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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, 2011

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 42,173,101 shares of no par value common stock outstanding on August 15, 2011

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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 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

UNAUDITED STATEMENT OF SHAREHOLDERS’ EQUITY

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, 2010.

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.

2.              LIQUIDITY

As of June 30, 2011, we had a working capital deficit of $3,919,302, and for the six months ended June 30, 2011, our cash used in operating activities amounted to $2,477,064.  We estimate that our investment needs during the remainder of fiscal year 2011 and in 2012 will amount to $3,207,000 related to our natural gas processing plant and our natural gas properties within the Madisonville field and our California properties.  Our results of operations resulted in an accumulated deficit of $46,351,502 from inception through the six months ended June 30, 2011.  Further, we have maturing debt obligations, debt service, lease obligations and dividend requirements that will require cash payments.  We hold working interests and overriding royalty 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 fiscal year 2011 and future periods.  Exploratory and developmental drilling is scheduled during the remainder of fiscal 2011 and future periods on our undeveloped properties.  We will need additional financing to continue development. 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 may 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

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our Form 10-K for the year ended December 31, 2010.

4.              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:

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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 three and six months ended June 30, 2011 and June 30, 2010 respectively because their effects were considered antidilutive.

5.              OIL AND GAS PROPERTIES

There were no material changes to oil and gas properties from those disclosed in the audited annual consolidated financial statements for the year ended December 31, 2010.

On April 1, 2011, we entered into a Purchase and Sale Agreement with Peregrine Midstream Partners LLC “Peregrine” whereby we agreed to sell certain equipment at the Madisonville Treatment Facility for $8.75 million subject to certain regulatory approvals.  On May 31, 2011 the potential sale price was increased to $9.3 million and the closing of the transaction was no longer subject to regulatory approval. Pursuant to the pending transaction we have received cash totaling $325,000 as of June 30, 2011.  These amounts are non-refundable (except for a material breach of the Amended PSA by Madisonville), and they will be credited to the purchase price at the time of closing. Peregrine paid an additional $50,000 on July 28, 2011. We have recorded the amounts received in connection with this pending transaction as non refundable deposits.

On August 10, 2011 the PSA with Peregrine was amended for a second time. In connection with this second amendment the closing date for the transaction has been set to occur no later than September 19, 2011.  An additional $1.2 million in non-refundable cash was received by the Company to be applied to the purchase price with the remaining $7.675 million to be paid at the time of closing. Of the $1.2 million received $700,000 was used for the repayment of outstanding principal on our Bank of Oklahoma term loan. At the time of the closing of the transaction the remaining proceeds from this sale will be used for the repayment of the  remaining outstanding principal and accrued interest of the term loan (Note 6).

On May 8, 2011 Madisonville Midstream LLC suspended operations of its Madisonville Treating Facility for maintenance. The maintenance turnaround was extended when additional maintenance requirements and upgrade opportunities were identified.  The field work required a curtailment of our production.

6.              DEBT

As of June 30, 2011 and December 31, 2010 debt consisted of the following:

(a)          In March 2011, the Company modified its bank loan with Bank of Oklahoma, (“BOK”) the Fourth Amendment of the Amended and Restated Term Loan Agreement which extended the loan by an additional year so as to have the new maturity date being December 31, 2012.  In June 2011, the Company modified its bank loan with BOK, the Fifth Amendment of the Amended and Restated Term Loan Agreement which: (1) waived the minimum quarterly payment due on June 30, 2011; (2) provides for subsequent minimum quarterly payments of $183,000; (3) provided for an additional $1,000,000 in advances under the term loan of which $600,000 was drawn on June 16, 2011 and $400,000 on July 15, 2011; and (4) provides for the repayment of all outstanding principal and accrued interest under the BOK term loan pursuant to the pending sale of equipment to Peregrine Midstream Partners LLC. (Note 5). The Fifth Amendment did not change the terms of accrued interest, which remains payable quarterly in arrears at prime plus 3.25% or Libor plus 4.75% at the option of the Company.  This Fifth Amendment agreement contains customary affirmative and negative covenants. As of June 30, 2011 we were in compliance with all the covenants related to this loan.

(b)         In February 2011, Stuart J. Doshi, President and CEO, advanced $125,000 to the Company.  The note bears interest at 8% per annum and is payable on demand. We have included this amount in the current portion of notes payable on our unaudited consolidated balance sheet. Interest expense accrued on this note as of June 30, 2011 amounted to $3,425.

(c)      In February 2011, we extended seven notes totaling $1,515,000 for one additional year. In connection with these extensions, the Company extended warrants to purchase our common stock associated with the notes for an additional year. The fair value associated with the warrant extension was $7,788.

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7.              INCOME TAXES

The effective income tax rates for the six month period ending June 30, 2011 were negligible, primarily due to adjustments to the valuation allowance on deferred tax assets.

8.              STOCKHOLDERS’ EQUITY

On March 31, 2011, we completed a unit sale through a private placement transaction to certain institutional and individual accredited investors. Units were priced at $0.45 per unit, and each unit consisted of one share of no par value common stock, and a one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $0.75 for a period of three years. The total aggregate purchase price for the units sold was $922,648, and represented the sale of 2,050,328 common shares and 1,025,164 warrants (Note 10).  We granted “piggyback” registration rights to the investors with respect to the shares of common stock and common stock issuable upon exercise of the warrants which the investors acquired in the transaction.

On June 30, 2011, we completed a unit sale through a private placement transaction to certain institutional and individual accredited investors. Units were priced at $0.55 per unit, and each unit consisted of one share of no par value common stock, and a one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $1.00 for a period of three years. The total aggregate purchase price for the units sold was $556,560, and represented the sale of 1,011,928 common shares and 505,965 warrants (Note 10).  We granted “piggyback” registration rights to the investors with respect to the shares of common stock and common stock issuable upon exercise of the warrants which the investors acquired in the transaction.

9.              COMMON STOCK OPTIONS

On April 16, 2011, 150,000 common stock options with an exercise price of $3.85 per share expired.  Other than these expirations, there were no other material changes to common stock options from those disclosed in the audited annual consolidated financial statements for the year ended December 31, 2010.

10.      COMMON STOCK WARRANTS

On February 24, 2011 we extended a total of 151,500 warrants for an additional year in conjunction with the renewal of seven of our promissory notes payable (Note 6). The warrants expire in December 2012, May 2013, and June 2013, respectively.  The total fair value of the warrants as calculated using the Black - Scholes pricing model was $7,788. Key assumptions used in valuing the warrants included: an estimated dividend yield of 0%, volatility of 78.12%, an estimated risk-free interest rate based on the U.S. Treasury yield curve at the date of grant of 0.26% and an expected life of three years.

On March 1, 2011, we issued 1,025,164 warrants to purchase our common shares at $0.75 in conjunction with a private placement of our common stock (Note 8). The warrants expire on March 1, 2014.  The total fair value of the warrants as calculated using the Black-Scholes pricing model was $207,943.  Key assumptions used in valuing the warrants included: an estimated dividend yield of 0%, volatility of 77.65%, an estimated risk-free interest rate based on the U.S. Treasury yield curve at the date of grant of 1.15% and an expected life of three years.

On April 28, 2011, we issued 505,965 warrants to purchase our common shares at $1.00 in conjunction with a private placement of our common stock (Note 8). The warrants expire on April 28, 2014.  The total fair value of the warrants as calculated using the Black-Scholes pricing model was $165,105.  Key assumptions used in valuing the warrants included: an estimated dividend yield of 0%, volatility of 96.36%, an estimated risk-free interest rate based on the U.S. Treasury yield curve at the date of grant of 1.03% and an expected life of three years.

As of June 30, 2011 we have reserved 5,563,194 shares of common stock for the exercise of our stock purchase warrants.

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11.       SUBSEQUENT EVENTS

We have evaluated all activity of the Company and concluded that no subsequent events have occurred that would require recognition in the consolidated financial statements or disclosure in the notes to the consolidated financial statements, except as disclosed below:

On July 11, 2011 80,000 shares of our Series B preferred shares were converted to common stock on a one to one basis.

On July 15, 2011, we borrowed an additional $400,000 on the Bank of Oklahoma loan, under the terms of the Fifth Amendment of the amended and restated term loan agreement.

On August 10, 2011 the PSA with Peregrine related to the sale of idle equipment at our Madisonville Treating Facility was amended for a second time. In connection with this second amendment the closing date for the transaction has been set to occur no later than September 19, 2011.  An additional $1.2 million in non-refundable cash was received by the Company to be allocated to the purchase price with the remaining $7.675 million to be paid at the time of closing. Of the $1.2 million received in connection with the amendment $700,000 was used in the repayment of principal on our Bank of Oklahoma term loan.

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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”, 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 247,218 gross (33,302 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 all of our revenues for 2011. We expect the majority of our capital expenditures for the remainder of 2011 and in 2012 will be for the Madisonville Project and the gas processing plant.

Results of Operations

The financial information with respect to the three and six months ended June 30, 2011 and 2010 as 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.

Revenue and Operating Trends

We have 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.

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In 2005 we secured a commitment from the Madisonville Gas Plant (“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 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.

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”).

While there can be no assurance, our goal is to make the necessary upgrades to the plant and increase the production rates from our wells which may result in higher net production and increased revenue during the remainder of 2011 as compared to 2010 and prior periods. To accomplish the plant upgrades, we will need to raise additional capital. Due to the unsettled state of the capital markets, funds may not be available, or may not be available on favorable terms.

During the three and six months ended June 30, 2011, 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 on May 8, 2011 MM suspended operations of its Madisonville Treating Facility for maintenance. The maintenance turnaround was extended when additional maintenance requirements and upgrade opportunities were identified.  The field work required a curtailment of our production which we anticipate will resume in August 2011.

Subject to capital availability, we plan to workover the Mitchell #1 well and to frac and connect via gathering line the Wilson #1 well during remainder of fiscal 2011 and in 2012. Once the above production enhancements are completed, the Company expects the combined Rodessa formation production to increase from current rates.  The Company hopes to continue to realize both intermediate and long term cost and operating efficiencies by consolidating the upstream and midstream portions of Madisonville under common ownership. 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 three and six months ended June 30, 2011

Natural gas prices have been volatile due to concerns surrounding the current global financial crisis and a resultant decline in demand for natural gas. Fluctuations in the price for natural gas are closely associated with customer demand relative to the volumes produced and the level of inventory in underground storage.

Company Overview for the three and six months ended June 30, 2011

Our net loss applicable to common shareholders for the three and six months ended June 30, 2011 was $1,338,266 and $2,789,644, respectively.  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, 2011 of $46,351,502.  All of our natural gas sales for three and six months ended June 30, 2011 were derived from our Madisonville Project, from two producing wells, the UMC Ruby Magness #1 well (the “Magness Well”) and the Angela Farris Fannin #1 well (the “Fannin Well”). On May 8, 2011 MM suspended operations of its Madisonville Treating Facility for maintenance. The maintenance turnaround was extended when additional maintenance requirements and upgrade opportunities were identified.  The field work required a curtailment of our production which we anticipate will resume in August 2011.

Comparison of Results of Operations for the three months ended June 30, 2011 and 2010

During the three months ended June 30, 2011, we had gross natural gas revenues of $206,590. During this period the sales of gas from our wells amounted to 52,255 Mcf and our average natural gas price realized was $3.95 per Mcf. During the three months ended June 30, 2010 we had gross natural gas revenues of $810,796. Our natural gas sales for the three months ended June 30, 2010 were 205,128 Mcf and our average natural gas price realized was $3.95 per Mcf. Revenues decreased during the three months ended June 30, 2011 as compared to the prior year period due to a 75% decrease in production volumes related to normal decline curves as well as treatment plant downtime resulting from maintenance.

During the three months ended June 30, 2011, we incurred plant operating expenses of $604,781. During the three months ended June 30, 2010, the plant operating expense was $1,046,835.  The decrease in plant operating expense of $442,054 or 42% was primarily attributable to cost cutting measures at our facility coupled with the fact that on May 8, 2011 MM suspended operations of its Madisonville Treating Facility for maintenance. The maintenance turnaround was extended when additional maintenance requirements

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and upgrade opportunities were identified.  The field work has required a curtailment of our production which is expected to be completed in August 2011, at which time production is expected to commence.

During the three months ended June 30, 2011, we incurred lease operating expenses of $65,842. Our net average lifting cost for the 2011 period was $1.26 per Mcf. During the three months ended June 30, 2010, we incurred lease operating expenses of $70,278. Our net average lifting cost for the 2010 period was $0.34 per Mcf. The average lifting cost per Mcf in 2011 was higher due to lower production volumes and curtailment of production while most of the lease operating expenses such as salaries, insurance, and ad valorem property taxes were fixed costs.

General and administrative (“G&A”) expenses for the three months ended June 30, 2011 were $523,600 compared to $502,842 for the three months ended June 30, 2010. This represents a $20,758 or 4% increase over the prior period. The higher G&A expense incurred in 2011 was attributable primarily to a one time listing fee for the newly issued common stocks.

Depreciation, depletion and amortization expense (“DD&A”) for the three months ended June 30, 2011 was $93,857 as compared to $187,789 in the corresponding 2010 period. These amounts primarily represent amortization of the oil and gas properties. The 50% decrease was attributable primarily to lower production volumes.

Loss from operations totaled $1,081,490 for the three months ended June 30, 2011 as compared to $996,948 for the three months ended June 30, 2010. The increase in the loss from operations was primarily attributable to lower gas income partially offset by lower operating expenses, and reduced depreciation and depletion expenses recorded in the corresponding prior period.

During the three months ended June 30, 2011 and 2010, we incurred interest expense of $174,833 and $174,889, respectively.

Comparison of Results of Operations for the six months ended June 30, 2011 and 2010

During the six months ended June 30, 2011, we had gross natural gas revenues of $607,939. During this period the sales of gas from our wells amounted to 159,201 Mcf and our average natural gas price realized was $3.82 per Mcf. During the six months ended June 30, 2010 we had gross natural gas revenues of $2,006,369. Our natural gas sales for the six months ended June 30, 2010 were 447,476 Mcf and our average natural gas price realized was $4.48 per Mcf. Revenues decreased during the six months ended June 30, 2011 as compared to the prior year period due to a 64% decrease in production volumes related to normal decline curves as well as treatment plant downtime as described elsewhere herein, and a 15% decrease in natural gas prices.

During the six months ended June 30, 2011, we incurred plant operating expenses of $1,321,837. During the six months ended June 30, 2010, the plant operating expense was $2,186,949.  The decrease in plant operating expense of $865,112 or 40% was primarily attributable to cost cutting measures at our facility and curtailment of production in May 2011.

During the six months ended June 30, 2011, we incurred lease operating expenses of $138,465. Our net average lifting cost for the 2011 period was $0.87 per Mcf. During the six months ended June 30, 2010, we incurred lease operating expenses of $194,583. Our net average lifting cost for the 2010 period was $0.43 per Mcf. The average lifting cost per Mcf in 2011 was higher due to lower production volumes and curtailment of production while most of the lease operating expenses such as salaries, insurance, and ad valorem property taxes were fixed costs.

General and administrative (“G&A”) expenses for the six months ended June 30, 2011 were $1,133,963 compared to $1,237,022 for the six months ended June 30, 2010. This represents a $103,059 or 8% decrease over the prior period. The lower G&A expense incurred in 2011 was attributable primarily to reduced salary expense.

Depreciation, depletion and amortization expense (“DD&A”) for the six months ended June 30, 2011 was $221,800 as compared to $396,482 in the corresponding 2010 period. These amounts primarily represent amortization of the oil and gas properties. The 44% decrease was attributable primarily to lower production volumes.

Loss from operations totaled $2,208,126 for the six months ended June 30, 2011 as compared to $2,008,667 for the six months ended June 30, 2010. The increase in the loss from operations was primarily attributable to lower gas income partially offset by lower operating and administrative expenses, and reduced depreciation and depletion expenses as compared to those recorded in the corresponding prior period.

During the six months ended June 30, 2011 and 2010, we incurred interest expense of $399,411 and $348,908, respectively. The higher interest expense in the 2011 period was due to $60,000 Bank of Oklahoma loan fee recorded in the first quarter of 2011.

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Recent Developments

On January 6, 2011, we entered into a sublease agreement whereby a portion of the Company’s principal executive offices have been leased to a third party. The terms of the sublease agreement include a seventy-five month term cancelable by either party with ninety days written notice after December 31, 2011.  The Company will recoup approximately 50% of the base rental obligation through the sublease agreement.

In February 2011, we extended the maturity on three separate notes totaling $850,000 to December 2012. In connection with the extension, the Company extended the warrants to purchase our common stock associated with these three notes for an additional year.

In February 2011, we extended the maturity of two notes totaling $365,000 through May 2013. In connection with the extension, the Company extended the warrants to purchase our common stock associated with these two notes for an additional year.

In February 2011, we extended the maturity of two notes totaling $300,000 through June 2012.  In connection with the extension, the Company extended the warrants to purchase our common stock associated with these two notes for an additional year.

In February 2011, Stuart J. Doshi, President and CEO, advanced to us a loan in the amount of $125,000. The note accrues interest at 8% annually and is payable on demand.

During February and March 2011, we completed a private placement transaction.  The total placement consisted of 2,050,328 units priced at $0.45 per unit. Each unit consisted of one share of no par value common stock, and a one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $0.75 for a period of three years. The total aggregate purchase price for the units sold was $922,648, and represented the sale of 2,050,328 common shares and 1,025,164 warrants.

On April 1, 2011, we entered into a Purchase and Sale Agreement with Peregrine Midstream Partners LLC whereby we agreed to sell certain idle and non-income producing equipment at the Madisonville Treatment Plant for $8.75 million subject to certain regulatory approvals. On May 31, 2011 the potential sale price was increased to $9.3 million and the closing of the transaction was no longer subject to regulatory approval. Pursuant to the pending transaction we have received deposits totaling $325,000 as of June 30, 2011. The deposits are non-refundable (except for a material breach of the Amended PSA by Madisonville), and they will be credited to the purchase price at the time of closing. Peregrine paid $50,000 on July 28, 2011 and will pay an additional $50,000 on August 30, 2011. We have recorded the amounts received in connection with this pending transaction as non refundable deposits. Under the Amended PSA, in the event that closing would have occurred on or before July 31, 2011, the purchase price would have been reduced from $9,300,000 to $9,100,000.

On May 2, 2011 Linc Energy, the operator of our Alaska leases in the Cook Inlet region reported that drilling and testing on the LEA #1 well located in the Point MacKenzie Block of the Cook Inlet Basin had been completed. Three sandstone targets were tested separately. Despite the fact that gas shows were encountered while drilling, the sandstone targets were too tight to produce commercial quantities of gas. Although the LEA#1 has not proved to be commercial, the operator intends to use information acquired while drilling the well to continue exploration in the Cook Inlet Basin.

In June 2011, we completed a unit sale through a private placement transaction to certain institutional and individual accredited investors. Units were priced at $0.55 per unit, and each unit consisting of one share of no par value common stock, and a one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $1.00 for a period of three years. The total aggregate purchase price for the units sold was $556,560, and represented the sale of 1,011,928 common shares and 505,965 warrants.   We granted “piggyback” registration rights to the investors with respect to the shares of common stock and common stock issuable upon exercise of the warrants which the investors acquired in the transaction.

In June 2011, the Company modified its bank loan with BOK, the Fifth Amendment of the Amended and Restated Term Loan Agreement which: (1) waived the minimum quarterly payment due on June 30, 2011; (2) provides for subsequent minimum quarterly payments of $183,000; (3) provided for additional advances under the term loan of which $600,000 was drawn on June 16, 2011 and $400,000 on July 15, 2011; and (4) provides for the repayment of all outstanding principal and accrued interest under the BOK term loan pursuant to the pending sale of equipment to Peregrine Midstream Partners LLC. The Fifth Amendment did not change the terms of accrued interest, and is payable quarterly in arrears at prime plus 3.25% or Libor plus 4.75% at the option of the Company.  The amendment agreement contains customary affirmative and negative covenants including restrictions on incurring debt in the amount in excess of $375,000.

On August 10, 2011 the PSA with Peregrine was amended for a second time. In connection with this second amendment the closing date for the transaction has been set to occur no later than September 19, 2011.  An additional $1.2 million in non-refundable cash was received by the Company to be applied to the purchase price with the remaining $7.675 million to be paid at the time of closing. Of the $1.2 million received $700,000 was used for the repayment of outstanding principal on our Bank of Oklahoma term loan. At the time of the closing of the transaction the remaining proceeds from this sale will be used for the repayment of the remaining outstanding principal and accrued interest the term loan.

Liquidity and Capital Resources

We had a working capital deficit of $3,919,302 at June 30, 2011 versus $2,990,010 at December 31, 2010. Our working capital deficit increased during six months ended June 30, 2011 due primarily to losses incurred in connection with natural gas operations and the repayments of debt obligations.

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Our cash balance at June 30, 2011 was $733,590 compared to a cash balance of $947,863 at December 31, 2010. The change in our cash balance is summarized as follows:

Net cash used in operating activities of $2,477,064 and $1,474,333 for the six months ended June 30, 2011 and 2010 respectively are attributable to our net income adjusted for non-cash charges as presented in the consolidated statements of cash flows and changes in working capital as discussed above.

We have historically financed our business activities principally through issuances of common shares, preferred shares, promissory notes and common share purchase warrants issued 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 to satisfy working capital requirements and invest in oil and natural gas properties and the gas treatment plant totaling $91,417 and $74,483 for the six months ended June 30, 2011 and 2010, respectively.

Our current cash and cash equivalents and anticipated cash flow from operations may not be sufficient to meet our working capital, and capital expenditure requirements for the foreseeable future.  Additional financing is required to carry out our business plan. We have entered into a Purchase and Sale Agreement with Peregrine Midstream Partners LLC whereby we would sell certain idle and non-income producing equipment at the Madisonville Treatment Plant for $9.3 million. See “Outlook for 2011 and 2012 Capital” for a description of our expected capital expenditures for the year of 2011. 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. We periodically borrow funds through the issuance of short and long term promissory notes to finance our activities.

As of June 30, 2011, we have a working capital deficit of $3,919,302 and for the six months ended June 30, 2011, our cash used in operating activities amounted to $2,477,064.  Further, we estimate our minimum investment needs during the year of 2011 and 2012 to be $3,207,100 related to our natural gas processing plant and our natural gas properties within the Madisonville field and our California properties.  Due to the current natural gas commodity price environment and less volume of gas produced, due to curtailment of production in connection with maintenance, our results of natural gas operations amounted to a loss of $2,566,177 for the six months ended June 30, 2011.  Further, we have maturing debt obligations, 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 2011 and future periods.  Exploratory and developmental drilling is scheduled during 2011 and future periods on our undeveloped properties.   We are attempting to raise additional cash through the sale or farm out of certain of our unproved properties.   We may also 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.

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As discussed in the “Outlook for 2011 and 2012 Capital”, we are forecasting capital expenditures of $3.2 million during the remainder of 2011 and in 2012. We will need to obtain adequate sources of cash to fund these anticipated capital expenditures and to follow through with our plans for continued investments in oil and gas properties. Our success, in part, depends on our ability to generate additional financing and/or farmout certain of our projects.  Additionally, as a result of the current economic downturn, the Company may have difficulty raising sufficient funds to meet our projected funding requirements.

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.

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, 2010.  There were no material changes to our contractual obligations since December 31, 2010 except items 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, 2011, 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.  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, or other gas financial instruments in 2011.

Outlook for 2011 and 2012 Capital

Depending on capital availability, we are forecasting capital spending of up to approximately $3,207,000 during the remainder of fiscal 2011, and in 2012, allocated as follows:

1.               Madisonville Project, Madison County, Texas — Approximately $3,028,000 may be expended in the Madisonville Field area as follows: Capital maintenance, repair of the gas treatment plant, well workovers and land costs.

2.               California — Approximately $179,000 to be utilized for land and permitting 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 expenditures listed above. We may, in our discretion, fund the foregoing planned expenditures from operating cash flows, asset sales, potential debt and equity issuances and/or a combination of all four. The Madisonville Project forecasted capital expenditures will play an important part in the Company achieving its 2011 and 2012 cash flow projections.  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 and economic events around the world, which are difficult to predict, will continue to influence both oil and gas prices. Significant price changes for oil and gas often lead to changes in the levels of drilling activity which in turn lead to changes in costs to explore, develop and acquire oil and gas reserves. Significant change in costs could affect the returns on our capital expenditures.

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.

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 $4.2 million in 2011 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.

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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, 2010 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, 2010 for a description of the principal risks faced by us.

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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.

Interest Rate Risk. Interest rates on future debt offerings could be higher than current levels, causing our financing costs to increase accordingly. We do not currently utilize hedging contracts to protect against interest rate risk.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our President, Chief Executive Officer and Chairman and our interim Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2011.  Based on this evaluation, we have concluded that, as of June 30, 2011, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our President and Chief Executive Officer and interim Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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, 2010, referred to as our 2010 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 2010 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

In February and March 2011, we completed a sale through a private placement transaction to certain institutional and individual accredited investors.  Units were priced at $0.45 per unit and each unit consisted of one share of no par value common stock, and one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $0.75 per share for a period of three years. The total aggregate purchase price was $922,648 and represented the sale of 2,050,328 common shares and 1,025,164 warrants to acquire common shares. In connection with the sale, we granted “piggyback” registration rights to the investors with respect to the shares of common stock and common stock issuable upon exercise of the warrants which the investors acquired. The Company paid no fees or commissions in connection with the sale of the units.

In June 2011, we completed a unit sale through a private placement transaction to certain institutional and individual accredited investors. Units were priced at $0.55 per unit, and each unit consisting of one share of no par value common stock, and a one-half common share purchase warrant. Each one whole warrant entitles the holder to acquire one common share at a price of $1.00 for a period of three years. The total aggregate purchase price for the units sold was $556,560, and represented the sale of 1,011,928 common shares and 505,965 warrants.  We granted “piggyback” registration rights to the investors with respect to the shares of common stock and common stock issuable upon exercise of the warrants which the investors acquired in the transaction. The Company paid no fees or commissions in connection with the sale of the units.

GeoPetro issued the aforementioned common shares and warrants in reliance on the exemption from registration provided for under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), and Rule 506 of Regulation D thereunder. GeoPetro 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 purchasers, including the representations with respect to each purchaser’s status as an accredited investor, as such term is defined in Rule 501(a) of the Securities Act, and each purchaser’s investment intent with respect to the securities purchased.

The sale of the Securities was undertaken without registration under the Securities Act in reliance upon an exemption from the registration requirements of the Securities Act set forth in Sections 4(2) thereunder.  The investors each qualified as an “accredited investor” within the meaning of Rule 501(a) of Regulation D.  In addition, the Securities, which were taken for investment purposes and not for resale, were subject to restrictions on transfer.  We did not engage in any public advertising or general solicitation in connection with this transaction, and we provided the investors with disclosure of all aspects of our business, including providing the investor with our reports filed with the Securities and Exchange Commission and other financial, business and corporate information.  Based on our investigation, we believed that the accredited investors obtained all information regarding the Company that they requested, received answers to all questions posed and otherwise understood the risks of accepting our Securities for investment purposes.

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Use of Proceeds

Proceeds realized will be spent in the following order of priority:

Proceeds from this offering will be used by the Company

(1)                                  Debt Service

(1)                                  General Working Capital

(1)                                  Madisonville Project, Madison County

(1)                                  California Project

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.

Item 3.  Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5.  Other Information.

Not applicable

Item 6.  Exhibits

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EXHIBIT INDEX

(1)          Furnished herewith

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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 15, 2011.

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