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 March 31, 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 May 1, 2014, 40,649,440 shares and 6,188,032 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)

FOR THE THREE MONTHS ENDED MARCH 31,

See accompanying Notes to Consolidated Financial Statements (Unaudited).

4

Table of Contents

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

See accompanying Notes to Consolidated Financial Statements (Unaudited).

5

Table of Contents

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

FOR THE THREE MONTHS ENDED MARCH 31,

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. Our principal operations and producing properties are 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.

7

Table of Contents

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. ASU 2014-08 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 adoption of the ASU would be the reclassification of all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in the Consolidated Balance Sheet (Unaudited) as of December 31, 2013.

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

On May 12, 2014, we closed the previously announced 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 purchase price of $107.0 million was adjusted downward $9.5 million primarily to account for cash flows from the effective date to closing, resulting in net proceeds of $97.5 million.  The final adjusted purchase price is to be determined within 95 days of the close of the Asset Sale or by August 15, 2014.

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 material 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.

Note 4—Assets and Liabilities Held For Sale and Discontinued Operations

As a result of meeting all of the relevant criteria established under GAAP, we have classified all of the assets included in the Asset Sale as Assets held for sale and all related liabilities as Liabilities held for sale, both in the Consolidated Balance Sheet (Unaudited) as of March 31, 2014. Additionally, the related operating activities are presented as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013.

Assets held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014 include:

Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014 include:

Results for activities reported as discontinued operations for the three months ended March 31, 2014 and 2013 were as follows:

8

Table of Contents

Note 5—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 shares of common stock would have an anti-dilutive effect. A reconciliation of Net loss per common share for the three months ended March 31, 2014 and 2013 is as follows:

Net loss per common share—diluted for the three months ended March 31, 2014 excluded the effect of outstanding exercisable options to purchase 1,555,508 shares, 135,343 weighted average restricted shares outstanding, and 6,188,032 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”) (47,600,246 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, 2014 for accretion of and dividends paid for Preferred Stock of $644,744 and $600,443, 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, 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 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 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.

9

Table of Contents

Note 6—Gas Properties

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale which included substantially all of our gas properties. Proved gas properties and accumulated depreciation, depletion, amortization and impairment of gas properties have been classified as a current asset in Assets held for sale in the Consolidated Balance Sheet (Unaudited) as of March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

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, 2014, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $4.02 per Mcf, resulting in a natural gas price of $4.14 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, 2014.

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.

Note 7—Asset Retirement Obligations

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. The buyer has assumed the entire current portion of our asset retirement obligation (“ARO”). Certain asset retirement obligations have been classified as a current liability in Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

We record an 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 three months ended March 31, 2014:

10

Table of Contents

(1)         The current portion of ARO as of March 31, 2014 has been classified as Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

Note 8—Derivative Instruments and Hedging Activities

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. On that date, in connection with the closing of the Asset Sale, we settled all of our outstanding natural gas hedge positions for approximately $3.1 million.

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 March 31, 2014, 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.

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 March 31, 2014, we had the following natural gas derivative contracts:

(1)                  At March 31, 2014, Derivative liability—current and Derivative liability—non-current have each been classified as a current liability in Liabilities held for sale in the Consolidated Balance Sheet (Unaudited). See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

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

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

11

Table of Contents

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 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 are used to discount future cash flows. The estimated fair value of our natural gas derivative contracts also 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 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 transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended March 31, 2014. 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:

The following losses on our hedging instruments have been classified as Discontinued operations on the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

12

Table of Contents

Note 9—Long-Term Debt

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. Immediately following the closing of the Asset Sale, we repaid all outstanding borrowing under our credit agreement of $69.1 million. Borrowings under our credit agreement have been classified as Liabilities held for sale in the Consolidated Balance Sheet (Unaudited) at March 31, 2014. See Note 4—Assets and Liabilities Held For Sale and Discontinued Operations for further discussion on the classification.

During 2012, the amounts borrowed under our credit agreement exceeded the borrowing base.  Borrowings under our credit agreement at August 8, 2012 totaled $148.6 million. On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended our credit agreement to provide for a tranche A loan in the amount of our borrowing base and a tranche B loan in the amount of the borrowing base deficiency.

On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in the state of Alabama. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under the Company’s credit agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under our credit agreement totaled $77.0 million.

Our 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. All outstanding borrowings under our credit agreement are due and payable on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. Our borrowing base is defined to be equal to the amount borrowed under our credit agreement. Our 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% or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00%. 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%. All financial covenants were deleted by the amendment to our credit agreement and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013 and thereafter).

As of March 31, 2014 and December 31, 2013, we had $70.0 million and $71.6 million, respectively, of borrowings outstanding under our credit agreement. As of March 31, 2014 and December 31, 2013, the interest rates applied to borrowings were 3.21% and 3.24%, respectively. For the three months ended March 31, 2014, we had no borrowings and made payments of $1.6 million under our credit agreement. For the three months ended March 31, 2014 interest on the borrowings averaged 4.02%. For the three months ended March 31, 2013, we had no borrowings and made payments of $4.5 million under our credit agreement. For the three months ended March 31, 2013 interest on the borrowings averaged 4.27%.

The following is a summary of our long-term debt at March 31, 2014 and December 31, 2013:

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 as of March 31, 2014 and December 31, 2013 was estimated to be approximately $69.4 million and $70.1 million, respectively.

Note 10—Income Taxes

As described in Note 3—Subsequent Events—Sale of our Central Appalachian Assets and Termination of Credit Agreement, on May 12, 2014, we closed the Asset Sale. In connection with the closing of the Asset Sale, we estimated income tax payable in the amount of $1.2 million, representing alternative minimum tax. No regular income tax is expected to result from the transaction as we estimate sufficient net operating losses will be carried forward from prior years to offset the estimated gain on the Asset Sale.

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.

13

Table of Contents

For tax reporting purposes, we have federal and state net operating losses (“NOLs”) of approximately $156.1 million and $162.6 million, respectively, at March 31, 2014 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOLs of approximately $156.0 million and $162.3 million, respectively, at December 31, 2013 that were available to reduce future taxable income. Our first material federal NOL carryforward expires in 2022 and the last one expires in 2034.

Additionally, for tax reporting purposes, we have a federal capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012, of approximately $33.9 million at March 31, 2014 that is available to reduce future taxable capital gains and expiring in 2017. Additionally, we have a federal capital loss carryforward of $0.2 million generated by the sale of other assets in 2014.

At March 31, 2014, we have a valuation allowance of $83.1 million recorded against our net deferred tax asset which includes $70.2 million related to our United States operations and $13.0 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012 and other assets in 2014.

The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a decrease of $0.3 million in the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate is as follows:

Note 11—Common Stock

As of March 31, 2014, shares of our Common Stock issued and outstanding were 40,659,872 and 40,649,440, respectively.  As of December 31, 2013, shares of our Common Stock issued and outstanding were 40,662,749 and 40,652,317, respectively. Included in shares of our Common Stock issued as of March 31, 2014 and December 31, 2013 were 10,432 shares of treasury stock held by the Company. Included in our Common Stock both issued and outstanding at March 31, 2014 and December 31, 2013 were 136,065 and 158,065 shares of restricted stock, respectively. During the three months ended March 31, 2014, 153 shares of restricted stock were forfeited and canceled upon the termination of an employee by the Company and 2,724 shares of restricted stock expired unvested and were canceled.

Note 12—Series A Convertible Redeemable Preferred Stock

At March 31, 2014 and December 31, 2013, 6,188,032 and 6,000,571 shares of Preferred Stock were issued and outstanding, respectively. At March 31, 2014, an additional 1,213,800 shares of our Preferred Stock are reserved exclusively for the payment of paid-in-kind dividends (“PIK dividends”). We measure the fair value of PIK dividends using the closing quoted NASDAQ market price on the dividend date (categorized as level 1). The following table details the activity related to the Preferred Stock for the three months ended March 31, 2014:

Note 13—Share-Based Awards

Our 2006 Long-Term Incentive Plan (the “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. However, the Company does not anticipate any additional grants will be awarded under the 2006 Plan in the immediate future. 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 Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.

14

Table of Contents

During the three months ended March 31, 2014, we recorded a compensation expense accrual of $39,343 which was allocated as an addition of $2,105 to lease operating expenses and an addition of $37,238 to general and administrative expense. 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. At March 31, 2014, the future compensation cost of all the outstanding awards is $27,150 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 0.65 years.

Incentive Stock Options

The table below summarizes incentive stock option activity for the three months ended March 31, 2014:

Non-Qualified Stock Options

The table below summarizes non-qualified stock option activity for the three months ended March 31, 2014:

Restricted Stock Awards

The table below summarizes non-vested restricted stock awards activity for the three months ended March 31, 2014:

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, 2014.

15

Table of Contents

Note 14— 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, 2014, 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.

16

Table of Contents

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 2013 Annual Report on Form 10-K that we filed with the Securities and Exchange Commission on March 31, 2014, 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, 2013, which are included in our 2013 Annual Report on Form 10-K.

Overview

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 central Appalachian Basin in Virginia and West Virginia.

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 flows from operations, bank borrowing and equity raises.

Recent Developments

On May 12, 2014, we closed the previously announced 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 purchase price of $107.0 million was adjusted downward $9.5 million to account for cash flows from the effective date to closing, resulting in net proceeds of $97.5 million.  The final adjusted purchase price is to be determined within 95 days of the close of the Asset Sale or by August 15, 2014

Immediately following the closing of the Asset Sale, GeoMet, Bank of America, N.A., as administrative agent (the “Administrative Agent”), and the banks 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 approximately $69.1. As a result, we satisfied all of our material 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. 

The Asset Purchase Agreement required that all of our employees who accepted employment with the Buyer following the consummation of the Asset Sale first resign their employment with us. Our board of directors adopted a plan of termination effective as of the closing of the Asset Sale, pursuant to which we will terminate all employment agreements, change of control agreements and plans, and benefit plans including its long-term incentive plan, and, in exchange for releases, pay the severance benefits and change of control payments provided for under all of such agreements and plans, including a cash amount in lieu of reimbursement of COBRA premiums, as if all of such employees had been terminated (estimated to total approximately $4 million).  See executive compensation arrangements described below.  We have concluded that we will need to continue to employ various people to provide certain services to the Buyer during the 90-day transition period following the closing of the Asset Sale, and to comply with our public reporting requirements.   These remaining employees, including our named executive officers, will be employed on an at-will basis.

The remaining balance of the net proceeds from the Asset Sale totaled approximately $24 million.  These funds will be held by the Company and used for normal working capital and operating expense purposes while we evaluate our next steps. We currently anticipate that the Asset Sale will be followed by either a business combination/merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

Executive Compensation Arrangements

Effective as of the closing of the Asset Sale, each of Mr. William C. Rankin,  the Company’s President and Chief Executive Officer, Mr. Tony Oviedo, the Company’s Senior Vice President, Chief Financial Officer, Chief Accounting Officer and Controller, and Mr. Brett S. Camp, the Company’s Senior Vice President – Operations, entered into an (i) Agreement Concerning Termination of Employment Agreement and General Release (the “Severance Agreement”) and (ii) Agreement Concerning Forfeiture of Restricted Stock and Restricted Stock Units under the GeoMet, Inc. 2006 Long-Term Incentive Plan (the “Forfeiture Agreement”). 

   William C. Rankin

Under the terms of Mr. Rankin’s Severance Agreement, Mr. Rankin and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Rankin’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Rankin an amount equal to (i) $1,024,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Rankin would have received if Mr. Rankin’s employment was

17

Table of Contents

terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Rankin was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Rankin in a single lump sum on May 30, 2014.

Pursuant to the Severance Agreement, Mr. Rankin’s employment with the Company will continue on an at-will basis, terminable by either Mr. Rankin or the Company for any reason with or without notice.  Mr. Rankin will be a part-time employee and dedicate an average of 20% of his working time to the Company. Mr. Rankin’s base salary following the closing of the Asset Sale is $1,250.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Rankin agreed to release the Company and its affiliates from any and all claims.

Pursuant to Mr. Rankin’s Forfeiture Agreement, Mr. Rankin agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Rankin immediately prior to the closing of the Asset Sale.

   Tony Oviedo

Under the terms of Mr. Oviedo’s Severance Agreement, Mr. Oviedo and the Company terminated the Amended and Restated Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Oviedo’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Oviedo an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Oviedo would have received if Mr. Oviedo’s employment was terminated in connection with the Asset Sale), plus (b) $24,391.98 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Oviedo was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Oviedo in a single lump sum on May 30, 2014.

Pursuant to the Severance Agreement, Mr. Oviedo’s employment with the Company will continue on an at-will basis, terminable by either Mr. Oviedo or the Company for any reason with or without notice.  Mr. Oviedo will be a full-time employee and dedicate an average of 100% of his working time to the Company. Mr. Oviedo’s base salary following the closing of the Asset Sale is $4,625.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Oviedo agreed to release the Company and its affiliates from any and all claims.

Pursuant to Mr. Oviedo’s Forfeiture Agreement, Mr. Oviedo agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Oviedo immediately prior to the closing of the Asset Sale.

   Brett S. Camp

Under the terms of Mr. Camp’s Severance Agreement, Mr. Camp and the Company terminated the Employment Agreement entered into by such parties on May 14, 2012,  agreed to thereafter continue Mr. Camp’s employment with the Company on an at-will basis, and agreed that the Company would pay Mr. Camp an amount equal to (i) $630,000.00 (which amount is equal to estimated amount of severance pay under the terminated employment agreement that Mr. Camp would have received if Mr. Camp’s employment was terminated in connection with the Asset Sale), plus (b) $35,070.48 (which amount is equal to the estimated amount of the severance benefits under the terminated employment agreement if Mr. Camp was to become entitled to such benefits for the full number of months specified in such agreement), less all required withholdings and deductions.  Such payment would be made to Mr. Camp in a single lump sum on May 30, 2014.

Pursuant to the Severance Agreement, Mr. Camp’s employment with the Company will continue on an at-will basis, terminable by either Mr. Camp or the Company for any reason with or without notice.  Mr. Camp will be a part-time employee and dedicate an average of 50% of his working time to the Company. Mr. Camp’s base salary following the closing of the Asset Sale is $2,310.00 per week, less all required withholdings and deductions, payable on the Company’s customary payroll dates.  In consideration of the payments described above, Mr. Camp agreed to release the Company and its affiliates from any and all claims.

Pursuant to Mr. Camp’s Forfeiture Agreement, Mr. Camp agreed to forfeit, for no monetary consideration, all unvested restricted stock and restricted stock units in the Company held by Mr. Camp immediately prior to the closing of the Asset Sale.

Areas of Operation

Prior to the closing of the Asset Sale, our core areas of operations were in the Central Appalachian Basin of Virginia and West Virginia. We also previously had operations located in the Black Warrior and Cahaba Basins in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama and, on May 12, 2014, closed the sale of substantially all of our remaining assets which were located in the Central Appalachian Basin of Virginia and West Virginia.

Central Appalachia

Pond Creek and Lasher Fields—We were the operator of 298 producing vertical CBM wells in which we owned 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 15.3 MMcf per day for the three months ended March 31, 2014. Our natural gas production from the Pond Creek field was delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We had 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 was delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also owned and operated a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production was gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system. In addition, we owned and operated a disposal well to dispose of produced water from both the Pond Creek and Lasher fields.

18

Table of Contents

Pinnate Horizontal Wells—We were the operator of 44 producing pinnate horizontal CBM wells in which we owned a 71.6% average working interest in central and northern West Virginia. We also had a 33.7 % average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. Net daily sales of natural gas averaged 6.0 MMcf per day for the three months ended March 31, 2014.  We were party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring through November 2024 which could have been automatically extended at GeoMet’s option at the maximum tariff rate. We were also party to a 10,000 MMBtu per day gathering contract that was in a month-to-month evergreen term.  In some cases, our natural gas sales volumes were delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes were sold at a delivery point into the respective interstate pipeline system utilized.

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, 2014.

Natural Gas Production Operations Summary

As a result of meeting all of the criteria established under GAAP, we have presented our natural gas operating results as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three months ended March 31, 2014 and 2013. The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the three months ended March 31, 2014 and 2013. This table should be read with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).