Table of Contents

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, 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 August 1, 2013, 40,662,749 shares and 5,642,541 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

Table of Contents

TABLE OF CONTENTS

2

Table of Contents

Part I. FINANCIAL INFORMATION

Item  1.                                Financial Statements

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

3

Table of Contents

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

4

Table of Contents

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

5

Table of Contents

GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

6

Table of Contents

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. Subsequent to the asset sale, our core area of operations is the Central Appalachian Basin of Virginia and West Virginia. We also own additional coalbed methane development rights, principally in Virginia and West Virginia.

Note 2— Sale of Coalbed Methane Properties in Alabama

On June 14, 2013, the Company closed the sale of all of its coal bed methane properties located in the state of Alabama. The sale resulted in proceeds of approximately $62.0 million after normal and customary purchase price adjustments of $1.2 million to account for net cash flows from the effective date to the closing date. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under the Company’s Credit Agreement and $5.0 million was held in reserve to pay transaction related costs and expenses, including the liquidation of certain natural gas hedge positions. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million and such amount has been established as the new borrowing base. In connection with this repayment the non-conforming “Tranche B” portion of total outstanding borrowings, which has existed since August 2012, has been eliminated and the Company no longer has a borrowing base deficiency under the Credit Agreement. The next scheduled borrowing base determination is expected to occur on or around December 15, 2013 and will be based on the Company’s reserves at June 30, 2013. The Credit Agreement continues to have a maturity date of April 1, 2014.

GeoMet’s net interest in the sold properties produced approximately 9,700 Mcf of natural gas per day during the month of March 2013 (the effective date of the sale was April 1, 2013), or approximately 29% of GeoMet’s total production for this time period. As of April 1, 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.

Total gain on the sale included the following:

No current federal or state income taxes payable were recorded in conjunction with the sale of the Alabama properties which is the result of 2013 tax basis operating losses generated in the normal course of business that are estimated to be available to offset the taxable gain. Additionally, under GAAP, our pre-gain net deferred tax asset of $97.4 million and the offsetting $97.4 valuation allowance recorded against it were both reduced by $14.2 million as a result of recording the gain. At June 30, 2013, the remaining net deferred tax asset is $83.2 million for which a full valuation allowance remains recorded against it.

Pro forma adjustments related to the unaudited pro forma financial information presented below were computed assuming the transaction was consummated on January 1, 2012 and include adjustments which give effect to events that are (i) directly attributable to the transaction, (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) is the Total gain on sale disclosed above of $37,135,611.

7

Table of Contents

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.  Although the recent sale of gas properties by the Company caused the Company to be in conformity with its borrowing base, the Company remains highly leveraged.  In addition, 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.  Also, as of June 30, 2013, the Company had a working capital deficit of $71.3 million, a retained deficit of $265.4 million and stockholders’ deficit of $74.1 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 for the next twelve months.

Management’s current business plan is to continue to evaluate its strategic alternatives. Additionally, management is seeking to divest properties with limited value and will consider additional asset sale opportunities as they arise. Management also remains focused on maintaining compliance with the Credit Agreement, as amended, maintaining production levels, and keeping costs under control.

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 Pronouncements

In July 2013, the FASB, issued ASU, No. 2013-10, Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes. The amendments in ASU 2013-10 permit the Fed Funds Effective Swap Rate (OIS) to be used as a U.S. benchmark interest rate for hedge accounting purposes under Topic 815, in addition to UST and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We are presently assessing the potential impact of ASU 2013-11.

In February 2013, the FASB issued 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 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.

8

Table of Contents

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. See disclosure provided in Note 9—Derivative Instruments and Hedging Activities.

Note 5—Net Income (Loss) Per Common Share

Net income (loss) per common share—basic is calculated by dividing Net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net income (loss) per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing Net income (loss) available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net income (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 Net income (loss) per common share is as follows:

Net income (loss) per common share—basic for both the three and six months ended June 30, 2013 included $0.92 per common share, net of $0 tax, resulting from the Gain on the sale of Properties in Alabama. Net income (loss) per common share—diluted for both the three and six months ended June 30, 2013 included $0.45 per common share, net of $0 tax, resulting from the Gain on the sale of Properties in Alabama.

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 and 231,457 weighted average restricted shares outstanding because they were assumed reacquired under the treasury stock method.

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 and 232,274 weighted average restricted shares outstanding because they were assumed reacquired under the treasury stock method.

9

Table of Contents

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.

Note 6—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.

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 and six months ended June 30, 2013 and 2012 were as follows:

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

10

Table of Contents

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 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.

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.

In accordance with the full cost method of accounting for gas properties as prescribed by the SEC, sales of oil and gas reserves in place are generally accounted for as adjustments of capitalized cost, with no gain or loss recognized, unless such adjustments significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center (i.e. depletion rate).  A significant alteration would not ordinarily be expected to occur for sales involving less than 25 percent of the reserve quantities of a given cost center.  The sale of the Alabama gas properties, as disclosed in Note 2— Sale of Coalbed Methane Properties in Alabama, would have significantly altered the depletion rate. As such, a gain on the sale was recorded in the Consolidated Statements of Operations for the three and six months ended June 30, 2013.

Note 8—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, 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. At June 30, 2013, we do not have the ability to enter into natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

11

Table of Contents

In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has 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 limits the downside risk of adverse price movements, it also limits 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 prohibits 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 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, 2013, we had the following natural gas derivative contracts:

At December 31, 2012, we had the following natural gas derivative contracts:

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

12

Table of Contents

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 and six months ended June 30, 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: