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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

OR

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 001-32960

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

(Address of principal executive offices and telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

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.  x  Yes  o  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x  Yes  o  No

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.

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

As of May 1, 2013, 40,689,486 shares and 5,471,610 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

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Part I. FINANCIAL INFORMATION

Item 1.                                   Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

See accompanying Notes to Audited Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

See accompanying Notes to Audited Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

See accompanying Notes to Audited Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE YEARS ENDED DECEMBER 31,

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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 primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba and Black Warrior Basins in Alabama and the central Appalachian Basin in Virginia and West Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, Virginia, and West Virginia.

Note 2— Sale of Coalbed Methane Properties in Alabama

On May 3, 2013, the Company entered into a purchase and sale agreement (“PSA”) to sell its coalbed methane properties in Alabama to Saga Resource Partners LLC, for a purchase price of $63.2 million, subject to customary purchase price adjustments. The effective date of this transaction is April 1, 2013, and it is expected to close on or before June 14, 2013, subject to the exercise of preferential rights and customary closing conditions. GeoMet plans to use the cash proceeds from this asset divestiture, net of purchase price adjustments and other transaction related expenditures, to repay borrowings under its Credit Agreement. We have estimated no material income tax impact on the gain resulting from the sale due to offsetting operating losses.

In connection with the PSA to sell the coalbed methane properties in Alabama, on May 1, 2013, the Company and the lenders under its Fifth Amended and Restated Credit Agreement executed the Fifth Amendment to such agreement (“Amendment”), which became effective as of May 1, 2013 and provides the necessary consents to sell the coalbed methane properties in Alabama. The Amendment requires repayment of a minimum of $52 million of borrowings which will result in the elimination of the “non-conforming” tranche B portion of total outstanding borrowings. Following the expected use of net proceeds for repayment of indebtedness, GeoMet’s borrowing base will be the lesser of $83 million or actual outstanding borrowings at such time.

GeoMet’s average net interest in the coalbed methane properties in Alabama being sold produced approximately 9,700 Mcf of natural gas per day during the month of March 2013, or approximately 29% of GeoMet’s total production for this time period. As of March 31, 2013 and based on Securities and Exchange Commission guidelines, GeoMet’s net proved reserves attributable to the coalbed methane properties in Alabama being sold were estimated to be approximately 43 Bcf, all classified as proved developed reserves.

Note 3— Going Concern and Management’s Plans

The accompanying consolidated financial statements (unaudited) have been prepared in conformity with accounting principles generally accepted in the United States which contemplate continuation of the Company as a going concern. In 2012, the amounts outstanding under the Company’s Fifth Amended and Restated Credit Agreement (“Credit Agreement”) exceeded the borrowing base as determined by the lenders under the Credit Agreement.  In August 2012, the Company amended the Credit Agreement to provide for a conforming tranche limited to the borrowing base, and a non-conforming tranche in the amount outstanding in excess of the borrowing base.  The Company is required to dedicate substantially all of its free cash flow to repayment of the non-conforming tranche.  The Credit Agreement matures on April 1, 2014, and no assurances can be made that the Company will be able to refinance, repay or further extend the maturity date of the Credit Agreement.  The borrowing base deficiency also adversely impacted the Company’s working capital by reclassifying the next twelve months’ required payments from Long-term debt to Current Liabilities in the Consolidated Balance Sheets (Unaudited) as of March 31, 2013. In addition, as of March 31, 2013, the Company had a working capital deficit of $8.3 million, a retained deficit of $307.8 million and stockholders’ deficit of $114.6 million.  Depressed natural gas prices in 2012 resulted in significant property impairments and full valuation of our deferred tax assets during 2012. On April 2, 2013, all the indebtedness under the Company’s Credit Agreement was reclassified to current liabilities. These and other factors raise substantial doubt about the Company’s ability to continue as a going concern.

Management’s current business plan is primarily focused on eliminating the borrowing base deficiency, maintaining compliance with the Credit Agreement, as amended, maintaining production levels and controlling costs.  In addition, management recently executed a purchase and sale agreement for all of the Company’s coalbed methane properties in Alabama described above in Footnote 2 — Sale of Coalbed Methane Properties in Alabama that were being marketed for sale by an asset divestiture firm.  Management will continue to evaluate the viability of additional asset sales or strategic corporate transactions. There can be no assurance that the Company will be able to sell properties (including under the existing PSA), to effect a strategic transaction, or realize adequate proceeds from the sale of properties to eliminate the deficiency under, or to refinance, the Credit Agreement.

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The ability of the Company to continue as a going concern is dependent upon its ability to generate sufficient cash flows and sales proceeds or other sources of capital sufficient to repay or refinance its indebtedness, continue its operations and fund its long-term capital needs. The accompanying consolidated financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

Note 4—Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date. ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations addressed within existing guidance. The update is effective for interim and annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented for those obligations that existed upon adoption of ASU 2013-04. We are presently assessing the potential impact of ASU 2013-04.

In February 2013, the FASB issued Accounting Standards Update (“ASU”) No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. The update requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under accounting principles generally accepted in the United States (“GAAP”) to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning after December 15, 2012 The Company has adopted and applied the provisions of ASU 2012-02 which did not impact its operating results, financial position or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” The amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. The Company has adopted and applied the provisions of ASU 2013-01. As the Company currently presents unrealized gains (losses) on commodity derivatives on a gross basis on our Consolidated Balance Sheets (Unaudited), no material impact was noted.

In July 2012, the FASB issued ASU 2012-02, which amends the guidance in ASC 350-30 on testing indefinite-lived intangible assets, other than goodwill, for impairment. The FASB issued the ASU in response to feedback on ASU 2011-08, which amended the goodwill impairment testing requirements by allowing an entity to perform a qualitative impairment assessment before proceeding to the two- step impairment test. Similarly, under ASU 2012-02, an entity testing an indefinite-lived intangible asset for impairment has the option of performing a qualitative assessment before calculating the fair value of the asset. Although ASU 2012-02 revises the examples of events and circumstances that an entity should consider in interim periods, it does not revise the requirements to test indefinite-lived intangible assets (1) annually for impairment and (2) between annual tests if there is a change in events or circumstances. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The Company has adopted and applied the provisions of ASU 2012-02 which did not impact its operating results, financial position or cash flows.

Note 5—Discontinued Operations

On June 20, 2012, we disposed of Hudson’s Hope Gas, Ltd., a subsidiary which held our Canadian gas properties, in exchange for two million shares of Canada Energy Partners, Inc. (“CEP Shares”) which we are restricted from selling before June 20, 2013. We recognized a loss on the disposition in the amount of $0.7 million, which was made up of a $1.3 million loss related to the currency translation adjustment, offset by $0.3 million in asset retirement obligations conveyed to the buyer and the proceeds consisting of the $0.3 million in estimated fair value of the CEP shares received. The loss on this disposition has been included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited). Additionally, all historical operating results related to the disposed company have been removed from Operating (loss) income and included in Discontinued operations, net of tax, in the Consolidated Statements of Operations (Unaudited) for the periods presented.

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As a result of the disposition, we are classifying these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations for the three months ended March 31, 2013 and 2012 were as follows:

Note 6—Net Loss Per Common Share

Net Loss Per Share of Common Stock— Net loss per common share—basic is calculated by dividing Net loss available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net loss available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential shares of common stock would have an anti-dilutive effect. A reconciliation of the numerator and denominator for the three months ended March 31, 2013 and 2012 is as follows:

Net loss per common share—diluted for the three months ended March 31, 2013 excluded the effect of outstanding exercisable options to purchase 2,365,466 shares, 233,099 weighted average restricted shares outstanding, and 5,305,865 shares of Series A Convertible Redeemable Preferred Stock (40,814,346 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a Net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net loss available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net loss available to common stockholders for the three months ended March 31, 2013 for Accretion of and dividends paid for Series A Convertible Redeemable Preferred Stock of $493,537 and $1,076,318, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

Net loss per common share—diluted for the three months ended March 31, 2012 excluded the effect of outstanding exercisable options to purchase 1,384,398 shares, 262,896 weighted average restricted shares outstanding, and 4,549,537 shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a Net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net loss available to common stockholders is also

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adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net loss available to common stockholders for the three months ended March 31, 2012 for Accretion of and dividends paid for Series A Convertible Redeemable Preferred Stock of $462,016 and $1,241,365, respectively, in computing Net loss per common share—diluted as the preferred shares were anti-dilutive.

Note 7—Gas Properties

The method of accounting for oil and gas producing activities determines which costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for our gas properties. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized.

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 involves 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. 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 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 the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. In addition, 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.

For the twelve months ended March 31, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $2.97 per Mcf, resulting in a natural gas price of $3.03 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, no write-down of the carrying value of our U.S. full cost pool was required at March 31, 2013.

For the twelve months ended March 31, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.75 per Mcf, resulting in a natural gas price of $3.90 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, we recorded a $15.8 million write-down of the carrying value of our U.S. full cost pool at March 31, 2012.

Note 8—Asset Retirement Obligations

We record an asset retirement obligation (“ARO”) in the Consolidated Balance Sheets (Unaudited) 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. Periodically, we update the cost assumptions resulting from market changes and revise the liability recorded accordingly.

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The following table details the changes to our asset retirement liability for the three months ended March 31, 2013:

Note 9—Derivative Instruments and Hedging Activities

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. 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 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, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. Our Credit Agreement limits amounts of future natural gas production that we may hedge. At March 31, 2013, we do not have the ability to enter into additional natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

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. 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 Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

Commodity Price Risk and Related Hedging Activities

At March 31, 2013, we had the following natural gas collar positions:

At December 31, 2012, we had the following natural gas collar positions:

At March 31, 2013, we had the following natural gas swap positions:

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At December 31, 2012, we had the following natural gas swap positions:

At December 31, 2012, we had the following forward sales at NYMEX plus a fixed basis:

The aforementioned forward physical sale contracts qualified for normal purchase and sale exemption and, as such, we have elected not to record it on the Consolidated Balance Sheets (Unaudited) using mark-to-market accounting.

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants or affiliates of the 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.

We estimate the fair value of our natural gas derivative contracts and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. 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 credit risk on the fair value of the assets and liabilities related to the items stated below. The consideration for discounting our counterparties’ liabilities (our assets) was based on the difference between the S&P credit rating of a comparable company to our counterparties and the 13-week Treasury bill rate, both at the reporting date. The consideration for discounting our liabilities was based on the difference between the market weighted average cost of debt capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included our long-term debt.

In order to estimate the fair value of our natural gas derivative contracts, 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.

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended March 31, 2013. Based on the use of observable market inputs, we have designated these types of instruments designated below as Level 2. The fair value of our Level 2 derivative instruments were as follows:

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The following losses (gains) on our hedging instruments included in the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2013 and 2012 are as follows:

Note 10—Investment in Canada Energy Partners

At March 31, 2013 and December 31, 2012, we own two million shares of Canada Energy Partners (“CEP”), discussed in Note 5—Discontinued Operations, which we classify as available for sale and record at fair value in Other noncurrent assets on the Consolidated Balance Sheets (Unaudited) based on the closing price of the shares on the TSX Venture Exchange on that date. Gains or losses related to both market price fluctuation and currency translation adjustment on the shares of CEP are held in Accumulated other comprehensive loss in the Consolidated Balance Sheets (Unaudited). At March 31, 2013 and December 31, 2012, the value of the shares recorded in Other noncurrent assets was $262,044 and $240,749, respectively, using a Level 1 input. Accumulated other comprehensive loss of $31,725 in the Consolidated Balance Sheets (Unaudited) as of March 31, 2013 consisted of a $41,599 cumulative decrease in market value offset by a $9,874 cumulative gain related to currency translation on the CEP shares. Accumulated other comprehensive loss of $53,020 in the Consolidated Balance Sheets (Unaudited) as of December 31, 2012 consisted of a $61,661 cumulative decrease in market value offset by a $8,641 cumulative gain related to currency translation on the CEP shares.

Note 11—Long-Term Debt

Under our Credit Agreement, outstanding borrowings may not exceed a borrowing base determined by the lenders.  During 2012, the amounts borrowed under our Credit Agreement exceeded the borrowing base.  On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended the Credit Agreement. Borrowings under the Credit Agreement at August 8, 2012 totaled $148.6 million. The Credit Agreement, as amended, provided for a tranche A loan in the amount of our borrowing base and a tranche B loan in the amount of the excess.  The borrowing base, determined as of May 1, 2012, is currently $115.0 million.  The tranche B loan was $21.8 million as of March 1, 2013.  The borrowing base will be re-determined as of each June and December with the next determination scheduled to be completed by December 15, 2013.  Upon any re-determination of the borrowing base, the re-determined amount of the conforming borrowing base will constitute a new tranche A loan, with any decrease in tranche A causing an automatic corresponding increase in tranche B, subject to certain limitations described below, and any increase in tranche A causing an automatic corresponding decrease in tranche B. At the next and any subsequent borrowing base determination, tranche B may not increase by more than 25% of the amount of the principal payments made on tranche B loans since the prior redetermination of the borrowing base. If a future determination of the borrowing base results in the outstanding amount of the tranche B loan exceeding the amount permitted under the Credit Agreement, we have 30 days to repay such excess. The Credit Agreement no longer provides for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed by the Company. All outstanding borrowings under the Credit Agreement are due and payable on April 1, 2014. In addition, the Credit Agreement obligates us to reduce our borrowings monthly by substantially all of our available excess cash flow. The Credit Agreement provides for interest to accrue at a rate calculated, at our option, at the Adjusted Base Rate plus a margin of 2.00% on tranche A loans and 4.00% on tranche B loans or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00% on tranche A loans and 5.00% on tranche B loans. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. The Credit Agreement requires an additional payment to the lenders based on the amount of tranche B loans as follows:

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All financial covenants were deleted by the Amendment and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013) and a maximum debt covenant as follows:

As of March 31, 2013, we had $134.8 million of borrowings outstanding under our Credit Agreement. As of March 31, 2013, the interest rates applied to borrowings under tranche A and tranche B were 3.20% and 5.39%, respectively.  As of December 31, 2012, interest rates applied to borrowings under tranche A and tranche B were 3.21% and 5.21%, respectively. For the three months ended March 31, 2013, we had no borrowings and made payments of $4.5 million under the Credit Agreement. For the three months ended March 31, 2012, we borrowed $7.4 million and made payments of $15.8 million under the Credit Agreement. For the three months ended March 31, 2013 and 2012, interest on the borrowings averaged 4.27% and 2.90% per annum, respectively.

The following is a summary of our long-term debt at March 31, 2013 and December 31, 2012:

We record our debt instruments based on contractual terms. We did not elect to apply the fair value option for recording financial assets and financial liabilities. We measure the fair value of our debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 or 2 within the fair value hierarchy. 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 market weighted average cost of equity capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.  The fair value of long-term debt at March 31, 2013 and December 31, 2012 was estimated to be approximately $123.0 million and $121.6 million, respectively.

In connection with the PSA to sell the coalbed methane properties in Alabama, on May 1, 2013, the Company and the lenders under its Fifth Amended and Restated Credit Agreement executed the Fifth Amendment to such agreement (“Amendment”), which became effective as of May 1, 2013 and provides the necessary consents to sell the coalbed methane properties in Alabama. The Amendment requires repayment of a minimum of $52 million of borrowings which will result in the elimination of the “non-conforming” tranche B portion of total outstanding borrowings. Following the expected use of net proceeds for repayment of indebtedness, GeoMet’s borrowing base will be the lesser of $83 million or actual outstanding borrowings at such time. This Fifth Amended does not extend the maturity date nor allows additional borrowing; however, it primarily provides a mechanism to recognize direct transaction costs in arriving at the net proceeds to be applied toward the outstanding debt.  Among other things, the Amendment increased the capital expenditure restriction in 2013 from $1.0 million to $1.5 million and increased the amount of cash the Company could retain in calculating its monthly loan reduction to $2.0 million from $1.0 million. The Company paid the banks a fee equal to 25 basis points on the tranche B portion of the loan which totaled $48,250. The Amendment is conditioned upon completion of the asset sale described in Note 2— Sale of Coalbed Methane Properties in Alabama.

Note 12—Income Taxes

We record our income taxes using an asset and liability approach. 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 basis of assets and liabilities using enacted tax rates at the end of the period. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.

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For tax reporting purposes, we have federal and state net operating losses (“NOL’s”) of approximately $137.8 million and $127.0 million, respectively, at March 31, 2013 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOL’s of approximately $137.8 million and $127.0 million, respectively, at December 31, 2012 that were available to reduce future taxable income. Our first material NOL carryforward expires in 2022 and the last one expires in 2032.

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations, of approximately $34.9 million at March 31, 2013 that is available to reduce future taxable capital gains and expiring in 2017.

At March 31, 2013, we have a valuation allowance of $98.8 million recorded against our net deferred tax asset which includes $85.4 million related to our U.S. operations and $13.4 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd., as described in Note 5—Discontinued Operations.

A reconciliation of the effective tax rate to the statutory rate is as follows:

Note 13—Common Stock

At March 31, 2013 and December 31, 2012, there were 40,689,486 and 40,690,077 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at March 31, 2013 and December 31, 2012 were 254,260 and 254,260 shares of restricted stock, respectively. The following table details the activity related to our common stock for the three months ended March 31, 2013:

Note 14—Series A Convertible Redeemable Preferred Stock

At both March 31, 2013 and December 31, 2012, 5,305,865 shares of preferred stock were issued and outstanding. At March 31, 2013, an additional 2,095,967 shares of our Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using a discounted cash flow analysis based on our current borrowing rates (categorized as level 3). For the three months ended March 31, 2013, the change in the balance of our Series A Convertible Redeemable Preferred Stock consisted entirely of accretion of the discount of $493,537.

On March 8, 2013, we declared a quarterly dividend of 165,745 shares of Preferred Stock covering the period January 1, 2013 through March 31, 2013. As those shares were not issued until April 1, 2013, they were not been included in the Preferred Stock balance at March 31, 2013. As such, we recorded a dividend payable in Current liabilities in the Consolidated Balance Sheets (Unaudited) at March 31, 2013 at an estimated fair value of $1,075,685.

Note 15—Share-Based Awards

As of March 31, 2013, our 2006 Long-Term Incentive Plan (the “2006 Plan”) is our only authorized stock-based award plan. Our 2005 Stock Option Plan was terminated on March 11, 2011 as no options granted under the plan remained outstanding at that time. Our 2006 Plan authorizes 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 4,000,000 shares are available for grant under this plan. The 2006 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,

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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 which are granted solely to our named executive officers, 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 granted to our directors vest immediately.

During the three months ended March 31, 2013, we recorded a compensation expense accrual of $58,724 which was allocated as an addition of $6,752 to lease operating expenses and an addition of $51,972 to general and administrative expense. The future compensation cost of all the outstanding awards is $251,530 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 0.70 years.

Incentive Stock Options

The table below summarizes incentive stock option activity for the three months ended March 31, 2013:

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the three months ended March 31, 2013:

Restricted Stock Awards

The table below summarizes non-vested restricted stock awards activity for the three months ended March 31, 2013:

Restricted Stock Unit Awards

On April 5, 2011, we granted 232,089 restricted stock units to our five executive officers. These restricted stock units vest upon the Company’s achievement of certain performance targets, but no earlier than ratably over the three year period following the grant date, at which time one common share will be issued and exchanged for each restricted stock unit held. If the requisite performance targets are not achieved in the seven year period ended April 5, 2018, the restricted stock units will expire. Restricted stock units are included in the calculation of diluted earnings per share utilizing the treasury stock method. On April 30, 2012, 99,108 restricted stock units vested with a vesting date fair value of $0.53 per share. On June 25, 2012, 16,428 restricted stock units were forfeited. There have been no grants of restricted stock units subsequent to the aforementioned grant. Unrecognized compensation cost related the restricted stock units is $116,553 at March 31, 2013.

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Note 16— Commitments and Contingencies

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 are not possible to reasonably predict, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

Environmental and Regulatory

As of March 31, 2013, 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.

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Item 2.                                  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statement Regarding Forward-Looking Information

Management’s Discussion and Analysis of Financial Condition and Results of Operations and other items in this Quarterly Report on Form 10-Q contain forward-looking statements and information that are based on management’s beliefs, as well as assumptions made by, and information currently available to, management. When used in this document, the words “believe,” “anticipate,” “estimate,” “expect,” “intend,” “may,” “will,” “project,” “forecast,” “plan,” and similar expressions are intended to identify forward-looking statements. Although management believes that the expectations reflected in these forward-looking statements are reasonable, it can give no assurance that these expectations will prove to have been correct. These statements are subject to certain risks, uncertainties and assumptions. Certain of these risks are summarized in this report and under “Item 1A. Risk Factors” in our 2012 Annual Report on Form 10-K that we filed with the SEC on March 28, 2013, which you should read carefully in connection with our forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated. We undertake no obligation to release publicly any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

You should read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in conjunction with the corresponding sections and our audited consolidated financial statements for the fiscal year ended December 31, 2012, which are included in our 2012 Annual Report on Form 10-K.

Overview

GeoMet, Inc. is primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids.  We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba and Black Warrior Basins in Alabama and the central Appalachian Basin in Virginia and West Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, Virginia, and West Virginia. As of March 31, 2013, we own a total of approximately 138,000 net acres of coalbed methane and oil and gas development rights.

The natural gas industry is capital intensive. Natural gas markets traditionally have been highly volatile. We have historically made substantial capital expenditures in the exploration, development and acquisition of natural gas reserves. Our capital expenditures have been financed primarily with internally generated cash from operations and proceeds from bank borrowings.

Natural gas prices in 2012 were depressed compared with prices generally prevailing over the last several years.  The low natural gas prices had pervasive adverse consequences to our business.  The borrowing base deficiency was caused by low natural gas prices. On August 8, 2012, we amended our Credit Agreement to include a conforming tranche equal to the borrowing base, and a non-conforming tranche in the amount of the excess.  The amendment requires that we use all of our excess cash flows to reduce outstanding borrowings under the non-conforming tranche, and significantly limits our capital expenditures.  The Credit Agreement, as amended, has higher interest rates and increased bank fees and professional fees. The maturity date was amended to April 1, 2014.  While the amendment provided time to seek a strategic corporate transaction, we believe these efforts have been impeded because of the borrowing base deficiency. However, we have executed a purchase and sale agreement which we believe will eliminate the borrowing base deficiency. The borrowing base deficiency exhausted our hedging credit capacity; thereby, adversely impacting our ability to hedge future gas sales volumes.  Retaining and attracting competent personnel has been challenging and is likely to worsen.  The need to reduce costs due to lower natural gas prices and operating margins creates vulnerability in conducting our business.

Additionally, depressed natural gas prices resulted in significant property impairments and full valuation of our net deferred tax asset during 2012. Low natural gas prices and our indebtedness contributed to our common stock being delisted by NASDAQ as we had no remaining equity and the market price of our common stock had diminished.

Management’s current business plan is primarily focused on eliminating our borrowing base deficiency, maintaining compliance with our Credit Agreement, as amended, maintaining production levels and keeping costs under control.

During 2011 and the first five months of 2012, prices received for natural gas in the United States continued to decline significantly which we believe, among other things, was due to an over-supply of natural gas, primarily resulting from shale drilling and reduced demand due to a much warmer winter than normal. On April 21, 2012, the Henry Hub spot price closed at $1.825/ MMBtu, its lowest in over ten years. Presented below are the NYMEX Settle Prices for the period January 2011 through May 2013 and the NYMEX Forward Curve Prices (as of May 7, 2013) for natural gas for the period June 2013 through December 2013.

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The chart above demonstrates the rapid gas price decline of late 2011 and early 2012. This rapid decline resulted in severe capital and liquidity constraints, creating a borrowing base deficiency under our Credit Agreement. In May 2013, the NYMEX Settle Price has returned to a level similar to that of January 2011. In order to understand why the Company’s Borrowing Base has not returned to prior levels, it is important to examine other factors. The table below compares the NYMEX Natural Gas Forward Price Curves as of January 1, 2011 and May 1, 2013.

The chart above demonstrates the significant difference in the forward price curves for comparable periods as of January 1, 2011 and May 1, 2013. The difference in the forward curves is as much as $1.64/MMBtu. We believe that the diminished forward curve and the delayed response by our bank group to the improving price trend are the primary drivers impeding recovery of our borrowing base to previous levels, resulting in the continued need to follow through with our current business plan described above.

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Recent Developments

On May 3, 2013, the Company entered into a purchase and sale agreement (“PSA”) to sell its coalbed methane properties in Alabama to Saga Resource Partners LLC, for a purchase price of $63.2 million, subject to customary purchase price adjustments. The effective date of this transaction is April 1, 2013, and it is expected to close on or before June 14, 2013, subject to the exercise of preferential rights and customary closing conditions. GeoMet plans to use the cash proceeds from this asset divestiture, net of purchase price adjustments and other transaction related expenditures, to repay borrowings under its Credit Agreement. We have estimated no material income tax impact on the gain resulting from the sale due to offsetting operating losses.

In connection with the PSA to sell the coalbed methane properties in Alabama, on May 1, 2013, the Company and the lenders under its Fifth Amended and Restated Credit Agreement executed the Fifth Amendment to such agreement (“Amendment”), which became effective as of May 1, 2013 and provides the necessary consents to sell the coalbed methane properties in Alabama. The Amendment requires repayment of a minimum of $52 million of borrowings which will result in the elimination of the “non-conforming” tranche B portion of total outstanding borrowings. Following the expected use of net proceeds for repayment of indebtedness, GeoMet’s borrowing base will be the lesser of $83 million or actual outstanding borrowings at such time.

GeoMet’s average net interest in the coalbed methane properties in Alabama being sold produced approximately 9,700 Mcf of natural gas per day during the month of March 2013, or approximately 29% of GeoMet’s total production for this time period. As of March 31, 2013 and based on Securities and Exchange Commission guidelines, GeoMet’s net proved reserves attributable to the coalbed methane properties in Alabama being sold were estimated to be approximately 43 Bcf, all classified as proved developed reserves.

Lantana Oil & Gas Partners was divestment advisor to GeoMet for the sales process.

Areas of Operation

Our core areas of operations are in the Central Appalachian Basin of Virginia and West Virginia and the Black Warrior and Cahaba Basins in Alabama. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. The Black Warrior and Cahaba Basins are hilly, gently rolling regions and coal mining is also present but less active.

Central Appalachia

Pond Creek and Lasher Fields—We are the operator of 298 producing vertical CBM wells in which we own a 99.0% average working interest in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia. Net daily sales of gas averaged 16.1 MMcf per day for the three months ended March 31, 2013. Our natural gas production from the Pond Creek field is delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We have two long-term transportation agreements with ETNG which went into effect in April 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. Our gas from the Lasher field is delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also own and operate a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production is gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system.

Pinnate Horizontal Wells—We are the operator of 44 producing pinnate horizontal CBM wells in which we own a 71.6% average working interest in central and northern West Virginia. We also have a 33.7% average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. Net daily sales of natural gas averaged 8.4 MMcf per day for the three months ended March 31, 2013.  We are party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring from April 2013 through November 2024 which can be automatically extended at GeoMet’s option at the maximum tariff rate. We are also party to a 10,000 MMBtu per day gathering contract that is currently in a month-to-month evergreen term.  In some cases, our natural gas sales volumes are delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes are sold at a delivery point into the respective interstate pipeline system utilized.

Alabama

Gurnee Field—We are the operator of 217 producing vertical CBM wells, of which we own a 100.0% working interest, in the Gurnee field located in the Cahaba Basin in central Alabama. Net daily sales of gas averaged 4.4 MMcf for the three months ended March 31, 2013. Our natural gas sales volumes from the Cahaba Basin are delivered and sold into the Southern Natural Gas pipeline system and no firm transportation arrangements are necessary.  We own and operate a water gathering system which includes an approximately 39 mile pipeline to the Black Warrior River for disposal of produced water under a permit issued by the Alabama Department of Environmental Management.  We also own and operate an approximately 17 mile, 12 inch high-pressure steel pipeline and gas treatment and compression facilities through which we gather, dehydrate, and compress natural gas for delivery into the Southern Natural Gas pipeline system.

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Black Warrior Basin—We own working, overriding royalty or royalty interests in 1,056 non-operated producing vertical CBM wells in the Black Warrior Basin in central Alabama. All of these non-operated vertical wells have an average royalty and or overriding royalty interest of 12.0%. We also own an average working interest of 15.4% in 498 of these wells. Net daily sales of gas averaged 5.6 MMcf for the three months ended March 31, 2013. Our gas sales volumes from the Black Warrior Basin are delivered and sold into the Southern Natural Gas pipeline system under transportation arrangements controlled by the operators of the properties.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires us to use our judgment to make estimates and assumptions that affect certain amounts reported in our financial statements. As additional information becomes available, these estimates and assumptions are subject to change and thus impact amounts reported in the future. Critical accounting policies are those accounting policies that involve judgment and uncertainties affecting the application of those policies and the likelihood that materially different amounts would be reported under different conditions or using differing assumptions. We periodically update our estimates used in the preparation of the financial statements based on our latest assessment of the current and projected business and general economic environment. There have been no significant changes to our critical accounting policies during the three months ended March 31, 2013.

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Natural Gas Production Operations Summary

The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the three months ended March 31, 2013 and 2012. This table should be read with the discussion of the results of operations for the periods presented below.