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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 June 30, 2012

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 August 1, 2012, 40,390,077 shares and 4,989,309 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 Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

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 an independent natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coalbed methane) and non-conventional shallow gas. Our principal operations and producing properties are located in Alabama, West Virginia and Virginia.

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2011 and the accompanying notes included in our Annual Report on Form 10-K, which we filed with the Securities and Exchange Commission (the “SEC”) on March 30, 2012.

Note 2—Liquidity and Going Concern Considerations

As previously disclosed in our Quarterly Report on Form 10-Q for the period ended March 31, 2012 (“First Quarter Report”), as of May 15, 2012, we had $148.6 million outstanding under our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”). As previously disclosed, the Credit Agreement provides that the borrowing base is set at the sole discretion of our lenders in June and December of each year based, in part, on the value of our estimated reserves as determined by the lenders using natural gas prices forecasted by the lenders. As of the filing date of our First Quarter Report, we expected that, due to the decline in the bank group’s price projections, the outstanding balance under the Credit Agreement at the June determination date would exceed the new borrowing base, resulting in a borrowing base deficiency which we would not be able to cure absent reaching a new agreement. As of the filing date of our First Quarter Report, the aforementioned conditions raised substantial doubt about our ability to continue as a going concern for the twelve months ended March 31, 2013.

As expected, on June 8, 2012, our bank lending group completed its June 2012 re-determination of our borrowing base under the Credit Agreement and notified us that our new borrowing base was $115.0 million, a reduction from the previous borrowing base of $180 million. As of June 8, 2012, we had $148.6 million drawn under the Credit Agreement, which resulted in a borrowing base deficiency of $33.6 million. As a result of this borrowing base deficiency, we were no longer able to borrow under the Credit Agreement.

In response to this borrowing base deficiency, we entered into the Fourth Amendment to our Fifth Amended and Restated Credit Agreement (the “Amendment”), effective August 8, 2012. The Amendment provides for an initial conforming borrowing base of $115.0 million (“Tranche A”) with the balance then remaining in the amount of $33.6 million constituting a non-conforming tranche (“Tranche B”). We are obligated, among other things, to reduce the balance of Tranche B each month by a certain amount of our excess cash flows for the period, as defined by the Amendment. In addition, we are no longer able to borrow any additional funds under the Credit Agreement, as amended.

The borrowing base will continue to be determined as of each June and December with the next determination scheduled to be completed by December 31, 2012. This Credit Agreement, as amended, matures on April 1, 2014.  We believe this amendment will allow us to continue normal production operations for at least the next twelve months and management believes we have the ability to comply with the terms of the Credit Agreement, as amended; however due to the uncertainty of natural gas prices, there are no assurances that there will not be an additional borrowing base deficiency at the December 2012 or any subsequent borrowing base redetermination, which is at the sole discretion of our lenders. For additional information related to the Credit Agreement, as amended, see Note 10—Long-Term Debt.

Note 3—Recent Pronouncements

On June 16, 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05, Presentation of Comprehensive Income, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and six months ended June 30, 2012.

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On May 12, 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). The ASU is the result of joint efforts by the FASB and IASB to develop a single, converged fair value framework—that is, converged guidance on how (not when) to measure fair value and on what disclosures to provide about fair value measurements. Thus, there are few differences between the ASU and its international counterpart, IFRS 13. While the ASU is largely consistent with existing fair value measurement principles in U.S. GAAP, it expands ASC 820’s existing disclosure requirements for fair value measurements and makes other amendments. Many of these amendments were made to eliminate unnecessary wording differences between U.S. GAAP and IFRS. However, some could change how the fair value measurement guidance in ASC 820 is applied. The ASU is effective for interim and annual periods beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three and six months ended June 30, 2012. See disclosure provided in Note 10—Long-Term Debt and Note 12—Series A Convertible Redeemable Preferred Stock.

Note 4—Net Loss Per Common Share

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 common shares would have an anti-dilutive effect. A reconciliation of Loss per common share is as follows:

Net loss per common share—diluted for the three months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 164,565 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 268,739 weighted average restricted shares outstanding, and 4,691,632 shares of Series A Convertible Redeemable Preferred Stock (36,089,476 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, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Net loss per common share—diluted for the six months ended June 30, 2012 excluded the effect of outstanding exercisable options to purchase 2,490,558 shares, 198,327 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 258,399 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, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

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Net loss per common share—diluted for the three months ended June 30, 2011 excluded the effect of outstanding exercisable options to purchase 2,603,536 shares, 232,089 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 350,906 weighted average restricted shares outstanding, and 4,278,124 shares of Series A Convertible Redeemable Preferred Stock (32,908,646 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, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Net loss per common share—diluted for the six months ended June 30, 2011 excluded the effect of outstanding exercisable options to purchase 2,603,536 shares, 232,089 restricted stock units for which common shares are distributed upon achievement of certain performance targets, 366,975 weighted average restricted shares outstanding, and 4,148,538 shares of Series A Convertible Redeemable Preferred Stock (31,911,830 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, restricted stock units, restricted shares and preferred shares to be anti-dilutive.

Note 5—Discontinued Operations

On June 20, 2012, we sold 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 to sell for one year. We recognized a loss on the sale 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 liabilities conveyed to the buyer and the proceeds consisting of the $0.3 million in fair value of the CEP shares received. The loss on the sale 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 all periods presented.

As a result of the sale, we are treating these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations were as follows:

Statements of Operations (Unaudited):

Balance Sheets (Unaudited):

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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 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. Depletion rates for the three and six months ended June 30, 2012 were $0.92 and $0.95 per Mcf, respectively. Depletion rates for the three and six months ended June 30, 2011 were both $0.83 per Mcf.

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. 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’ (deficit) 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, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of ASC 410-20-25, 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 June 30, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.17 per Mcf, resulting in a natural gas price of $3.34 per Mcf when adjusted for regional price differentials. For the three and six months ended June 30, 2012, we recorded a $42.3 million and a $58.0 million write-downs, respectively, of the carrying value of our U.S. full cost pool.

Note 7—Asset Retirement Liability

We record an asset retirement obligation (“ARO”) on 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 we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate.

The following table details the changes to our asset retirement liability for the six months ended June 30, 2012:

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The following table details the changes to our asset retirement liability for the six months ended June 30, 2011:

Note 8—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 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, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. We are limited by our credit facility (discussed in Note 10—Long-Term Debt ) to the amount of our natural gas derivative contracts during any period to no more than 85% 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. 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 June 30, 2012, we had the following natural gas collar positions:

At June 30, 2012, we had the following natural gas swap positions:

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At December 31, 2011, we had the following natural gas swap positions: