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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x         QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2009

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 001-16749

GeoPetro Resources Company

(Exact name of registrant as specified in its charter)

(415) 398-8186

(Registrant’s telephone number, including area code)

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.  Yes x No o.

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).  Yes o  No o

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 definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x.

There were 34,284,646 shares of no par value common stock outstanding on August 10, 2009.

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PART I. FINANCIAL INFORMATION

Item 1.   Financial Statements.

GEOPETRO RESOURCES COMPANY

UNAUDITED CONSOLIDATED BALANCE SHEETS

See accompanying notes to these unaudited consolidated financial statements.

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GEOPETRO RESOURCES COMPANY

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to these unaudited consolidated financial statements.

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GEOPETRO RESOURCES COMPANY

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to these unaudited consolidated financial statements.

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GEOPETRO RESOURCES COMPANY

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1.     BASIS OF PRESENTATION AND USE OF ESTIMATES:

The interim consolidated financial statements of GeoPetro Resources Company (“we,” “us,” “our,” “GeoPetro” or the “Company”) are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year or for previously reported periods due in part, but not limited to, the volatility in crude oil and natural gas commodity prices, interest rates, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product demand, market competition, interruption in production and our ability to obtain additional capital. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in GeoPetro’s Annual Report on Form 10-K for the year ended December 31, 2008.

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of GeoPetro and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which may affect the amount at which oil and natural gas properties are recorded. The computation of share-based compensation expense requires assumptions such as volatility, expected life and the risk-free interest rate. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Change in Accounting Method and Basis of Presentation - Revenue Recognition—Prior to December 31, 2008, revenue was recognized upon delivery of oil and gas production and was shown net of applicable royalty payments, as well as processing, gathering, transportation and marketing fees. The Company recognized revenue from the Madisonville Field net of applicable fees to gather, treat, transport and market the Company’s natural gas production. The applicable fees were paid to unrelated third parties.  On December 31, 2008, the Company completed the acquisition of the Plant from MGP. As of January 1, 2009, revenue is being recognized without the netting of applicable royalty payments, as well as processing, gathering, transportation and marketing fees since we have acquired the Plant. For all periods presented, revenue from the Madisonville Field is recognized when the price for gas delivered became fixed and determinable.

Impairment of Oil and Gas Properties—Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost center (country) do not exceed their fair value.  Impairment is recognized when the carrying value is greater than the discounted future cash flows.  In the event of impairment, the amount by which the carrying value exceeds the estimated fair value of the long-lived asset is charged to earnings. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.  We recognized no impairment of evaluated properties at June 30, 2009.

2.     LIQUIDITY:

As of June 30, 2009, we have a working capital deficit of $3,850,600, and for the six months ended, our cash used in operating activities amounted to $2,144,015.  We estimate our minimum investment needs during the remainder of 2009 amount to $4,500,000 related to our natural gas processing plant and our natural gas properties within the Madisonville field.  Our results of natural gas operations amounted to a deficit of $791,283 for the six months ended June 30, 2009.  Further, we have debt service and dividend requirements that will require cash payments.  We hold working interests in undeveloped leases, seismic options, lease options and foreign concessions and we have participated in seismic surveys and the drilling of test wells on undeveloped properties.  We plan further leasehold acquisitions and seismic operations for the remainder of 2009 and future periods.  Exploratory and developmental drilling is scheduled during 2009 and future periods on our undeveloped properties.  During the six months ended June 30, 2009, we raised $850,000 in convertible notes that were converted into our Series B Preferred Stock on April 30, 2009, raised another $1,000,000 in our Series B

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Preferred Stock, and issued $765,000 in promissory notes. We potentially plan to sell idle equipment from our natural gas processing plant.  In addition to these items, we need to raise additional equity or enter into new borrowing arrangements to finance our operating deficit and our continued participation in planned activities. If additional financing is not available, we will be compelled to reduce the scope of our business activities.  If we are unable to fund our operating cash flow needs and planned capital investments, it will be necessary to farm-out our interest in proposed wells, sell a portion of our interest in prospects, sell a portion of our interest in our producing oil and gas properties, reduce general and administrative expenses, or a combination of all of these factors.

3.     RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS:

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”). SFAS No. 141R, which among other things, establishes principles and requirements for how the acquirer in a business combination (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquired business, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. This standard will change our accounting treatment for business combinations on a prospective basis.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. Minority interests are recharacterized as noncontrolling interests and classified as a component of equity. It also establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary and requires expanded disclosures. This statement is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. The adoption of SFASB No. 160 on January 1, 2009 did not have a material impact on our financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133.  SFAS 161 amends and expands the disclosure requirements of FASB Statement No. 133 with the intent to provide users of financial statement with an enhanced understanding of (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and the related hedged items are accounted for under FASB Statement No. 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect and entity’s financial position, financial performance and cash flows.  The adoption of SFAS No. 161 on January 1, 2009 did not have a material impact on our reported financial position or results of operations.

In June 2008, the FASB ratified the consensus reached on Emerging Issues Task Force (“EITF”) Issue No. 07-05, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock (“EITF No. 07-05”). EITF No. 07-05 clarifies the determination of whether an instrument (or an embedded feature) is indexed to an entity’s own stock, which would qualify as a scope exception under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. EITF No. 07-05 is effective for financial statements issued for fiscal years beginning after December 15, 2008. Early adoption for an existing instrument is not permitted. The adoption of EITF No. 07-05 on January 1, 2009 did not have a material effect on our consolidated financial statements.

In December 2008, the SEC issued the final rule on the Modernization of Oil and Gas Reporting.  This SEC ruling revises its oil and gas reserves reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited.  These revisions by the SEC are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves.  These changes include:

·      Modifying prices used to estimate reserves for SEC disclosure purposes to a 12-month average price instead of a single-day, period-end price.

·      Requiring certain additional disclosures around proved undeveloped reserves, internal controls used to ensure objectivity of the estimation process, and qualifications of those preparing and/or auditing the reserves.

·      Expanding the definition of oil and gas reserves and providing clarification of certain concepts and technologies used in the reserve estimation process.

·      Allowing optional disclosure of probable and possible reserves and permitting optional disclosure of price sensitivity analysis.

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Historically, the reserves calculated based on the SEC’s reporting requirements were also used to calculate depletion on our producing properties, as required by SFAS 69, “Disclosures about Oil and Gas Producing Activities” (SFAS 69). However, the change in the SEC reporting requirements has not yet been adopted by the FASB. The SEC has announced its intent to discuss potential amendments to SFAS 69 with the FASB so that the reserves disclosed remain consistent with the reserves used to calculate depletion on our producing properties. Any such change would impact our future financial results. The SEC has indicated that it may delay the effective date of the revised reporting requirements if the FASB does not make conforming amendments by December 31, 2009.

On June 30, 2009, we adopted Statement of Financial Accounting Standards No. 165, Subsequent Events (SFAS 165). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Specifically, SFAS 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The adoption of SFAS 165 had no impact on the our results, cash flow or financial position as  management already followed a similar approach prior to the adoption of this standard.

4.     EARNINGS (LOSS) PER COMMON SHARE:

Basic net loss per common share is computed by dividing the net loss attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period.

Diluted net loss per common share is computed in the same manner, but also considers the effect of common stock shares underlying the following:

All of the common shares underlying the stock options, warrants and convertible preferred stock, Series B above were excluded from diluted weighted average shares outstanding for the six months ended June 30, 2009 because their effects were antidilutive. On June 30, 2008, the diluted weighted average shares outstanding included 58,703 common shares of warrants and 889,226 common shares of options.

5.     GAS PROCESSING PLANT

On December 31, 2008, the Company completed the acquisition of a natural gas treatment plant (the “Plant”) from Madisonville Gas Processing, LP (“MGP”), in exchange for shares of GeoPetro’s common stock, assumption of debt and a cash payment (“the Acquisition”). The Plant is located in Madison County, Texas and the new owner of the Plant is GeoPetro’s wholly-owned indirect subsidiary, Madisonville Midstream LLC (“MM”).

Our results of operations for the six months ended June 30, 2009 include the operating results of the Plant, but our results of operations for the six months ended June 30, 2008 do not include the operating results of the natural gas treatment plant because such acquisition closed on December 31, 2008. The following condensed pro forma information gives effect to the acquisition as if it had occurred on January 1, 2008. The pro forma information has been included in the notes as required by generally accepted accounting principles and is provided for comparison purposes only. The pro forma financial information is not necessarily indicative of the financial results that would have occurred had the acquisition been effective on the dates indicated and should not be viewed as indicative of operations in the future.

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6.     DEBT:

Debt at June 30, 2009 and December 31, 2008 consisted of the following:

(a)   The Company issued four promissory notes totaling $1,050,000 during December 2008 with maturity dates in December 2011. The notes may be repaid at any time without penalty. The notes bear an annual rate of eight percent (8%), with such interest payable quarterly in arrears. The principal amount and accrued and unpaid interest are due and payable on December 23, 2011. In connection with the notes, the Company paid loan origination fees totaling $6,000 and granted three-year exercisable warrants to purchase 105,000 Common Shares and reissued 15,000 warrants at $1.00 per share. We also issued 150,000 warrants as a finder’s fee. The fair value of the warrants on the dates of issuance, $122,764 and the $6,000 of loan origination fees, was recorded as a debt discount and is being amortized over the life of the promissory note. As of June 30, 2009, the unamortized debt discount was $106,937.

(b)   During the six months ended June 30, 2009 the Company borrowed $365,000 pursuant to two separate three-year loans. The notes have maturity dates in May 2012.  The notes may be repaid at any time without penalty.  The notes bear an annual rate of eight percent (8%), with such interest payable quarterly in arrears.  The principal amount and accrued and unpaid interest are due and payable on May 2012.  In connection with the notes, the Company granted three-year exercisable warrants to purchase 36,500 Common Shares warrants at $1.00 per share. The fair value of the warrants on the dates of issuance, $12,724, was recorded as a debt discount and is being amortized over the life of the promissory note. As of June 30, 2009, the unamortized debt discount was $12,194.

(c)   In June 2009 the Company borrowed $300,000 pursuant to two separate one-year loans. The two notes have maturity dates in May 2010.  The notes may be repaid at any time without penalty.  The notes bear an annual rate of eight percent (8%), with such interest payable quarterly in arrears.  The principal amount and accrued and unpaid interest are due and payable on May 2010.  In connection with the notes, the Company granted three-year exercisable warrants to purchase 30,000 Common Shares warrants at $1.00 per share. The fair value of the warrants on the dates of issuance, $7,537, was recorded as a debt discount and is being amortized over the life of the promissory note. As of June 30, 2009, the unamortized debt discount was $7,537.

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(d)   In June 2009 the Company borrowed $100,000 from a related party. The note is payable on demand.  The note bears an annual rate of eight percent (8%), with such interest payable at maturity.

(e)   Effective December 31, 2008, the Company assumed $7,697,847 of Madisonville Gas Processing LP’s (“MGP”) bank debt related to the Company’s acquisition of the Madisonville Gas Treatment Plant (the “Plant”) via a (i) $1 million cash payment applied directly towards debt principal reduction, and (ii) a refinancing by GeoPetro of the $6,697,847 remaining balance in the form of a 3 year Amended and Restated Term Loan Agreement with the lender, Bank Oklahoma (“BOK”).  The terms of the three year loan provide for minimum quarterly principal payments of $150,000 and interest payable quarterly in arrears at prime plus 4% or Libor plus 5.5% at the option of the Company. At June 30, 2009, the interest rate was 6.54% (LIBOR + 5.5%).  Additional principal will be payable upon GeoPetro meeting certain net operating cash flow thresholds during the three year term of the loan.  The loan is secured by a first lien on the Madisonville Midstream Plant and all of the Company’s proved natural gas reserves located at the Madisonville Project.  In addition, GeoPetro has agreed to pay, at the time the loan is repaid in full, a loan origination fee of $60,000 for any annual period during which the loan principal remains outstanding.  There is no prepayment penalty.  The Amended and Restated Term Loan Agreement contains customary affirmative and negative covenants including restrictions on incurring additional debt and requiring that the Company maintain a minimum tangible net worth of at least $35,000,000.

7.     INCOME TAXES:

The Company files income tax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or state income tax examinations underway.  Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2005 and for state and local tax authorities for tax years before 2004.  The Company does, however, have net operating losses generated in tax years 1997 and after, which remain open for examination.

The Company adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1, 2007. As December 31, 2008 the Company had no unrecognized tax benefits. There have been no changes during the year with respect to unrecognized tax benefits.  The Company does not foresee the total amounts of unrecognized tax benefits significantly increasing within the next 12 months.  Furthermore, no corresponding interest and penalties have been accrued as the Company is in a net operating loss position.

The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). SFAS 109 requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities. Where it is more likely than not that a tax benefit will not be realized, a valuation allowance is recorded to reduce the deferred tax asset to its realizable value.

A valuation allowance has been provided against the Company’s net deferred tax assets as the Company believes that it is more likely than not that the net deferred tax assets will not be realized.

The effective tax rate for the six month period ended June 30, 2009 was 0%, and for the year ended December 31, 2008 is (7.9) percent, and differs from statutory rates primarily due to changes in the valuation allowance.

8.     COMMON STOCK OPTIONS:

There were no material changes to common stock options from those disclosed in the audited annual consolidated financial statements for the year ended December 31, 2008 except the following.

On June 26, 2009, the Company granted a total of 60,000 options to four non-management directors. The weighted average fair value of options granted as calculated under the Black-Scholes pricing model was $0.33 per share with the following weighted-average assumptions: risk-free, weighted-average interest rate of 2.53 percent based on the U.S. Treasury yield curve in effect at the time of grant, expected dividend yield of 0 percent, expected life of 5 years from the date of grant, and expected volatility of 113 percent.

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On April 27, 2009. the Company reduced the option price previously granted to an officer from $2.10 per share to $1.00 per share based on the new employment agreement. The fair value of the repricing options was insignificant.

The options outstanding as of June 30, 2009 have the following contractual lives:

The total intrinsic value of options outstanding was approximately $0 and $3,366,500 at June 30, 2009 and 2008 respectively. The intrinsic value for exercisable options was $0 and $3,309,100 at June 30, 2009 and 2008, respectively.

As of June 30, 2009, there are 2,004,000 options which are exercisable. The remaining 716,000 options will become exercisable over the next four years. The stock compensation expense related to the unvested awards is $1,401,056.

9.     COMMON STOCK WARRANTS:

On April 10, 2009, the Company extended the expiration date on a warrant to purchase 114,000 shares of common stock (exercisable at $3.50 per share) to December 15, 2011.  The fair value of the warrant extension was insignificant.

On March 31, 2009, the Company extended the expiration date on a warrant to purchase 100,000 shares of common stock (exercisable at $5.25 per share) to March 31, 2014.  The fair value of the warrant extension was insignificant.

On February 23, 2009, the Company issued 50,000 shares of the common stock warrants to a non-related party expiring February 22, 2012 with a strike price of $1.00 per share. Warrants granted shall vest according the following schedule: 25% immediately; 25% at the three month anniversary of the signing of the agreement; 25% at the six month anniversary of the signing of the agreement; and 25% at the nine month anniversary of the signing of the agreement. The grant-date fair value of the warrants amounted to $8,106, using the Black-Scholes valuation method, which is recognized in general and administrative expense on our consolidated statement of operations ratably over the requisite service period as defined by the vesting schedule above.

10.  COMMITMENTS AND CONTINGENCIES:

There are no material changes to commitments and contingencies from those disclosed in the audited annual consolidated financial statements for the year ended December 31, 2008.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with accompanying financial statements and related notes included elsewhere in this report. It contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward looking statements.

Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas and oil, economic and competitive conditions, regulatory changes, estimates of proved reserves, potential failure to achieve production from development drilling projects, capital expenditures and other uncertainties, as well as those factors discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Notes Regarding Forward Looking Statements”, all of which are difficult to predict and which expressly qualify all subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf. In light of these risks, uncertainties and assumptions, the forward looking events discussed may not occur. We do not have any intention or obligation to update forward-looking statements included in this report after the date of this report, except as required by law.

Overview

We are an oil and gas company in the business of exploring and developing oil and natural gas reserves on a worldwide basis. Since inception, we have conducted leasehold acquisition, exploration and drilling activities on our North American, Australian and Indonesian prospects. These projects currently encompass approximately 379,547 gross (161,171 net) acres, consisting of mineral leases, production sharing contracts and exploration permits that give us the right to explore for, develop and produce oil and natural gas. Most of these properties are in the exploration, appraisal or development drilling phase and have not begun to produce revenue from the sale of oil and natural gas. Excluding minor interest and dividend income, our only significant cash inflows until 2003 were the recovery of capital invested in projects through sale or other divestiture of interests in oil and gas prospects to industry partners.

Since 2003, substantially all of our revenue has been generated from natural gas sales derived from the Magness #1, the Fannin #1, and the Mitchell #1 wells in the Madisonville Field in East Texas under spot gas purchase contracts at market prices. Natural gas sales from the Madisonville Field are expected to account for substantially all of our revenues for 2009. We expect the majority of our capital expenditures in 2009 will be for the Madisonville Project.

Results of Operations

The financial information with respect to the six months ended June 30, 2009 and 2008 that is discussed below is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods.  The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal years.

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Revenue and Operating Trends in 2009

We developed an onsite plan to treat and remove impurities from the Madisonville Project natural gas in order to meet pipeline-quality specifications. The Madisonville Project is located in East Texas. In 2003, the construction and installation of a natural gas treatment plant with a designed capacity of 18 million cubic feet of gas per day (“MMcf/d”) and associated pipeline and gathering facilities were completed. The treatment plant and associated gathering facilities were owned by an unaffiliated third party.

In 2005 we secured a commitment from MGP to install and make operational additional treating facilities capable of treating 50 MMcf/d, which combined with the capacity of the current in-service treating facilities will represent a total designed treating capacity of 68 MMcf/d for the Madisonville treatment plant.   In early November 2007, MGP began testing the additional treatment facilities by accepting 20 MMcf/d at the inlet.   Subsequently in December 2007, MGP temporarily suspended the operations of the additional treatment facilities in order to make modifications to more effectively deal with the presence of diamondoids in the gas stream produced from the Rodessa Formation.

During 2008, MGP analyzed various options for removing the diamondoids; however, they did not complete the necessary plant system modifications.  On December 31, 2008, we purchased the gas treatment plant (the “Plant”) and related gathering pipeline from MGP in exchange for assumption of secured debt, payment of certain outstanding payables of MGP and shares of GeoPetro’s common stock.  The effective date of the acquisition was December 31, 2008 and the new owner of the Plant is GeoPetro’s wholly-owned, indirect subsidiary, Madisonville Midstream LLC (“MM”).  We anticipate completing installation of the system modifications required in the plant in 2009 or in 2010.  In the meantime, the existing, in service portion of the plant continues to operate with an effective capacity of approximately 15 MMcf/d of inlet gas.

While there can be no assurance we will be successful, our goal is to make the necessary upgrades to the acquired gas treatment plant and increase the production rates from our wells which may result in higher net production and increased revenue during the later quarterly periods in 2009 as compared to the six months ended June 30, 2009. To accomplish the plant upgrades, we will need to raise capital in 2009. Due to the tight credit markets and persisting weakness in the stock market, funds may not be available, or may not be available on favorable terms.

During the six months ended June 30, 2009, we did not generate sufficient revenues to cover the plant operating expenses and lease operating expenses in our Madisonville Project.  This was due to low production volumes, high shrinkage rates in the gas plant and low natural gas prices.   In order to address this shortfall, we are implementing immediate measures to increase production volumes and reduce operating expenses. We utilized idle equipment and implemented operating efficiencies in the Plant to reduce the Plant inlet pressure in June 2009. This measure increases the combined production from the Magness #1 and Fannin #1 wells from current levels. In addition, subject to capital availability, we subsequently plan to workover the Mitchell #1 well and to frac and connect via gathering line the Wilson #1 well. Once the above production enhancements are completed, the Company expects the combined Rodessa formation production to increase from current rates.  The Company hopes to realize both intermediate and long term cost and operating efficiencies by consolidating the upstream and midstream portions of Madisonville under common ownership. Prior to the consolidation, MGP and GeoPetro employed a combined total of 30 persons, whereas subsequent to the consolidation, GeoPetro and MM now employ a combined total of 21 persons, representing a net reduction of 9 persons (30% of the combined pre-consolidation workforce). Despite the challenges of the current environment, we accomplished the necessary goal of vertically integrating our position in the Madisonville field.  We continue to explore other longer term cost saving and efficiency measures in the Plant.

Industry Overview for the six months ended June 30, 2009

The six months ended June 30, 2009 saw weaker natural gas prices. The Houston Ship Channel price, the index price prevailing in the locale of our Madisonville Project in Madison County, Texas, as quoted in Gas Daily as of June 30, 2009, was $3.88 per Mcf versus $5.25 per Mcf as of December 31, 2008.  Natural gas prices have been very volatile during 2008 and early 2009 due to supply concerns earlier in 2008, and more recently due to recession concerns arising from the current global financial crisis and a resultant decline in demand for natural gas.

Company Overview for the six months ended June 30, 2009

Our net loss after taxes for the six months ended June 30, 2009 was $3,381,585. From our inception, through mid-2003, we only received nominal revenues from our oil and natural gas activities, while incurring substantial acquisition and exploration costs and overhead expenses which have resulted in an accumulated deficit through June 30, 2009 of

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$15,591,912. Commencing in May 2003, we placed our Madisonville Project into production. All of our oil and natural gas sales for six months ended June 30, 2009 were derived from our Madisonville Project, from three producing wells, the Magness #1 well (the “Magness Well”), the Fannin #1 well (the “Fannin Well”), and the Mitchell #1 well (the “Mitchell Well”).

Comparison of Results of Operations for the three months ended June 30, 2009 and 2008

During the three months ended June 30, 2009, we had gross natural gas revenues from the treatment plant of $1,039,739 and revenues from treating third party gas in the Plant of $30,463. Our gross production from our wells was 357,276 Mcf (production net of royalties of 257,931 Mcf) of natural gas at an average price of $2.91 per Mcf. During the three months ended June 30, 2008, we had net oil and natural gas revenues of $2,650,992. Our net production for the three months ended June 30, 2008 was 374,534 Mcf at an average price of $7.08 per Mcf. Revenues decreased in the three months ended June 30, 2009 as compared to the prior year period due to lower natural gas prices and 31% lower net production volumes. Net natural gas prices were approximately 59% lower for the three months ended June 30, 2009 versus the same period in 2008.  The average natural gas price of $7.08 per Mcf for the 2008 period was net of treating, gathering, marketing and transportation fees in accordance with our contracts with MGP and Gateway ADAC Pipeline, LLC.  The contracts that were in place with MGP were terminated as of December 31, 2008.

Prior to December 31, 2008, revenue was recognized upon delivery of oil and gas production and was shown net of applicable royalty payments, as well as processing, gathering, transportation and marketing fees. As indicated in the preceding paragraph, the Company recognized revenue from the Madisonville Field net of applicable fees to treat, gather, transport and market the Company’s natural gas production. The applicable fees were paid to unrelated third parties.  On December 31, 2008, the Company completed the acquisition of the Plant from MGP. Commencing January 1, 2009, revenue is being recognized without the netting of applicable royalty payments, as well as processing, gathering, transportation and marketing fees since we have acquired the Plant. For all periods presented, revenue from the Madisonville Field is recognized when the price for gas delivered became fixed and determinable.

Our results of operations for the three months ended June 30, 2009 include the operating results of the Plant, but our results of operations for the three months ended June 30, 2008 do not include the operating results of the natural gas treatment plant because such acquisition closed on December 31, 2008. The following condensed pro forma information gives effect to the acquisition as if it had occurred on January 1, 2008. The pro forma information has been included in the notes to the financial statements included elsewhere in this document as required by generally accepted accounting principles and is provided for comparison purposes only. The pro forma financial information is not necessarily indicative of the financial results that would have occurred had the acquisition been effective on the dates indicated and should not be viewed as indicative of operations in the future.

During the three months ended June 30, 2009, we incurred plant operating expenses of $1,308,367. Our average plant operating cost for the 2009 period was $3.57 per Mcf on gross throughput of 366,371 Mcf. We purchased the gas treatment plant effective on December 31, 2008, thus there was no plant operating expense for the comparable 2008 period.

During the three months ended June 30, 2009, we incurred lease operating expense of $83,535. Our net average lifting cost for the 2009 period was $0.32 per Mcf. During the three months ended June 30, 2008, we incurred lease operating expense of $646,559. Our net average lifting cost for the 2008 period was $1.73 per Mcf. The average lifting cost per Mcf in 2009 was lower due to cost cutting efforts and a reduction of ad valorem property taxes applicable to the wells.

During the three months ended June 30, 2009, we incurred no net profits interest expense associated with the Magness, the Fannin, and the Mitchell wells as compared to $260,868 during the three months ended June 30, 2008. The decrease resulted from lower gas prices and production volumes in the three months ended June 30, 2009 versus 2008. The net profit interest is 12.5% of the net operating profit from our Magness, Fannin, and Mitchell wells.

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General and administrative (“G&A”) expenses for the three months ended June 30, 2009 were $616,655 compared to $604,090 for the three months ended June 30, 2008. This represents a $12,565 or 2% increased over the prior year period. The higher G&A expense incurred in 2009 was due primarily to the amortization of stock compensation expense associated with the newly issued options in June 2008.

For the three months ended June 30, 2009, no impairment expense was incurred versus $63,766 for the same period of 2008.  The 2008 impairment write-downs were due to remaining cost of certain dry holes drilled on our Canadian oil and gas properties, which resulted in ceiling test write downs.

Depreciation, depletion and amortization expense (“DD&A”) for the three months ended June 30, 2009 was $416,405 as compared to $448,305 in the same period of 2008, which amounts primarily represent amortization of the oil and gas properties for the three months ended June 30, 2009 and 2008, respectively. The 7% decrease was due to lower net production in the three months ended June 30, 2009.

Loss from operations totaled $1,354,760 for the three months ended June 30, 2009 as compared to income from operations of $627,404 for the three months ended June 30, 2008. The increase in the loss from operations was due primarily to lower gas prices, lower production volume, and higher expenses.

Other income for the three months ended June 30, 2009 and 2008 consisted of interest income in the amount of $330 and $17,803, respectively. Interest income decreased due primarily to lower average cash and cash equivalent balances because of the acquisition of the gas treatment plant on December 31, 2008.

During the three months ended June 30, 2009 and 2008, we incurred interest expense of $167,907 and $0, respectively. We borrowed funds in late December 2008 and the first two quarters of 2009 related to the plant acquisition and working capital requirements. There were no borrowings outstanding in the three months ended June 30, 2008.

Net loss before taxes for the three months ended June 30, 2009 was $1,522,337 as compared to net income before taxes of $645,207 for the three months ended June 30, 2008. The net loss incurred during the three months ended June 30, 2009 was primarily due to weaker gas prices, lower production volumes and expenses associated with the gas treatment plant.

Income tax expense for the three months ended June 30, 2009 was $1,845 compared to $8,495 in the same period of 2008. The income tax expense in 2009 was due to the payment of the Texas Franchise tax and the 2008 income tax was due to alternative minimum tax incurred in the second quarter of 2008.

Comparison of Results of Operations for the six months ended June 30, 2009 and 2008

During the six months ended June 30, 2009, we had gross natural gas revenues from the treatment plant of $1,878,153 and revenues from treating third party gas in the Plant of $68,117. Our gross production from our wells was 610,866 Mcf (production net of royalties of 441,277 Mcf) of natural gas at an average price of $3.07 per Mcf. During the six months ended June 30, 2008, we had net oil and natural gas revenues of $4,793,590. Our net production for the six months ended June 30, 2008 was 825,184 Mcf at an average price of $5.81 per Mcf. Revenues decreased in the six months ended June 30, 2009 as compared to the prior year period due to lower natural gas prices and 47% lower net production volumes. Net natural gas prices were approximately 47% lower for the six months ended June 30, 2009 versus the same period in 2008.  The average natural gas price of $5.81 per Mcf for the 2008 period was net of treating, gathering, marketing and transportation fees in accordance with our contracts with MGP and Gateway ADAC Pipeline, LLC.  The contracts that were in place with MGP were terminated as of December 31, 2008.

Prior to December 31, 2008, revenue was recognized upon delivery of oil and gas production and was shown net of applicable royalty payments, as well as processing, gathering, transportation and marketing fees. As indicated in the preceding paragraph, the Company recognized revenue from the Madisonville Field net of applicable fees to treat, gather, transport and market the Company’s natural gas production. The applicable fees were paid to unrelated third parties.  On December 31, 2008, the Company completed the acquisition of the Plant from MGP. Commencing January 1, 2009, revenue is being recognized without the netting of applicable royalty payments, as well as processing, gathering, transportation and marketing fees since we have acquired the Plant. For all periods presented, revenue from the Madisonville Field is recognized when the price for gas delivered became fixed and determinable.

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Our results of operations for the six months ended June 30, 2009 include the operating results of the Plant, but our results of operations for the six months ended June 30, 2008 do not include the operating results of the natural gas treatment plant because such acquisition closed on December 31, 2008. The following condensed pro forma information gives effect to the acquisition as if it had occurred on January 1, 2008. The pro forma information has been included in the notes to the financial statements included elsewhere in this document as required by generally accepted accounting principles and is provided for comparison purposes only. The pro forma financial information is not necessarily indicative of the financial results that would have occurred had the acquisition been effective on the dates indicated and should not be viewed as indicative of operations in the future.

During the six months ended June 30, 2009, we incurred plant operating expenses of $2,353,139. Our average plant operating cost for the 2009 period was $3.71 per Mcf on gross throughput of 634,192 Mcf. We purchased the gas treatment plant effective on December 31, 2008, thus there was no plant operating expense for the comparable 2008 period.

During the six months ended June 30, 2009, we incurred lease operating expense of $384,414. Our net average lifting cost for the 2009 period was $0.87 per Mcf. During the six months ended June 30, 2008, we incurred lease operating expense of $990,382. Our net average lifting cost for the 2008 period was $1.20 per Mcf. The average lifting cost per Mcf in 2009 was lower due to cost cutting efforts and a reduction of ad valorem taxes applicable to the wells.

During the six months ended June 30, 2009, we incurred no net profits interest expense associated with the Magness, the Fannin, and the Mitchell wells as compared to $488,929 during the six months ended June 30, 2008. The decrease resulted from lower gas prices and production volumes in the six months ended June 30, 2009 versus 2008. The net profit interest is 12.5% of the net operating profit from our Magness, Fannin, and Mitchell wells.

General and administrative (“G&A”) expenses for the six months ended June 30, 2009 were $1,465,593 compared to $1,319,513 for the six months ended June 30, 2008. This represents a $146,080 or 11% increase over the prior year period. The higher G&A expense incurred in 2009 was due primarily to the amortization of stock compensation expense associated with the newly issued options in June 2008.

For the six months ended June 30, 2009, no impairment expense was incurred versus $63,766 for the same period of 2008.  The 2008 impairment write-downs were due to remaining cost of certain dry holes drilled on our Canadian oil and gas properties, which resulted in ceiling test write downs.

Depreciation, depletion and amortization expense (“DD&A”) for the six months ended June 30, 2009 was $726,491 as compared to $982,735 in the same period of 2008, which amounts primarily represent amortization of the oil and gas properties for the six months ended June 30, 2009 and 2008, respectively. The 26% decrease was due to lower net production in the six months ended June 30, 2009.

Loss from operations totaled $2,983,367 for the six months ended June 30, 2009 as compared to income from operations of $948,265 for the six months ended June 30, 2008. The increase in the loss from operations was due primarily to lower gas prices, lower production volume, and higher expenses.

Other income for the six months ended June 30, 2009 and 2008 consisted of interest income in the amount of $3,973 and $47,868, respectively. Interest income decreased due primarily to lower average cash and cash equivalent balances because of the acquisition of the gas treatment plant in December 31, 2008.

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During the six months ended June 30, 2009 and 2008, we incurred interest expense of $400,346 and $0, respectively. We borrowed funds in late December 2008 and the six months ended June 30, 2009 related to the plant acquisition and working capital requirements. There were no borrowings outstanding in the same period of 2008.

Net loss before taxes for the six months ended June 30, 2009 was $3,379,740 as compared to net income before taxes of $996,133 for the six months ended June 30, 2008. The net loss incurred during the six months ended June 30, 2009 was primarily due to weaker gas prices, lower production volumes and expenses associated with the gas treatment plant.

Income tax expense for the six months ended June 30, 2009 was $1,845 compared to $15,295 in the same period of 2008. The income tax expense in 2009 relates to the Texas Franchise tax and the 2008 income tax expense was due to alternative minimum tax incurred in the same period of 2008.

Recent Developments

During the six months ended June 30, 2009 we borrowed $850,000 pursuant to five separate three year loans which were convertible into a newly designated class of preferred stock of GeoPetro, Series B Convertible Preferred Stock (the “Series B Preferred Stock”) and $765,000 pursuant to four separate three year loans.  The $850,000 in loans converted into Series B Preferred Stock on April 30, 2009, along with an additional $1,000,000 which was advanced during April for a total subscription in the private placement to date of 2,466,670 shares for a purchase price of $0.75 per share and an aggregate investment of $1,850,000. The holders of Series B Stock are entitled to receive an annual dividend at the rate of $0.06 per share and are entitled to such number of votes per share as equals the number of common shares into which each share of Series B Stock is convertible. Each share of Series B Stock is convertible, at the option of the holder, into fully paid and non-assessable common shares on a one-for-one basis, subject to certain adjustments. The Series B Stock will automatically convert into common shares on a one-for-one share basis effective the first trading day after the reported high selling price for the Company’s common shares on any international, national or regional securities exchange or inter-dealer quotation system including but not limited to, NASDAQ, the Pink Sheets or the Over-the-Counter Bulletin Board, is at least $1.50 per share for any ten consecutive trading days. If an automatic conversion occurs within one year after the Series B Stock was purchased from the Company, a holder will receive, on the one-year anniversary date of his, her or its purchase, a cash dividend equivalent to a full year of dividends less any dividends paid before such conversion.

In accordance with the provisions of an agreement with Adelphi Energy Limited (“Adelphi”) and our wholly owned subsidiary, GeoPetro Resources (South Bengara-II) Pte. Ltd., we relinquished our interest in the recently awarded South Bengara-II production sharing contract, onshore Indonesia.  On May 18, 2009, we received repayment of a loan we had previously made to Adelphi in the amount of $95,000 in connection with the acquisition of the production sharing contract.

Liquidity and Capital Resources

We had a working capital deficit of $3,850,600 at June 30, 2009 versus $2,151,652 at December 31, 2008. Our working capital decreased during six months ended June 30, 2009 due primarily to weaker gas prices and lower production.

We have historically financed our business activities through June 30, 2009 principally through issuances of common shares, promissory notes and common share purchase warrants in private placements and an initial public offering. These financings are summarized as follows:

The net proceeds of our equity financings have been primarily used in the working capital requirement and invested in oil and natural gas properties totaling $557,311 and $3,106,752 for the six months ended June 30, 2009 and 2008, respectively.

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Our cash balance at June 30, 2009 was $330,953 compared to a cash balance of $770,779 at December 31, 2008. The change in our cash balance is summarized as follows:

During the six months ended June 30, 2009, we raised $850,000 from the issuance of convertible loans and $765,000 from the issuance of promissory notes to accredited investors all of which were subordinated to the Bank of Oklahoma loan and unsecured.  The $850,000 promissory notes converted to Series B Preferred Stock effective April 30, 2009.  We raised an additional $1,000,000 from the issuance of Series B Preferred Stock in April 2009.

Our current cash and cash equivalents and anticipated cash flow from operations may not be sufficient to meet our working capital, capital expenditures and growth strategy requirements for the foreseeable future. See “Outlook for 2009” for a description of our expected capital expenditures for 2009. If we are unable to generate revenues necessary to finance our operations over the long-term, we may have to seek additional capital through the sale of our equity or borrowing. As noted in “Recent Developments,” we periodically borrow funds pursuant to short and long term promissory notes to finance our activities.

As of June 30, 2009, we have a working capital deficit of $3,850,600, and for the six months ended June 30, 2009, our cash used in operating activities amounted to $2,144,015.  Further, we estimate our minimum investment needs during the remainder of 2009 amount to be $4,500,000 related to our natural gas processing plant and our natural gas properties within the Madisonville field.  Due to the current natural gas commodity price environment, our results of natural gas operations amounted to a loss of $3,406,297 for the six months ended June 30, 2009.  Further, we have debt service and dividend requirements that will require cash payments.  We hold working interests in undeveloped leases, seismic options, lease options and foreign concessions and we have participated in seismic surveys and the drilling of test wells on undeveloped properties.  We plan further leasehold acquisitions and seismic operations for the remainder of 2009 and future periods.  Exploratory and developmental drilling is scheduled during 2009 and future periods on our undeveloped properties.  Subsequent to June 30, 2009, we are attempting to raise additional capital through a bridge loan financing and through issuance of additional shares of our Series B Preferred Stock, and we potentially plan to sell idle equipment from our natural gas processing plant.  In addition to these items, we need to raise additional equity or enter into new borrowing arrangements to finance our operating deficit and our continued participation in planned activities. If additional financing is not available, we will be compelled to reduce the scope of our business activities.  If we are unable to fund our operating cash flow needs and planned capital investments, it will be necessary to farm-out our interest in proposed wells, sell a portion of our interest in prospects, sell a portion of our interest in our producing oil and gas properties, sell all or a portion of our gas plant, reduce general and administrative expenses, or a combination of all of these factors.

As discussed in the “Outlook for 2009”, we are forecasting capital expenditures of $7.5 million during 2009. We will need to obtain adequate sources of cash to fund our anticipated capital expenditures through the end of 2009 and to follow through with plans for continued investments in oil and gas properties. Our success, in part, depends on our ability to generate additional financing and farmout certain of our projects.  Additionally, as a result of the 2008 economic downturn, the Company may have difficulty raising sufficient funds to meet our projected funding requirements. The tight credit markets and downturn in the stock market may impair our ability to generate additional financing.

We will continue to analyze the potential effects of the global economic downturn on our business and prospects and our ability to generate additional financing.

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Contractual Obligations

We have assumed various contractual obligations and commitments in the normal course of our operations and financing activities.  We have described these obligations and commitments in our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section in our Annual Report on Form 10-K for the year ended December 31, 2008.  There were no material changes to our contractual obligations since December 31, 2008 except the borrowings described in “Recent Developments”.

Off Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2009, our off-balance sheet arrangements and transactions include operating lease agreements. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Financial Instruments

We currently have no natural gas price financial instruments or hedges in place. Similarly, we have no financial derivatives. Our natural gas marketing contracts use “spot” market prices. Given the uncertainty of the timing and volumes of our natural gas production this year, we do not currently plan to enter into any long term fixed-price natural gas contracts, swap or hedge positions, other gas financial instruments or financial derivatives in 2009.

Outlook for 2009

Depending on capital availability, we are forecasting capital spending of up to approximately $7.5 million during the year 2009, allocated as follows:

1                          Madisonville Project, Madison County, Texas — Approximately $6.2 million may be expended in the Madisonville Field area as follows: $3 million for capital maintenance and repair on new gas treatment plant; $2 million toward the fracture stimulation and hook up costs of the Wilson Well; $500,000 for the Mitchell well workover; $400,000 for lowering the line pressure; and $300,000 for lease acquisitions.

2.                       Cook Inlet, Alaska — Approximately $1.0 million to be utilized for land delay rentals, geologic and geophysical costs, wellsite preparation, permitting, and logistics.

3.                       California and Indonesia — Approximately $0.3 million to be utilized for land, geologic and geophysical costs.

We may, in our discretion, decide to allocate resources towards other projects in addition to or in lieu of, those listed above should other opportunities arise and as circumstances warrant. We currently do not have sufficient working capital to fund all of the capital expenditure listed above. See “Liquidity and Capital Resources.”

We expect commodity prices to be volatile, reflecting the current supply and demand fundamentals for North American natural gas and world crude oil. Political events around the world, which are difficult to predict, will continue to influence both oil and gas prices. Higher prices for oil and gas often lead to higher levels of drilling activity which in turn lead to higher costs to explore, develop and acquire oil and gas reserves due to greater competition for resources and supplies. These higher costs could affect the returns on our capital expenditures. Higher crude prices could also help keep natural gas prices high by keeping alternative fuels, such as heating oil and residual fuel, expensive.

Impact of Inflation & Changing Prices

We are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impair our ability to raise additional capital on acceptable terms. Likewise, a material decrease in current and projected natural gas prices could also impact our revenues and cash flows. This could impact our ability to fund future activities.

GeoPetro anticipates significantly lower average natural gas prices in 2009 compared to 2008. This will likely have a material negative impact on our cash flow and revenues.

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Changing prices have had a significant impact on costs of drilling and completing wells, particularly in the Madisonville Field area where we are currently the most active. The estimated cost of drilling and completing a Rodessa formation well at approximately 12,300 feet of depth has increased from $3.0 million in 2001 to $7.5 million in 2008 due to higher costs associated with tubular goods, well equipment, and day rates for drilling contracts, among other factors. These higher costs have impacted and will continue to impact our income from operations in the form of higher depletion expense.  We have not recently updated our cost estimates for drilling these wells but expect that current costs are lower than those prevailing in 2008.

Critical Accounting Estimates

Our consolidated financial statements have been prepared by management in accordance with U.S. GAAP. We refer you to the corresponding section in Part II, Item 7 and the notes to the consolidated financial statements of our Annual Report on Form 10-K for the year ended December 31, 2008 for the description of critical accounting policies and estimates.

Risks and Uncertainties

There are a number of risks that face participants in the U.S., Canadian and international oil and natural gas industry, including a number of risks that face us in particular. Accordingly, there are risks involved in an ownership of our securities. See “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008 for a description of the principal risks faced by us.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks arising from fluctuating prices of crude oil, natural gas and interest rates as discussed below.

Commodity Risk.  Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas in the East Texas region. Prices received for natural gas are volatile and unpredictable and are beyond our control.

Currency Translation Risk.  Because our revenues and expenses are primarily in U.S. dollars, we have little exposure to currency translation risk, and, therefore, we have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

Hedging. We did not enter into any hedging transactions during the six months ended June 30, 2009 and 2008.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on their evaluation as of six months ended June 30, 2009, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and in providing reasonable assurance that information required to be disclosed by the Company in such reports is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

From time to time, we are party to litigation or other legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Currently, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flow or results of operations.

Item 1A.  Risk Factors.

As of the date of this filing, there have been no material changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008, referred to as our 2008 Annual Report. An investment in our securities involves various risks. When considering an investment in our company, you should consider carefully all of the risk factors described in our 2008 Annual Report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial.

Item 2.  Unregistered Sales of Securities and Use of Proceeds.

Unregistered Sales of Securities

During the quarter ended June 30, 2009, we  entered into a preferred stock purchase agreement for the private placement of 2,466,672 shares of newly designated Series B Convertible Preferred Stock, for a purchase price of $0.75 per share and an aggregate investment of $1,850,000.  We  issued the Series B Convertible Preferred Stock in reliance on the exemption from registration provided for under Section 4(2) of the Securities Act, and Rule 506 of Regulation D thereunder. We relied on the exemption from registration provided for under Section 4(2) of the Securities Act based in part on the representations made by the investors, including the representations with respect to the investors’ status as accredited investors, as such term is defined in Rule 501(a) of the Securities Act, and the their investment intent with respect to the shares purchased.

Use of Proceeds

On our registration statement on Form S-1 (Reg. No. 333-135485) we registered up to 16,499,991 shares of our common stock, no par value per share, including 4,301,355 shares of common stock issuable upon exercise of warrants and options, for resale by selling shareholders. The registration statement was declared effective by the Securities and Exchange Commission in February 2007. The offering commenced on in February 2007 and has not terminated. On our registration statement on Form S-1 (Reg. No. 333-146557) we registered up to 2,002,599 shares of outstanding common stock and the resale of up to 780,857 shares of common stock issuable upon exercise of warrants, for resale by selling shareholders. The registration statement was declared effective by the Securities and Exchange Commission in October 2007. The offering commenced in October 2007 and has not terminated. We will not receive any proceeds from the sale of our common stock by the selling shareholders under the registration statements; however if all warrants and options to acquire our common stock being registered thereunder are exercised, we will realize cash proceeds of approximately $16 million, which we expect to use for general working capital purposes and the drilling of wells in our Texas, Alaska, California and Indonesian prospects.

If less than the $16 million proceeds are realized from the exercise of such warrants and options, the proceeds will be spent in the following order of priority:

1.       Madisonville Project, Madison County, Texas. Up to approximately $10 million will be expended in the Madisonville Field area towards the drilling and completion of one deep exploratory well location to an estimated depth of 18,000 feet.

2.       Alaska Cook Inlet Project, up to approximately $2.0 million will be expended for the drilling of pilot program wells.

3.       General working capital.

We do not know if, or how many, of the warrants or options will be exercised. This is our best estimate of our use of proceeds generated from the possible exercise of warrants or options based on the current state of our business operations, our current plans and current economic and industry conditions. Any changes in the projected use of proceeds will be made at the sole discretion of our board of directors.

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Item 3.  Defaults Upon Senior Securities

Not applicable.

Item 4.  Submission of Matters to a Vote of the Security Holders.

On June 26, 2009, the Company held its annual stockholders meeting. The Board proposed, and the shareholders approved, (i) the election of each of the Company’s Directors for an additional term of one year to expire at the Company’s next Annual Meeting and (ii) ratification of the appointment of Hein & Associates LLP as the Company’s independent registered public accounting firm for the fiscal year ending December 31, 2009. The number or votes cast for and against, or withheld, as to each Director and for the Ratification of Hein & Associates, LLP were as follows:

Item 5.  Other Information.

Not applicable

Item 6.  Exhibits

EXHIBIT INDEX

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 10, 2009.

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