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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, 2014

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, 2014, 40,515,020 shares and 6,381,359 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 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,” the “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. Prior to the completion of the sale of substantially all of our remaining assets on May 12, 2014, we were primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production was 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 were active as an operator, developer and producer of coalbed methane properties since 1993. Our principal operations and producing properties were located in the central Appalachian Basin in Virginia and West 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, 2013 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 31, 2014.

Note 2—Recent Accounting Pronouncement

In April 2014, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The ASU changes the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when an entity meets the criteria to be classified as held for sale, the component of an entity or group of components of an entity is disposed of by sale, or the component of an entity or group of components of an entity is disposed of other than by sale. ASU 2014-08 should be applied when any of these occur within annual periods beginning on or after December 15, 2014. Early adoption is permitted; however, the Company elected not to early adopt the ASU. The ASU requires entities to separately present assets and liabilities of a discontinued operation for all periods presented in the balance sheet. The impact of adopting the ASU would be the reclassification of all of the assets related to our operations as Assets held for sale and all related liabilities as Liabilities held for sale, both in our Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement

On May 12, 2014, we closed the sale of substantially all of our remaining assets which consisted of coalbed methane interests and other assets located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership (the “Buyer”). The purchase price of $107.0 million was adjusted downward $10.0 million to account for purchase price adjustments, resulting in net proceeds of $97.0 million. The final settlement statement is expected to be provided to the Buyer on August 15, 2014. The Buyer has 10 days after receipt of the final settlement statement, or through August 25, 2014, to review and make any objections.

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the financial institutions party thereto terminated the Fifth Amended and Restated Credit Agreement, dated as of October 14, 2011, by and among GeoMet, the Administrative Agent, the financial institutions party thereto as lenders and the other agents party thereto (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Immediately prior to termination of the Credit Agreement, we repaid all amounts owed to the lenders party to the Credit Agreement, which amounts totaled $69.1 million. As a result, we satisfied all of our obligations under the Credit Agreement. We were not required to pay a termination penalty or other fee in connection with the termination of the Credit Agreement.

Additionally, we settled all of our remaining outstanding natural gas hedge positions for approximately $3.1 million.

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Note 4—Assets and Liabilities Related to Discontinued Operations and Results of Discontinued Operations

As a result of the Asset Sale, we have classified all of the assets related to our gas properties as Assets related to discontinued operations and all related liabilities as Liabilities related to discontinued operations, both in the Consolidated Balance Sheet (Unaudited) as of June 30, 2014. Additionally, the related operating activities are presented as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three and six months ended June 30, 2014 and 2013.

Assets related to discontinued operations in the Consolidated Balance Sheet (Unaudited) at June 30, 2014 include:

Liabilities related to discontinued operations in the Consolidated Balance Sheet (Unaudited) at June 30, 2014 include:

Results for activities reported as discontinued operations (unaudited) for the three and six months ended June 30, 2014 and 2013 were as follows:

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Note 5— Gain on the Sale of Assets

The total gain on sale of assets for the three and six months ended June 30, 2014 as presented above include the following:

Current year operating losses generated in the normal course of business are less than the estimated taxable gain from the Asset Sale.  However, no regular income tax is expected to result from the Asset Sale as we estimate sufficient net operating losses will be available from prior years to offset the estimated taxable gain, resulting in a reduction of our deferred tax asset and the related valuation allowance of $22.7 million. We are subject to the Alternative Minimum Tax and have estimated $0.7 million in Income taxes payable recorded in the Consolidated Balance Sheet (Unaudited) as of June 30, 2014.

Note 6— Pro Forma Financial Information

Pro forma adjustments related to the unaudited pro forma financial information presented below were computed assuming the asset sales completed in June 2013 and May 2014 were both consummated on January 1, 2013 and include adjustments which give effect to events that are (i) directly attributable to the asset sales, (ii) expected to have a continuing impact on the registrant, and (iii) factually supportable. As such, included in Net income (loss), Net income (loss) available to common stockholders and Net income (loss) per common share (basic and diluted) for the six months ended June 30, 2013 are the gains on the asset sales completed in June 2013 and May 2014 of $37,135,611 and $61,824,007, respectively.

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Note 7—Net Income Per Common Share

Net income per common share—basic is calculated by dividing Net income available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net income per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net income 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 Net income per common share for the three and six months ended June 30, 2014 and 2013 is as follows:

Net income per common share—diluted for the three months ended June 30, 2014 excluded the effect of 60,563 weighted average restricted shares outstanding, and 6,381,359 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) (49,087,376 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the three months ended June 30, 2014 for accretion of and dividends paid for Preferred Stock of $705,165 and $553,405, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net income per common share—diluted for the six months ended June 30, 2014 excluded the effect of 97,746 weighted average restricted shares outstanding, and 6,381,359 shares of Preferred Stock (49,087,376 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the six months ended June 30, 2014 for accretion of and dividends paid for Preferred Stock of $1,349,909 and $1,153,848, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net income per common share—diluted for the three months ended June 30, 2013 excluded the effect of outstanding exercisable options to purchase 2,099,658 shares, 205,083 weighted average restricted shares outstanding, and 5,471,610 shares of Preferred Stock (42,089,307 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the three months ended June 30, 2014 for accretion of and dividends paid for Preferred Stock of $532,836 and $1,368,056, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net income per common share—diluted for the six months ended June 30, 2013 excluded the effect of outstanding exercisable options to purchase 2,099,658 shares, 219,014 weighted average restricted shares outstanding, and 5,471,610 shares of Preferred Stock (42,089,307 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported Loss from continuing operations which caused the options, restricted shares and the Preferred Stock to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net income available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the shares of Preferred Stock are anti-dilutive. As such, there was no add back to Net income available to common stockholders for the six months ended June 30, 2014 for accretion of and dividends paid for Preferred Stock of $1,026,373 and $2,444,374, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

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Note 8—Gas Properties

As described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we sold substantially all of our remaining assets. Prior to the Asset Sale, the method of accounting for oil and gas producing activities determined which costs were capitalized and how these costs were ultimately matched with revenues and expenses. We used 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 were capitalized.

Gas properties were depleted using the units-of-production method. The depletion expense was 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 the 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.

No ceiling test was performed at June 30, 2014, as there was no longer any value in the full cost pool. For the twelve months ended June 30, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.47 per Mcf, resulting in a natural gas price of $3.53 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 June 30, 2013.

Note 9—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.

The following table details the changes to our ARO for the six months ended June 30, 2014:

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Note 10—Derivative Instruments and Hedging Activities

In connection with the closing of the Asset Sale described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement, we settled all of our outstanding natural gas hedge positions for approximately $3.1 million.

Prior to the closing of the Asset Sale, in an effort to reduce the effects of the volatility of the price of natural gas on our operations, management had historically hedged 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 limited the downside risk of adverse price movements, it also limited future gains from favorable movements. We entered into hedging transactions, generally for forward periods up to two years or more, which increased the probability of achieving our targeted level of cash flows. Our price risk management policy strictly prohibited the use of derivatives for speculative positions.

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 incurred accounting losses on derivatives during periods where prices were rising and gains during periods where prices were falling which caused significant fluctuations in our Consolidated Balance Sheets (Unaudited) and Consolidated Statements of Operations (Unaudited).

Commodity Price Risk and Related Hedging Activities

At June 30, 2014, we had no natural gas derivative contracts.

At December 31, 2013, we had the following natural gas derivative contracts:

We reviewed the financial strength of our hedge counterparties and believed our credit risk was minimal. Our hedge counterparties were participants or affiliates of the participants in the Credit Agreement and the collateral for the outstanding borrowings under the Credit Agreement was used as collateral for our hedges. We did not have rights to collateral from our counterparties, nor did we have rights of offset against borrowings under the Credit Agreement.

We estimated the fair value of our natural gas derivative contracts using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. 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 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 were used to discount future cash flows. The estimated fair value of our natural gas derivative contracts also reflected its nonperformance risk, the risk that the obligation would not be fulfilled. Because nonperformance risk included our counterparties’ and our credit risk, we had considered the effect of credit risk on the fair value of our natural gas derivative contracts. 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 1-Year 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 1-Year Treasury bill rate.

We did not have any derivative assets or derivative liabilities as of June 30, 2014 and there were no transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended June 30, 2014. Based on the use of observable market inputs, we had 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 on our hedging instruments have been classified as Discontinued operations on the Consolidated Statements of Operations (Unaudited) for the three and six months ended June 30, 2014 and 2013.