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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 September 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)

1221 McKinney Street, Suite 3840

Houston, Texas 77010

(713) 659-3855

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

Former address:

909 Fannin, Suite 1850

Houston, Texas 77010

(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).  x  Yes o  No

As of November 1, 2014, 40,513,373 shares and 6,580,726 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

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Part I. FINANCIAL INFORMATION

Item 1.                                   Financial Statements

GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (UNAUDITED)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1—Organization and Our Business

GeoMet, Inc. (“GeoMet,” 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 engaged in the exploration, 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.

From May 13, 2014 through August 15, 2014, we provided transition services to ARP Mountaineer Productions, LLC, purchaser of certain of our assets, while simultaneously working toward the completion of the final purchase price adjustment described in Note 3—Sale of our Central Appalachian Assets and Termination of Credit Agreement. On August 15, 2014, we became a “shell company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934, as amended, because we no longer had operations and our assets consisted of cash and nominal other assets.

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.

In August 2014, the FASB issued ASU, No. 2014-15, Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The ASU provides guidance on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date of issuance of the entity’s financial statements (or within one year after the date on which the financial statements are available to be issued, when applicable). Further, an entity must provide certain disclosures if there is “substantial doubt about the entity’s ability to continue as a going concern.” The ASU is effective for annual periods ending after December 15, 2016, and interim periods thereafter and early adoption is permitted. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

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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 (the “Buyer”) 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 $10.0 million to account for purchase price adjustments, resulting in net proceeds of $97.0 million. We provided the final settlement statement to the Buyer on August 15, 2014. The proposed final purchase price adjustment provided to the Buyer was $346,606, which has been recorded as a current liability in the Consolidated Balance Sheet (Unaudited) as of September 30, 2014 and is expected to be settled in the fourth quarter of 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 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—Results of Discontinued Operations

As a result of the Asset Sale, all operating activities are presented as discontinued operations in the Consolidated Statements of Operations (Unaudited) for the three and nine months ended September 30, 2014 and 2013 as follows:

(1)                  The $571,733 gain on the sale of assets for the three months ended September 30, 2014 primarily resulted from the reduction of the asset retirement obligation through the assignment of certain wells to a third party.

Note 5— Gain on the Sale of Assets

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

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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 $22.8 million. We are subject to a federal alternative minimum tax and have estimated that amount to be $676,444 for 2014. In September 2014, we made an estimated payment of $550,000 and $126,444 remains as a payable recorded in the Consolidated Balance Sheet (Unaudited) as of September 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 nine months ended September 30, 2013 are the gains on the asset sales completed in June 2013 and May 2014 of $36,948,313 and $62,395,740, respectively.

Note 7—Net (Loss) 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, par value $0.001 per share (the “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 (loss) income per common share for the three and nine months ended September 30, 2014 and 2013 is as follows:

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Net loss per common share—diluted for the three months ended September 30, 2014 excluded the effect of 6,383,526 weighted average shares of Series A Convertible Redeemable Preferred Stock, par value $0.001 per share (the “Preferred Stock “) (49,104,045 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) because we reported Loss from continuing operations which caused 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 September 30, 2014 for accretion of and dividends paid for Preferred Stock of $772,910 and $649,897, respectively, in computing Net loss per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net income per common share—diluted for the nine months ended September 30, 2014 excluded the effect of 6,193,507 weighted average shares of Preferred Stock (47,642,363 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance), 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 nine months ended September 30, 2014 for accretion of and dividends paid for Preferred Stock of $2,122,819 and $1,802,687, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net loss per common share—diluted for the three months ended September 30, 2013 excluded the effect of outstanding options exercisable to purchase 1,591,920 shares, 116,553 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 176,935 weighted average restricted shares outstanding, and 5,644,456 weighted average shares of Preferred Stock (43,418,898 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) 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 September 30, 2013 for accretion of and dividends paid for Preferred Stock of $598,611 and $1,277,889, respectively, in computing Net loss per common share—diluted as the shares of Preferred Stock were anti-dilutive.

Net income per common share—diluted for the nine months ended September 30, 2013 excluded the effect of outstanding options exercisable to purchase 1,591,920 shares, 116,553 weighted average restricted stock units for which common shares are distributed upon achievement of certain performance targets, 204,833 weighted average restricted shares outstanding, and 5,475,217 weighted average shares of Preferred Stock (42,117,057 in dilutive shares, as converted, which assumes conversion on the later of the first day of the period or date of issuance) 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 nine months ended September 30, 2013 for accretion of and dividends paid for Preferred Stock of $1,624,984 and $3,721,062, respectively, in computing Net income per common share—diluted as the shares of Preferred Stock were anti-dilutive.

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.

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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 September 30, 2014, as there was no longer any value in the full cost pool. For the twelve months ended September 30, 2013, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.62 per Mcf, resulting in a natural gas price of $3.68 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 September 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 nine months ended September 30, 2014:

(1)                  Consists of the estimated plugging and abandonment costs of our two remaining pinnate wells.

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.

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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 September 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 September 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 September 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 nine months ended September 30, 2014 and 2013.

Note 11—Long-Term Debt

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. Immediately following the closing of the Asset Sale, we repaid all outstanding borrowings under the Credit Agreement of $69.1 million.

During 2012, the amounts borrowed under the Credit Agreement exceeded the borrowing base. Borrowings under the 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 the 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, we closed the sale of all of our 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 Credit Agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under the Credit Agreement totaled $77.0 million.

For the three months ended September 30, 2014, we had no borrowings outstanding under the Credit Agreement. For the three months ended September 30, 2013, we had no borrowings and made payments of $3.0 million under the Credit Agreement. For the three months ended September 30, 2013, interest on the borrowings averaged 3.83% per annum.

For the nine months ended September 30, 2014, we had no borrowings and made payments of $71.6 million under the Credit Agreement. For the nine months ended September 30, 2013, we had no borrowings and made payments of $65.3 million under the Credit Agreement. For the period January 1, 2014 through May 12, 2014, interest on the borrowings averaged 5.00% per annum. For the nine months ended September 30, 2013, interest on the borrowings averaged 4.03% per annum.

The following is a summary of our long-term debt at September 30, 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 December 31, 2013 was estimated to be approximately $70.1 million.

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Note 12—Income Taxes

We record our income taxes using an asset and liability approach. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.

For tax reporting purposes, we have federal and state net operating losses (“NOLs”) of approximately $118.2 million and $132.5 million, respectively, at September 30, 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 2024 and the last one expires in 2033.

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 September 30, 2014 that is available to reduce future taxable capital gains and expires in 2017. Additionally, we have a federal capital loss carryforward of $0.2 million generated by the sale of other assets in 2014.

At September 30, 2014, we have a valuation allowance of $60.7 million recorded against our net deferred tax asset which includes $47.8 million related to our United States operations and $12.9 million related to the capital loss carryforward generated by the sale of Hudson’s Hope Gas, Ltd. in 2012 and other assets in 2014.

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