent events in the credit and stock markets indicate a high likelihood 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 relationships, 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 downgrades of various financial issuers, unresolved 

issues with structured investment vehicles, deleveraging of financial institutions and hedge funds and dislocation in the interbank market. If significant, continued volatility, changes in interest 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, financial condition or cash flows through realized losses, and 

impairments. 

Although we expect to experience a reduction in the level of our capital spending in 2009, we believe the steps we have 

taken to date in response to the global slowdown in the natural gas industry 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 agreements with industry partners to reduce our costs. 

The natural gas industry is capital intensive. We make, and anticipate that we will continue to make, substantial capital 

expenditures in the exploration for, development and acquisition of natural 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 capital sources depends upon a number of variables, including 

our proved reserves, the volumes of natural gas we produce from existing wells, the prices at which we sell natural gas, our 

ability to acquire, locate and produce new reserves, and events occurring 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 terms 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 demand, market uncertainty, seasonal, political and other 

factors beyond our control. We are unable to accurately predict the prices we receive for our natural gas. Accordingly, any 

significant or sustained declines in natural gas prices may materially adversely affect our financial condition, liquidity, ability 

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 material 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 financial 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 connected 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 through 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 wells were re-stimulated and a horizontal well drilled in the 

second quarter was completed in the third quarter. These three wells were connected to sales in the third quarter with net gas 

sales averaging 0.1 MMcf per day through December 31, 2008. Two vertical test wells drilled in the western portion of the 

prospect are currently shut-in awaiting the identification of adequate water disposal and connection into a gas sales line. 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 Gething 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 dispute arose as to whether the preferential right to 

purchase applied to all the interests we owned in this property or just the working interests. We filed a declaratory judgment 

action asserting that the preferential right to purchase applied only to the working interests, and that we were entitled to retain

all remaining interests we owned in the property. Following a partial agreement with the other party, we assigned all our 

remaining interests in the property to that party, effective July 1, 2008. 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, which 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 operations 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 assets 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 various 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 critical accounting policies involve significant judgments, estimates, 

and a high degree of uncertainty in the preparation of our financial statements: 

Reserves. Our most significant financial estimates are based on estimates of proved gas reserves. Proved gas reserves 

represent estimated quantities of gas that geological and engineering data demonstrate, with reasonable certainty, to be 

recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates 

were made. There are numerous uncertainties inherent in estimating 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 available geologic, geophysical, engineering, and production 

data and, the accuracy of reserve estimates is a function of the 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 unevaluated properties, our rate for recording 

depreciation, depletion and amortization and our full cost ceiling limitation. 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 full 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 indirect 

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 estimated 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 reserves, which would have a significant impact on the depreciation, 

depletion and amortization rate. 

Under full cost accounting rules, total capitalized costs are limited 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 separately for our U.S. and Canadian cost centers. If capitalized 

costs (net 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 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 that reduces 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 prices 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 discounted 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 properties 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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approximately $5.84 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 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, we 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 properties 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 prices 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, we recognized an impairment of our gas properties of 

$18,686,273. 

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. 

Unevaluated Properties—The costs directly associated with unevaluated properties and properties under development 

are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production 

facilities in progress and wells pending determination of proved reserves 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 specific project basis. Costs associated with wells in progress

and wells pending determination are transferred to the amortization 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 reporting 

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 recognized in the period in which it is incurred. Upon initial 

recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the

long-lived asset by the same amount as the liability. The liability is accreted to its then present value each period, and the 

capitalized cost is depreciated over the useful life of the related 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 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 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 estimates of future taxable income, alternative minimum 

tax income, and changes in stockholder ownership that could trigger limits 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 clarifies 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 threshold and measurement attribute for financial statement 

recognition and disclosure of tax positions taken, or expected to be taken, on a tax return. The adoption of this pronouncement 

did not have a significant impact on the Company’s consolidated financial 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 whereby revenues, net of royalties, are recognized as the 

production is sold to purchaser. The amount of gas sold may differ from the amount to which the Company is entitled based on 

its working interest or net revenue interest in the properties. We typically do not have any significant producer gas imbalance 

positions because we own 100% working interest in the majority of our properties. A ready market for natural gas allows us to 

sell our natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the 

buyer. Revenue is recorded when title is transferred based on our nominations and net revenue interests. Pipeline imbalances 

occur when our production delivered into the pipeline varies from the gas we nominated for sale. Pipeline imbalances are 

settled with cash approximately thirty days from date of production and are recorded as a reduction of revenue or increase of 

revenue depending upon whether we are over-delivered or under-delivered. 

Settlements of gas sales occur after the month in which the gas was produced. We estimate and accrue for the value of 

these sales using information available at the time financial statements are generated. Differences are reflected in the 

accounting period during which payments are received from the purchaser. 

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 rates related to outstanding debt under our credit facility 

primarily through the use of fixed price swap agreements, basis swap agreements, three-way collars, and traditional collars. 

Consistent with our hedging policy, we entered into a series of derivative instruments to hedge a significant portion of our 

expected natural gas production through 2009 and 2010. We also entered into 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 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 instruments are recorded on the balance sheet at fair market 

value and changes in the fair market value of the derivatives are recorded 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 derivative instrument. To be designated as a cash flow hedge 

transaction, the relationship between the derivative and hedge items must be highly effective in achieving the offset of changes 

in cash flows attributable to the risk both at the inception of the derivative 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 application 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 and the 

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assumptions could be highly uncertain. For share-based awards outstanding prior to the adoption of SFAS 123(R), we will 

continue using the accounting principles originally applied to those awards before adoption. Therefore, we do not recognize 

any equity compensation cost on these prior awards in the future unless such awards are modified, repurchased or cancelled. 

Fair Value Measurement—In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“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 GAAP. SFAS 157 defines fair value as the exchange price 

that would be received for an asset or paid to transfer a liability (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 establishes 

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 levels of inputs that may be used to measure fair value. Level 1 

inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability 

to access at the measurement date. Level 2 inputs other than quoted prices included within Level 1 that are observable for the 

asset or liability, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that 

are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full 

term of the assets or liabilities. Level 3 inputs are derived from unobservable inputs that are supported by little or no market

activity and that are significant to the fair value of the assets or liabilities. See disclosure related to the implementation 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 nonfinancial assets and liabilities, except for items that are 

recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years 

beginning after November 15, 2008. We have elected to defer the application 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 fair value in goodwill impairment testing, asset 

retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. On 

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 illustrate 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 relates 

to nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business 

combination; impaired property, plant and equipment; goodwill; and initial recognition of asset retirement obligations. There 

has been no significant impact to our consolidated financial statements 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 volumes, production expenses and per Mcf data for the years 

ended December 31, 2008, 2007 and 2006. This table should be read with the discussion 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 gains 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 Statement 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 compared to the prior year. The increase in gas 

sales was a result of both increased gas prices and production. Production increased 5% and average gas prices, excluding 

hedging transactions, increased 32%. The $18.6 million increase in gas sales consisted of a $2.3 million increase in production 

and a $16.3 million increase in average prices. The increase in production was principally attributable to the continued 

development activities at our Pond Creek and Gurnee fields. 

Lease operating expenses. Lease operating expenses increased by $0.8 million, or 6%, to $14.8 million compared to the 

prior year. The $0.8 million increase in lease operating expenses consisted 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 compared to the same 

period in the prior year. The increase in compression expense consisted of a $0.1 million increase in production and a $0.4 

million increase in costs. The $0.4 million increase in costs was 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 transportation expenses resulting from the commencement of 

transportation on our own system from the Pond Creek field and the temporary release of a portion of our firm capacity 

commitments related to our Pond Creek field. 

Production taxes. Production taxes increased by $1.0 million, or 84%, to $2.1 million compared 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 derivative 

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, depletion and amortization increase consisted of a $0.4 

million increase in production and a $1.1 million increase in the depletion rate. 

Impairment of gas properties. At December 31, 2008, the carrying value of the Company’s oil and gas properties 

exceeded the full cost ceiling limitation by approximately $50.7 million. 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 increased general and administrative expenses was increased 

office expense, share based awards and investor relation expense, offset 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 prior year period. Realized losses represent net cash flow 

settlements paid to the counterparty while realized gains represent net cash flow settlement paid to us from the counterparty. 

Realized losses occur when natural gas prices or the derivative index 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 as 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 each reporting period. 

Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) decreased by $0.3 million, or 

7%, to $4.8 million compared to the prior year period. Gross interest 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 compared to an expense of $3.0 million in 

the prior year period. The effective tax rate for the 2008 was 3.1% as compared to 37.4% for 2007. The decrease in the 

effective tax rate was due to the full valuation of the deferred 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 business and second 

reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest 

entity under FIN 46 (R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income 

(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 insignificant impact on our net 

income (loss). As a result of exiting our third party marketing business, we are treating these activities as a discontinued 

operation for all the periods presented. 

47 

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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 compared to the prior year. The increase in gas 

sales was a result of increased production, partially offset by lower average gas prices. Production increased 14% while 

average gas prices, excluding hedging transactions, decreased 3%. The $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 million. The $2.4 million 

increase in lease operating expenses consisted of $1.7 million increase in production and $0.7 million increase in costs. The 

increase in costs is related to an increase in well service 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 transportation). 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 Mcf 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, partially 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 expense (74%) and office expenses and business taxes (6%). 

The largest dollar increase was in employee expenses and professional 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 derivative 

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 losses represent net cash flow settlements paid to the 

counterparty while realized gains represent net cash flow settlement paid to us from the counterparty. Realized losses occur 

when natural gas prices or the derivative index 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) 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 transactions that occur when the corresponding asset or liability 

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

values of derivative assets increase or the fair value of derivative liabilities decrease. Unrealized losses are recognized 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 million, or 

64%, to $5.1 million. The increase was primarily due to higher outstanding 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 decrease 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 principal driver for the difference in the effective tax rate 

was due to lower state income taxes resulting from state apportionment factor shifting. 

Discontinued operations. In September of 2007, we discontinued the third party marketing business and second 

reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest 

entity under FIN 46 (R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income 

(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 insignificant impact on our net 

income (loss). As a result of exiting our third party marketing business, 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 December 31, 2008 of $33.0 million combined together 

with $20.5 million (net) borrowed from our revolving credit facility were sufficient to fund our cash basis capital expenditures 

of $52.8 million. 

As of December 31, 2008, we had a working capital deficit of approximately $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 capital 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, results of expenditures and other factors. We routinely adjust 

our capital expenditure budget in response to changes in natural gas prices, drilling and acquisition costs, cash flow, drilling 

results and borrowing base redeterminations under our revolving credit 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 initial 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, the methods utilized to dispose of produced water, the transportation 

alternatives, and the timing and volume of initial and subsequent natural gas production volumes. 

Based upon current expectations, we believe that we will have adequate resources from cash flows provided by 

operations and from proceeds from our revolving credit facility borrowings to fund our 2008 capital expenditures and other 

working capital needs. 

Currently, there is an unprecedented uncertainty in the financial markets. 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 institutions 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 transactions would 

impact our current credit facility, the possibility does exist. Financial market disruptions may impact our ability to collect trade 

receivables. We constantly monitor the credit worthiness of our customers. 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 intention 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 cash flows are less than anticipated, amounts available for 

borrowing under our revolving credit facility are reduced or we are unable 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 downward movements in natural gas prices. Natural gas prices 

have experienced volatility in recent years in response to changes 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 impact of seasonality and weather, general economic 

conditions, the level of domestic and offshore natural gas production and 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 taxation. 

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 collars and swaps. While the use of these hedging arrangements 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 statistical 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 such future periods. We have historically used 

swaps, costless collars and three-way costless collars in our hedging activities. 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) and a minimum floor (a 

bought floor) future price. Three-way costless collars are similar to regular costless collars 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 these 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 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 results of operations as a result of changes in the estimated market 

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 positions: 

 

Interest Rate Risks and Related Hedging Activities 

When we enter into an interest rate swap, we may designate the derivative as a cash flow hedge, at which time we prepare 

the documentation required under SFAS No. 133, “Accounting for Derivative 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 values that are designated as cash flow hedges are deferred as 

other comprehensive income (loss) 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 interest 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 portion 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 collateral for the outstanding borrowings under our credit 

agreement is used as collateral for our hedges. We do not have rights 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 instruments. 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 discounted value. SFAS 157 clarifies that a fair value 

measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because 

nonperformance risk includes our counterparties’ and our credit risk, 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 company to ours and the 13-week Treasury bill rate, both at 

December 31, 2008. The following is a description of the valuation methodologies 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 these 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 America, 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 rate 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 borrowing 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 credit agreement are secured by first priority liens 

on substantially all of our assets including equity interests in our subsidiaries. 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 minimum current ratio and a minimum interest coverage 

ratio. Our ratio of consolidated current assets (adjusted for unrealized (gains) losses on derivative contracts and borrowing 

availability) to our consolidated current liabilities is not permitted to be less than 1 to 1 as of the end of any fiscal quarter, and 

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 amended credit agreement, excludes other non-cash charges 

deducted in determining net income (loss), which would include unrealized losses from the change in the market value of open 

derivative contracts. In addition, we are subject to covenants restricting or prohibiting cash dividends and other restricted 

payments, transactions with affiliates, incurrence of debt, consolidations 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 factors 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 swaps, we use a yield curve based on 

Money Market rates and Interest Rate swaps, extrapolate a forecast of future interest rates, estimate each future cash 

flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to 

present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting 

techniques used to establish the theoretical market value of interest bearing securities are based on readily available 

Money Market rates and Interest Rate swap market data. To extrapolate 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 proceed against the collateral securing the facility. Any 

acceleration in the repayment of our indebtedness or related foreclosure 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 revolving 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 business, debt service requirements and operating 

lease commitments. The following table summarizes these commitments 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 LLC, a variable interest entity under FIN 46(R) on 

August 1, 2006. The consolidation of the variable interest entity had no impact on our net income (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 insignificant impact on our net income (loss). As a 

result, we are treating our third party marketing activities as a discontinued operation for all the periods presented. 

The marketing activities of Shamrock Energy LLC have been transitioned to GeoMet, Inc without disruption in the 

marketing of our gas, and we do not expect to incur significant liabilities or sell any assets in connection with discontinuing 

this business. As a result, the discontinued operations have an insignificant 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 terms, 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 interest rate of 2.49%, net 

of swap recoveries. 

(3) As of December 31, 2008, we had a liability for unrecognized tax benefits 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 likely 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 “FASB”) 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 what information to disclose to enable users of the 

financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is to be applied 

prospectively to business combinations for which the acquisition date is 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 Value 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 permits an entity to measure eligible items 

at fair value as of specified election dates. The fair value 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 first 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 literature. 

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial 

Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the 

consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires that changes 

in a parent’s ownership interest in a subsidiary be reported as an 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 financial statements. SFAS 160 must be applied 

prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which are required to be applied 

retrospectively for all periods presented. The adoption of SFAS 160 did not have a material impact on our results of 

operations, cash flows or financial positions; however, it could impact future transactions entered into by us. 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an 

amendment of FASB Statement No. 133” (“SFAS 161”). This standard 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 related hedged items are accounted for under Statement 133 and its 

related interpretations, and (c) how derivative instruments and 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 assessing the impact of SFAS 161 on our disclosures relating to 

derivative instruments and hedging activities. The statement only provides 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 Hierarchy of Generally Accepted Accounting Principles.” The 

new standard is intended to improve financial reporting by identifying a consistent 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 GAAP hierarchy should be directed to entities because it is the 

entity (not its auditor) that is responsible for selecting accounting 

55 

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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. 

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 Securities” (“FSP EITF 03-6-1”), which addresses whether instruments 

granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in 

the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128, 

“Earnings per Share”. FSP 03-6-1 is effective for financial statements 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 to lead to reliable conclusions about reserve volumes. In 

addition, the new disclosure requirements require a company to (a) disclose 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) report 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 effective 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 received for our natural gas production. 

Realized prices received for our natural gas production are the spot prices applicable to natural gas. Prices received for natural 

gas are volatile and unpredictable and are beyond our control. At December 31, 2008, a 10% decrease in the prices received 

for natural gas production would have had an approximate $2.7 million impact on our revenues. 

Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. At 

December 31, 2008, we had $116.5 million outstanding under our revolving 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. 

All of the debt outstanding under our revolving credit facility accrues interest at floating or market rates. Fluctuations in 

market interest rates will cause our interest costs to fluctuate. Based upon the balance outstanding under our revolving credit 

facility at December 31, 2008, a 1% increase in market interest 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 based 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 foreign 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 rate 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 December 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 December 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 years ended December 31, 2008 and 2007 90

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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 in the period ended December 31, 2008. We also have audited the 

Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal 

Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The 

Company's management is responsible for these financial statements, for maintaining effective internal control over financial 

reporting, and for its assessment of the effectiveness of internal 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 Public 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 maintained in 

all material respects. Our audits of the financial statements 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 presentation. Our audit of internal control over financial reporting 

included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness 

exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits 

also included performing such other procedures as we considered necessary 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 process designed by, or under the supervision of, the 

company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the 

company’s board of directors, management, and other personnel to provide 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 reporting includes those policies and procedures that 

(1) pertain to the maintenance of records that, in reasonable detail, 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 generally accepted accounting principles, and that receipts and 

expenditures of the company are being made only in accordance with authorizations of management and directors of the 

company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or 

disposition of the company’s assets that could have a material effect on the financial statements. 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or 

improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a 

timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future 

periods are subject to the risk that the controls may become inadequate 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 internal 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 statements, the Company adopted Financial Accounting Standards 

Board Interpretations No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” 

on January 1, 2007. 

/s/ DELOITTE & TOUCHE LLP

Houston, TX 

March 12, 2009 

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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 impairment 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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GEOMET, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF OPERATIONS 

FOR THE YEARS ENDED DECEMBER 31, 

 

See accompanying Notes to Consolidated Audited Financial Statements. 

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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GEOMET, INC. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 

AND COMPREHENSIVE INCOME (LOSS) 

 

See accompanying Notes to Consolidated Audited Financial Statements. 

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 $(17,516,852) $ 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 $ (430,281) $ 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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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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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS 

Note 1—Organization and Our Business 

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the 

laws of the state of Delaware on November 9, 2000. We are an independent 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 America (“GAAP”) and include our accounts and the accounts 

of our wholly-owned subsidiaries, GeoMet Operating Company, Inc., GeoMet 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 assumptions 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 reported 

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 components of our depletion rate for natural gas properties, our 

unevaluated properties and our full cost ceiling test limitation. In addition, other significant estimates include estimates used in 

computing taxes, stock-based compensation, asset retirement obligations, 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 full 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 indirect 

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 estimated 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, which would have a significant impact on the depreciation, 

depletion and amortization rate. 

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated 

future net revenues, discounted at 10% per annum, plus cost of properties 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 to 

evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is performed separately 

for our U.S. and Canadian cost centers. If capitalized costs (net 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 impairment of 

the full cost pool is required. 

63 

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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-cash charge that reduces 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 test is calculated using natural gas prices in effect as of the balance sheet date and adjusted for “basis” or 

location differential, held constant over the life of the reserves, 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 properties under development 

are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production 

facilities in progress and wells pending determination of proved reserves 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 specific project basis. Costs associated with wells in progress

and wells pending determination are transferred to the amortization 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 reporting 

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 recognized in the period in which it is incurred. Upon initial 

recognition of the asset retirement liability, the asset retirement cost is capitalized by increasing the carrying amount of the

long-lived asset by the same amount as the liability. The liability is accreted to its then present value each period, and the 

capitalized cost is depreciated over the useful life of the related asset. 

Other Property and Equipment—The cost of other property and equipment is depreciated over the estimated 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 have an original maturity 

of three months or less, are considered cash equivalents. 

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

methane and is recorded at the lower of cost or market value using 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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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 solely attributable to employees as all notes due 

from executive officers were paid in January 2006 in accordance with 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 Board 

(“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 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 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 estimates of future taxable income, alternative minimum 

tax income, and changes in stockholder ownership that could trigger limits 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 clarifies 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 recognition and disclosure of tax positions taken, or expected to be 

taken, on a tax return. The adoption of this pronouncement did not have a significant impact on the Company’s consolidated 

financial 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 whereby revenues, net of royalties, are recognized as the 

production is sold to purchaser. The amount of gas sold may differ from the amount to which the Company is entitled based on 

its working interest or net revenue interest in the properties. We typically do not have any significant producer gas imbalance 

positions because we own 100% working interest in the majority of our properties. A ready market for natural gas allows us to 

sell our natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the 

buyer. Revenue is recorded when title is transferred based on our nominations and net revenue interests. Pipeline imbalances 

occur when our production delivered into the pipeline varies from the gas we nominated for sale. Pipeline imbalances are 

settled with cash approximately thirty days from date of production and are recorded as a reduction of revenue or increase of 

revenue depending upon whether we are over-delivered or under-delivered. 

Settlements of gas sales occur after the month in which the gas was produced. We estimate and accrue for the value of 

these sales using information available at the time financial statements are generated. Differences are reflected in the 

accounting period during which payments are received from the purchaser. 

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 in 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 natural gas. The availability of 

a ready market for natural gas will depend on numerous factors beyond our control, including 

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

weather, production of natural gas, imports, marketing, competitive fuels, proximity of natural gas pipelines and other 

transportation facilities, any oversupply or undersupply of natural gas, 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 reasonably 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 purchaser 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 believe 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 rate. See Notes 5 and 9 for the fair values of the receivable and debt. 

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 ended 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 acquisition, exploration and development activities are 

capitalized as part of our natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting 

services and other costs directly associated with those activities. We capitalized general and administrative costs related to our 

acquisition, exploration and development activities, during the periods ended 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 projects which are excluded 

from current depreciation, depletion and amortization calculations. For the years ended December 31, 2008, 2007 and 2006, 

we capitalized $304,342, $587,884 and $1,037,576 of interest, respectively. See Unevaluated Properties above for additional 

information on the criteria for including costs in unevaluated properties. 

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 rates related to outstanding debt under our credit facility 

primarily through the use of fixed price swap agreements, basis swap agreements, three-way collars, and traditional collars. 

Consistent with our hedging policy, we entered into a series of derivative instruments to hedge a significant portion of our 

expected natural gas production through 2009 and 2010. We also entered into 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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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

counterparties based on specific indices as required by the derivative agreements. These transactions are recorded in our 

financial statements in accordance with SFAS No. 133, “Accounting for 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 more 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 instruments are recorded on the balance sheet at fair value 

and changes in the fair value of the derivatives are recorded 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 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 derivative instrument. To be designated as a cash flow hedge 

transaction, the relationship between the derivative and hedge items must be highly effective in achieving the offset of changes 

in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis. 

Foreign Currency Translation—For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, 

asset and liability accounts are translated at period end exchange rates and revenue and expenses are translated at average 

exchange rates prevailing during the period. Translation adjustments are included in the Accumulated Other Comprehensive 

Income (Loss). Any gains or losses on transactions or monetary assets 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 market 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 provisions of SFAS No. 123(R), Share-Based Payment

(“SFAS 123(R)”), using the prospective transition method. The application 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 and the assumptions 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 equity 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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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 the disposed component after the disposal transaction is 

completed). Assuming both preceding conditions are met, the related 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 Measurements” (“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 GAAP. SFAS 157 defines fair value as the exchange price 

that would be received for an asset or paid to transfer a liability (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 establishes 

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 levels of inputs that may be used to measure fair value. Level 1 

inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability 

to access at the measurement date. Level 2 inputs other than quoted prices included within Level 1 that are observable for the 

asset or liability, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that 

are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full 

term of the assets or liabilities. Level 3 inputs are derived from unobservable inputs that are supported by little or no market

activity and that are significant to the fair value of the assets or liabilities. See disclosure related to the implementation 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 nonfinancial assets and liabilities, except for items that are 

recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years 

beginning after November 15, 2008. We have elected to defer the application 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 fair value in goodwill impairment testing, asset 

retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. On 

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 illustrate 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 relates 

to nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business 

combination; impaired property, plant and equipment; goodwill; and initial recognition of asset retirement obligations. There 

has been no significant impact to our consolidated financial statements 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 “FASB”) 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 what information to disclose to enable users of the 

financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is to be applied 

prospectively to business combinations 

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

for which the acquisition date is on or after the beginning of an entity’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 Value 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 permits an entity to measure eligible items 

at fair value as of specified election dates. The fair value 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 first 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 literature. 

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial 

Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the 

consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires that changes 

in a parent’s ownership interest in a subsidiary be reported as an 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 financial statements. SFAS 160 must be applied 

prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which are required to be applied 

retrospectively for all periods presented. The adoption of SFAS 160 did not have a material impact on our results of 

operations, cash flows or financial positions; however, it could impact future transactions entered into by us. 

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an 

amendment of FASB Statement No. 133” (“SFAS 161”). This standard 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 related hedged items are accounted for under Statement 133 and its 

related interpretations, and (c) how derivative instruments and 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 assessing the impact of SFAS 161 on our disclosures relating to 

derivative instruments and hedging activities. The statement only provides 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 Hierarchy of Generally Accepted Accounting Principles.” The 

new standard is intended to improve financial reporting by identifying a consistent 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 GAAP hierarchy should be directed to entities because it is the 

entity (not its auditor) that is responsible for selecting accounting 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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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 Securities” (“FSP EITF 03-6-1”), which addresses whether instruments 

granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in 

the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128, 

“Earnings per Share”. FSP 03-6-1 is effective for financial statements 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 to lead to reliable conclusions about reserve volumes. In 

addition, the new disclosure requirements require a company to (a) disclose 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) report 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 effective for disclosures in 

our Annual Report on Form 10-K for the year ended December 31, 2009. 

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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 (loss) 

income by the weighted average number of shares of common stock outstanding 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 numerator and denominator is as follows: 

 

Diluted net loss per share for the year ended December 31, 2008 excluded the effect of outstanding options to purchase 

1,757,256 shares and 401,075 restricted shares because we reported a net loss which caused options to be anti-dilutive. Diluted 

net income per share for the year ended December 31, 2007 excluded the effect 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 outstanding options to purchase 245,405 shares because the 

average market price at December 31, 2006 was less than the exercise 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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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 at 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 are 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 indirect 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 estimated 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 reserves, which would have a significant impact on the depreciation, 

depletion and amortization rate. 

Under full cost accounting rules, total capitalized costs are limited 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 limitation 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 and amortization) less related deferred taxes are greater than 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 that reduces 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 prices 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 143, 

the future cash outflows associated with settling asset retirement obligations are not included in the computation of the 

discounted present value of future net revenues for the purposes of the ceiling 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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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

At December 31, 2008, the carrying value of the Company’s gas properties 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 sales or an increase in operating costs or reductions in estimated 

economically recoverable quantities could result in the recognition of an impairment of gas properties in a future period. In the 

year ended December 31, 2008, the Company recognized an impairment of gas properties of $19,959,547, net of income tax of 

$12,087,937. There was no impairment of gas properties recognized in 2007 and 2006. 

At December 31, 2008, the carrying value of the Company’s gas properties 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 economically recoverable quantities could result in the recognition of an 

impairment of gas properties in a future period. In the year ended December 31, 2008, the Company recognized an impairment 

of gas properties of $18,686,273. There was no impairment of gas properties recognized in 2007 and 2006. 

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. 

Property Conveyance and Dispute 

We had previously entered into an agreement to sell our interests in a property, subject to a preferential right to purchase 

held by another party, which the other party subsequently exercised. A dispute arose as to whether the preferential right to 

purchase applied to all the interests we owned in this property or just the working interests. We filed a declaratory judgment 

action asserting that the preferential right to purchase applied only to the working interests, and that we were entitled to retain

all remaining interests we owned in the property. Following a partial agreement with the other party, we assigned all our 

remaining interests in the property to that party, effective July 1, 2008. 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, which 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 consolidated balance sheet and capitalize the asset retirement 

costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs 

capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed 

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 is 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 totaling $1,040,014 were due primarily to specific lease agreement

requirements related to plugging and abandonment of certain wells and 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

 

Form 10-K for fiscal year ended December 31, 2008 Page 79 of 104

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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 there 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 collars and swaps. While the use of these hedging arrangements 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 statistical 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 such 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) and a 

minimum floor (a bought floor) future price. Three-way costless collars are similar to regular costless collars 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 these transactions using the 

mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are 

rising and gains during periods where prices are falling which may cause 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 results of operations as a result of changes in the estimated market 

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 positions: 

 

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

 

Form 10-K for fiscal year ended December 31, 2008 Page 80 of 104

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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 derivative as a cash flow hedge, at which time we prepare 

the documentation required under SFAS 133. 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 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 interest 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 portion 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 collateral for the outstanding borrowings under our credit 

agreement is used as collateral for our hedges. We do not have rights 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 instruments. 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 discounted value. SFAS 157 clarifies that a fair value 

measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because 

nonperformance risk includes our counterparties’ and our credit risk, 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 company to ours and the 13-week Treasury bill rate, both at 

December 31, 2008. The following is a description of the valuation methodologies 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 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 factors 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 swaps, we use a yield curve based on 

Money Market rates and Interest Rate swaps, extrapolate a forecast of future interest rates, estimate each future cash 

flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to 

present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting 

techniques used to establish the theoretical market value of 

Form 10-K for fiscal year ended December 31, 2008 Page 81 of 104

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

Based on the use of observable market inputs, we have designated these 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, maturing January 6, 2011. On March 12, 2009, the 

Company’s bank syndicate approved a borrowing base of $140 million after completing its year-end borrowing base 

determination. The next regular borrowing base determination, which will 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 permits 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 borrowing base under the revolving credit facility is based 

upon the reserve valuation of our gas properties as of June 30 and December 31 of each year and other factors deemed relevant 

by the lenders, including Bank of America as agent. The lenders may also request one additional borrowing base redetermination 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 borrowing base. For the years ended December 31, 2008 

and 2007 we borrowed $115 million and $83 million, respectively, and made payments of $94.5 million and $47 million, 

respectively, under the revolving credit facility. The outstanding balances 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. The 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 Money Market rates and Interest Rate swap market data. To 

extrapolate 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 $ — 

 

Form 10-K for fiscal year ended December 31, 2008 Page 82 of 104

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

The following is a summary of our long-term debt at December 31, 2008 and 2007: 

 

We are subject to certain restrictive financial and non-financial covenants under the credit agreement, including a 

minimum current ratio, adjusted for unrealized (gains) losses on derivative 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 financial covenants in the credit agreement. 

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

 

The fair value of long-term debt at December 31, 2008 and 2007 is approximately $92,485,449 and $83,384,209, 

respectively. SFAS 157 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk 

that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of 

our credit risk on the fair value of the long-term debt. This consideration 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 business and second reportable segment which had 

been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46(R) on 

August 1, 2006. The consolidation of the variable interest entity had no impact 

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

 

Form 10-K for fiscal year ended December 31, 2008 Page 83 of 104

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

on our net income (loss) due to the 100% minority interest to Shamrock Energy 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 value and were equal to zero. Shamrock Energy LLC was a low 

margin business and as a result it did not have a significant impact 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 because 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 discontinued 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 accordance with the provisions of the FASB 

Statement No. 109, Accounting for Income Taxes, as clarified by FIN 48. This results in the recognition of deferred 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 tax assets and liabilities is recognized in the year of the enacted 

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

 

Form 10-K for fiscal year ended December 31, 2008 Page 84 of 104

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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 minimum tax income, and changes in stockholder ownership that 

could trigger limits on use of net operating losses under Section 382 of the Internal Revenue Code. We have a significant 

deferred tax asset associated with net operating loss carryforwards (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 future years. 

Our effective tax rate differs from the federal statutory rate primarily due to losses in Canada that we are unable to benefit 

from and state income taxes. The Canadian losses, as well as certain state losses, are fully reserved because it is more likely 

than not that we will not use those NOL’s to offset current tax 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 retained 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 change in the next twelve months; however we do not 

expect the change to have a significant impact on our results of operations or the financial position. 

We file a consolidated federal income tax return in the U.S. and 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 related to potential underpayment on any unrecognized tax 

benefits as a component of interest expense in the consolidated statement of operations. Penalties, if incurred, would be 

recognized as a component of penalty expense. As of the date of adoption 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 significantly 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 approximately $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 

Form 10-K for fiscal year ended December 31, 2008 Page 85 of 104

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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 years ended December 31, 2008, 2007, and 2006 

was different than the amount computed using the Federal statutory rate 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

 

Form 10-K for fiscal year ended December 31, 2008 Page 86 of 104

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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 treasury stock held by the Company. For the years 

ended December 31, 2008 and 2007, a total of 68,605 and 105,565 shares, respectively, of common stock were issued upon the 

exercise of stock options granted under our 2005 Stock Option Plan. In March 2008, we issued 253,806 shares of restricted 

stock to key employees, as well as 5 executive officers and two other officers, of the Company and 18,720 shares of common 

stock to our independent directors, representing 50% of their annual retainer. 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, respectively, 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 January 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 shares sold by certain of our existing 

stockholders, to qualified institutional buyers exempt from registration 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 approximately $17.5 million from certain of the selling 

stockholders for repayment of loans from us, including accrued and unpaid interest thereon. We used the net proceeds from 

this private equity offering, together with the proceeds from the repayment of certain of the selling stockholders’ loans, to 

repay a portion of the borrowings under our revolving credit facility and 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 shares 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 offering after deducting estimated offering expenses and 

underwriting discounts and commissions. We used the net proceeds from 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 provisions of Statement of Financial Accounting 

Standards No. 123(R), “Share-Based Payment”, using the prospective transition method. For share-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 these 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 authorized, 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 

Form 10-K for fiscal year ended December 31, 2008 Page 87 of 104

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

Our 2006 Long-Term Incentive Plan authorized the granting of incentive stock options, non-qualified stock options, stock 

appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. A maximum of 2,000,000 

shares is available for grant under this plan. The 2006 Long-Term Incentive 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 stockholders, and to closely link compensation with our 

performance. The exercise price of stock options granted under this plan 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 vesting criteria. In September 2007 we granted 219,279 

share-based stock option awards and we also granted 30,145 restricted stock awards, including 20,145 with performance-based 

vesting to our named executive officers and two other officers. In November 2007 we granted 19,841 incentive stock options, 

20,000 restricted stock awards and 40,159 non-qualified stock options to an 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 shares of common stock to our independent directors, 

representing 50% of their annual retainer. In September 2008, we granted 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 was allocated among lease operating 

expenses ($118,830), general and administrative expenses ($118,830), and capitalized to unevaluated gas properties 

($215,093). During 2008, we recorded a compensation expense accrual of $941,697 which 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 is $ 1,714,327 which will be amortized over the 

vesting period of such stock options and restricted stock. The weighted 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 the year ended December 31, 2007, the 

significant assumptions used in determining the compensation costs included a dividend yield of 0%, expected volatility of 

40.20%, risk-free interest rate of 4.02%, an expected term of 4.5 years, forfeiture rates from 5% to 15%, and no expected 

dividends. For the year ended December 31, 2006, the significant assumptions used in determining the compensation costs 

included a dividend yield of 0%, expected volatility of 36.95%, risk-free interest rate of 4.87%, an expected term of 4.5 years, 

forfeiture rates from 5% to 15%, and no expected dividends. 

 

83 

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

Incentive Stock Options 

The table below summarizes incentive stock option activity for the 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 December 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-date fair value of 

non-qualified stock options granted during the years 2007 and 2006 was $1.18 and $4.96, respectively. 

Restricted Stock Awards 

The table below summarizes non-vested restricted stock awards activity 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 fair value of the shares that vested on that date was 

$35,604. On June 15, 2008, 20,800 shares of restricted stock vested. The fair value of the shares that vested on that date was 

$186,576. On September 20, 2008, 5,591 shares of restricted stock vested. The fair value of the shares that vested on that date 

was $33,266. On September 24, 2008, 2,000 shares of restricted stock vested. 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 sharing plan under Section 401(k) of the Internal Revenue 

Code. Eligible employees may make contributions to the plan by electing 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 Plan 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 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 Circuit 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 temporary 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 have obtained approximately 81% control of the tract, 

either through purchases of undivided surface interests in the tract or by entering into surface use and right-of-way easement 

agreements. During our pipeline construction process, CNX purchased a minority undivided surface interest in the property 

and filed a lawsuit seeking to enjoin the construction of our Pond Creek gathering line across the property. We and CNX have 

since reached a resolution of this dispute. The settlement had no material 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 sought damages arising from alleged violations of the 

Virginia Antitrust Act, tortious interference with contractual relations with third parties and statutory and common law 

conspiracy. The suit sought compensatory and consequential damages for alleged violations of the Virginia Antitrust Act, 

including alleged anticompetitive efforts of CNX to dominate 

85 

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GEOMET, INC. AND SUBSIDIARIES 

NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS—(Continued) 

and maintain its control over the market for the production and transportation of coalbed methane gas from the Oakwood Field 

in Buchanan County, Virginia and for CNX’s alleged efforts to conspire 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 Virginia 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 accordance with an opinion issued by the Tazewell Circuit 

Court in December 2007, we have filed an amended 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 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 are 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 contracts, we can 

transport maximum daily volumes of (1) 7,000 MMBtu’s continuing until October 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-year increments, at the maximum tariff rate. As of 

December 31, 2008, the maximum commitment remaining under the transportation 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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SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON GAS 

EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) 

This supplemental schedule provides unaudited information pursuant to SFAS No. 69, Disclosures About Oil and Natural 

Gas Producing Activities, (“SFAS 69”) and certain other information. 

Capitalized Costs—Capitalized costs and accumulated depreciation, depletion, amortization and impairment of gas 

properties relating to our gas producing activities, all of which 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 directly attributable to acquisition, exploration and development 

activities as part of our investment in natural gas properties over 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 adjustment 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 acquisition, 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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Reserves—The following table summarizes our net ownership interests in estimated 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 estimating quantities of “proved,” “proved developed” and 

“proved undeveloped” natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all 

available geological, engineering and economic data for each reservoir. 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 production under varying economic conditions. 

Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although 

every reasonable effort is made to ensure that reserve estimates 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 connection 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 this statement, the amounts shown are based on prices and 

costs at December 31, 2008, 2007 and 2006, and assume continuation of existing 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 timing of 

future net cash flows. Extensive judgments are involved in estimating 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 when judged against actual subsequent results. Further, since prices 

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 proved 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 the years ended December 31, 2008, 2007 and 2006 

are summarized below: 

 

The weighted average prices of gas used with the above tables at December 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 quarter 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 that are designed to ensure that information 

required to be disclosed by us in the reports we file or submit under the 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 required to be disclosed by us is accumulated and 

communicated to management, including our Chief Executive Officer and Chief 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 procedures (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 this 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, including the Chief Executive Officer and Chief 

Financial Officer, we have evaluated our internal controls over financial reporting (as such term is defined in Rules 13a-15(f) 

and 15d-15(f) under the Exchange Act) that occurred during the year ended 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 Chief 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 reasonable assurance to the Company’s Management and 

Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations,

internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of 

effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or 

that the degree of compliance with the policies or procedures may deteriorate. 

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the

Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as 

of December 31, 2008. 

 

Houston, Texas 

March 12, 2009 

91 

/s/ J. DARBY SERÉ /s/ WILLIAM C. RANKIN 

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 may from time to time have investments in other 

exploration and production companies that may compete with us. Section 122(17) of the Delaware General Corporation Law 

permits a Delaware corporation, such as GeoMet, to renounce by action 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 corporate law concepts of fiduciary duty, our officers and directors 

generally have a duty to disclose to us opportunities that are related 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 Agreement 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 aspect 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 aware of so long as he did not become aware of the 

opportunity as a consequence of serving as a member of our board of directors. Furthermore, the Designated Party will be 

permitted to pursue that opportunity even if it is competitive with our business. This Business Opportunities Agreement does 

not prohibit us from pursuing any business opportunity to which we have renounced any interest or expectancy. It will provide 

the Designated Parties and their respective affiliates with some certainty that opportunities that they independently pursue will 

not be required to be first offered to us. 

The form of Business Opportunities Agreement is attached to this Form 10-K as exhibit 10.20. 

92 

• any business opportunity that is brought to the attention of a Designated 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 solely 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 reference to the 2009 Proxy Statement, which will be 

filed with the Commission not later than 120 days subsequent to December 31, 2008. Pursuant to Item 401(b) of Regulation SK, the information required by this item with respect to our executive officers is set forth in Part I of this report. 

Item 11. Executive Compensation 

The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be 

filed with the Commission not later than 120 days subsequent to December 31, 2008. 

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

The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be 

filed with the Commission not later than 120 days subsequent to December 31, 2008. 

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

The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be 

filed with the Commission not later than 120 days subsequent to December 31, 2008. 

Item 14. Principal Accountant Fees and Services 

The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be 

filed with the Commission not later than 120 days subsequent to December 31, 2008. 

93 

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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 December 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 December 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 years 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 on Form S-1 filed on July 25, 2006 

(Registration No. 333-131716)).

 3.2

 

Amended and Restated Bylaws of GeoMet, Inc. (incorporated herein 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 America Securities LLC, dated as of 

January 30, 2006 (incorporated herein by reference to Exhibit 4.1 to the Company’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 herein 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 Plan of GeoMet, Inc. 

(incorporated herein by reference to Exhibit 10.3 to the Company’s Registration 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 reference to Exhibit 10.4 to the 

Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333-

131716)).

10.4

 

Incentive Bonus Pool Plan, dated as of May 29, 2001 (incorporated herein by reference to Exhibit 10.5 to 

the Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333-

131716)).

10.5

 

Employment Agreement dated as of December 7, 2000 between GeoMet Resources, 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 Resources, 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 GeoMet, Inc., Bank of 

America, N.A., as Administrative Agent, and BNP Paribas, as 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 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 Registration Statement on Form S-1 

filed on May 12, 2006 (Registration No. 333-131716)) (portions of this exhibit 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).

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 (incorporated 

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 December 31, 2008 between 

GeoMet, Inc. and J. Darby Seré.

10.16*

 

Second Amendment to Employment Agreement dated effective as of December 31, 2008 between 

GeoMet, Inc. and William C. Rankin.

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96 

Exhibit No. Description

10.17 Stock Acquisition and Stockholders Agreement dated December 7, 2000 by and 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 signatories 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 Section 906 of the Sarbanes-Oxley Act 

of 2002.

* Filed herewith. 

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SIGNATURES 

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant 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 below by the following persons on behalf of the 

registrants and in the capacities on March 12, 2009. 

 

97 

GEOMET, INC.

By: /s/ J. DARBY SERÉ 

Name: J. Darby Seré

Title: President and Chief Executive Officer

Signature Capacity

/s/ J. DARBY SERÉ 

J. Darby Seré 

Chairman of the Board, President, Chief Executive Officer 

(Principal Executive Officer)

/s/ WILLIAM C. RANKIN 

William C. Rankin 

Executive Vice President, Chief Financial Officer 

(Principal Financial Officer)

/s/ TONY OVIEDO 

Tony Oviedo 

Vice President, Chief Accounting Officer and Controller

/s/ J. HORD ARMSTRONG, III 

J. Hord Armstrong, III 

Director

/s/ JAMES C. CRAIN 

James C. Crain 

Director

/s/ STANLEY L. GRAVES 

Stanley L. Graves 

Director

/s/ CHARLES D. HAYNES 

Charles D. Haynes 

Director

/s/ W. HOWARD KEENAN, JR. 

W. Howard Keenan, Jr. 

Director

/s/ PHILIP G. MALONE 

Philip G. Malone 

Director

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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 on Form S-1 filed on July 25, 2006 

(Registration No. 333-131716)).

 3.2

 

Form Amended and Restated Bylaws of GeoMet, Inc. (incorporated herein 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 America Securities LLC, dated as of 

January 30, 2006 (incorporated herein by reference to Exhibit 4.1 to the Company’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 herein by reference to Exhibit 

10.2 to the Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 

333-134070)).

10.2

 

Form of Incentive Stock Option Agreement for the 2005 Stock Option Plan of GeoMet, Inc. (incorporated 

herein by reference to Exhibit 10.3 to the Company’s Registration Statement 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 reference to Exhibit 10.4 to the 

Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333-

134070)).

10.4 

 

Incentive Bonus Pool Plan, dated as of May 29, 2001 (incorporated herein by reference to Exhibit 10.5 to 

the Company’s Registration Statement on Form S-1 filed on February 10, 2006 (Registration No. 333-

134070)).

10.5 

 

Employment Agreement dated as of December 7, 2000 between GeoMet Resources, 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 Resources, 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. 333-134070)).

10.7 

 

Third Amended and Restated Credit Agreement dated June 9, 2006, among GeoMet, Inc., Bank of America, 

N.A., as Administrative Agent, and BNP Paribas, as 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 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 Registration Statement on Form S-1 

filed on May 12, 2006 (Registration No. 333-131716)) (portions of this exhibit 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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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 (incorporated 

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 December 31, 2008 between 

GeoMet, Inc. and J. Darby Seré.

10.16* Second Amendment to Employment Agreement dated effective as of December 31, 2008 between 

GeoMet, Inc. and William C. Rankin.

10.17 Stock Acquisition and Stockholders Agreement dated December 7, 2000 by and 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 signatories 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 Section 906 of the Sarbanes-Oxley Act 

of 2002.

* Filed herewith. 

Form 10-K for fiscal year ended December 31, 2008 Page 104 of 104

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