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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 March 31, 2010

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 April 30, 2010.

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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

UNAUDITED STATEMENT OF SHAREHOLDERS’ EQUITY

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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, 2009.

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 March 31, 2010, we have a working capital deficit of $1,371,001, and for the three months ended March 31, 2010, our cash used in operating activities amounted to $907,162.  We estimate our minimum investment needs during 2010 amount to $3,528,000 related to our natural gas processing plant and our natural gas properties within the Madisonville field and our California properties.   Our results of natural gas operations amounted to a deficit of $1,011,719 for the three months ended March 31, 2010.  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 2010 and future periods.  Exploratory and developmental drilling is scheduled during 2010 and future periods on our undeveloped properties.  We will 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.  During the three months ended March 31, 2010 we sold our 100% working interest in approximately 123,000 acres onshore in the Cook Inlet region of Alaska (Note 5). 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 January 2010, the Financial Accounting Standards Board issued amendments to Fair Value Measurements and Disclosures under ASC Topic 820. Effective for our 2010 financial statements, this guidance provides for disclosures of significant transfers in and out of Levels 1 and 2. In addition, the guidance clarifies existing disclosure requirements regarding inputs and valuation techniques as well as the appropriate level of disaggregation for fair value measurements and disclosures. Effective for our 2011 financial statements, this guidance provides for disclosures of activity on a gross basis within Level 3 reconciliation.

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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:

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 months ended March 31, 2010 and March 31, 2009 because their effects were antidilutive.

5.     OIL AND GAS PROPERTIES

On February 26, 2010, we sold our 100% working interest in approximately 123,000 acres onshore in the Cook Inlet region of Alaska  (“the Alaskan leases”). The leasehold position consisted of two separate target areas, the Point MacKenzie Prospect and the Trading Bay Prospect, which have been selected for oil and gas exploration. The Point MacKenzie Prospect is located twelve miles northwest of Anchorage. The Trading Bay Prospect is located fifty miles west of Anchorage across the Cook Inlet.

In exchange for our 100% working interest in our Alaskan leases we received the following consideration:

A cash payment of $1.0 million to be held in an escrow account and released to us upon approval of the assignment of the Alaskan leases to the purchaser. This amount has been record as in “other” accounts receivable on our March 31, 2010 unaudited consolidated balance sheet.

A $4.0 million payment from the first 75% of 8/8ths of the proceeds from any oil and gas production from the Alaskan leases.

Subsequent to our receipt of the $4.0 million payment, we will thereafter receive an overriding royalty interest of 10% of 8/8ths in and to the Alaskan leases issued by the State of Alaska and the Alaska Mental Health Trust (which comprise over 99% of the Alaskan leases), and an overriding royalty interest of 7% of 8/8ths in and to the Alaskan leases issued by Cook Inlet Region, Inc., comprised of conventional oil and gas production and coal bed methane production.

The purchaser has agreed to pay all of the costs of maintaining the Alaskan leases at least through the end of the primary terms thereof.

Following the approval of the assignments of the Alaskan leases the purchaser will diligently commence and prosecute the drilling of the Frontier Spirit #1 exploration well to evaluate a conventional oil and gas prospect identified and developed by us.

Amounts  recorded pursuant to this transaction had been previously classified as unevaluated costs on our December 31, 2009 balance sheet.

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6.     DEBT

As of March 31, 2010 and December 31, 2009 debt consisted of the following:

On March 25, 2010 the Bank of Oklahoma, “BOK” waived compliance of a minimum tangible net worth requirement related to our $6,697,847 three year Term Loan Agreement.  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 March 31, 2010, the interest rate was approximately 5.749% (LIBOR + 5.5%). The Term Loan Agreement contains customary affirmative and negative covenants including restrictions on incurring additional debt and minimum tangible net worth requirements.  On March 25, 2010, BOK waived compliance of the minimum tangible net worth covenant and lowered the minimum requirement from $35 million to $18 million.

7.     INCOME TAXES

The effective income tax rates for the three month periods ended March 31, 2010  were negligible,  primarily due to adjustments to the valuation allowance on deferred tax assets.

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, 2009.

9.     COMMON STOCK WARRANTS

There were no material changes to common stock warrants from those disclosed in the audited annual consolidated financial statements for the year ended December 31, 2009.

10.  COMMITMENTS AND CONTINGENCIES

Office Lease - On February 15, 2010, we entered into a new lease for our principal executive office.  The terms of the lease provide for an eighty-four (84) month term. Minimum annual rentals due under this agreement are as follows:

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The lease provides that rent for the first five months of the lease term totaling $59,514 shall be abated provided we are not in default during the term of the lease.

Employment Agreements — On March 31, 2010 Chief Financial Officer, J. Chris Steinhauser with whom we had entered into an employment contract dated April 27, 2009, resigned from his positions as the Chief Financial Officer, Vice President of Finance and Secretary of the Company.

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 April 26, 2010 we extended our Vice President of Exploration, David V. Creel’s employment agreement through December 31, 2010; all other provisions per the terms of the original employment agreement remain unchanged.

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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 254,456 gross (40,540 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 the remainder of 2010. We expect the majority of our capital expenditures for the remainder of 2010 and in 2011 will be for the Madisonville Project and gas processing plant.

Results of Operations

The financial information with respect to the three months ended March 31, 2010 and 2009 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 in 2010

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.

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.

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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 expect to complete installation of the system modifications required in the new plant in 2010.  In the meantime, the existing, in service portion of the plant continues to operate with a design capacity of approximately 18 MMcf/d of inlet gas.

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 2010 as compared to 2009 and prior periods. To accomplish the plant upgrades, we will need to raise capital in 2010. 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 months ended March 31, 2010, 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. Subject to capital availability, we 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. 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 months ended March 31, 2010

Natural gas prices have been very volatile during 2010 and 2009 due to supply concerns earlier in 2009, 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 three months ended March 31, 2010

Our net loss for the three months ended March 31, 2010 was $1,296,168. 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 March 31, 2010 of $39,469,087.  All of our natural gas sales for three months ended March 31, 2010 were derived from our Madisonville Project, from three producing wells, the UMC Ruby Magness #1 well (the “Magness Well”), the Angela Farris Fannin #1 well (the “Fannin Well”), and the Mitchell #1 well (the “Mitchell Well”).

Comparison of Results of Operations for the three months ended March 31, 2010 and 2009

During the three months ended March 31, 2010, we had gross natural gas revenues from the treatment plant of $1,195,573. During this period, our gross production from our wells was 242,348 Mcf and our average natural gas price realized was $4.93 per Mcf. During the three months ended March 31, 2009, we had net oil and natural gas revenues of $876,068. Our gross production for the three months ended March 31, 2009 was 253,590 Mcf and our average natural gas price realized was $3.45 per Mcf. Revenues increased in the three months ended March 31, 2010 as compared to the prior year period due to higher natural gas prices offset by 4% lower production volumes. Natural gas prices were approximately 43% higher for the three months ended March 31, 2010 versus the same period in 2009.

During the three months ended March 31, 2010, we incurred plant operating expenses of $1,140,114. Our average plant operating cost for the 2010 period was $4.70 per Mcf. During the three months ended March 31, 2009, the plant operating expense was $1,044,772. The average plant operating cost for the 2009 period was $4.12 per Mcf.  The higher average plant operating cost per Mcf in 2010 was mainly attributable to higher electricity use at the plant.

During the three months ended March 31, 2010, we incurred lease operating expense of $124,305. Our net average lifting cost for the 2010 period was $0.51 per Mcf. During the three months ended March 31, 2009, we incurred lease operating expense of $300,879. Our net average lifting cost for the 2009 period was $1.19 per Mcf. The average lifting cost per Mcf in 2010 was lower due to cost cutting efforts and a reduction of ad valorem property taxes applicable to the wells.

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General and administrative (“G&A”) expenses for the three months ended March 31, 2010 were $734,180 compared to $848,938 for the three months ended March 31, 2009. This represents a ($114,758) or (14%) decrease over the prior period. The lower G&A expense incurred in 2010 was due primarily to the reduced costs associated with 2009 annual report.

Depreciation, depletion and amortization expense (“DD&A”) for the three months ended March 31, 2010 was $208,693 as compared to $310,086 in the corresponding 2009 period. These amounts primarily represent amortization of the oil and gas properties. The (33%) decrease was attributable primarily to lower depletion expense resulting from the lower value of oil and gas properties and as a result of ceiling test write-offs in the US cost pool recorded  during the fiscal year ended 2009.

Losses from operations totaled $1,011,719 for the three months ended March 31, 2010 as compared to $1,628,607 for the three months ended March 31, 2009. The decrease in the losses from operations was due primarily to higher gas prices and lower operating and administrative expenses.

Other income for the three months ended March 31, 2010 and 2009 consisted of interest income in the amount of $869 and $3,643, respectively. Interest income decreased due primarily to lower average cash and cash equivalent balances during the respective periods.

During the three months ended March 31, 2010 and 2009, we incurred interest expense of $174,019 and $232,439, respectively.  The higher interest expense in the 2009 period was primarily attributable to one-time loan fee payment.

Recent Developments

On February 15, 2010, we entered into a new lease for our principal executive office.  The terms of the lease provide for an eighty-four (84) month term. Minimum annual rentals due under this agreement are as follows:

The lease provides that rent for the first five months of the lease term totaling $59,514 shall be abated provided we are not in default during the term of the lease.

On February 26, 2010, we sold our 100% working interest in approximately 123,000 acres onshore in the Cook Inlet region of Alaska (the “Alaskan leases”). The leasehold position consisted of two separate target areas, the Point MacKenzie Prospect and the Trading Bay Prospect, which have been selected for oil and gas exploration. The Point MacKenzie Prospect is located twelve miles northwest of Anchorage. The Trading Bay Prospect is located fifty miles west of Anchorage across the Cook Inlet.

In exchange for our 100% working interest in our Alaskan leases we received the following consideration:

A cash payment of $1.0 million to be held in an escrow account and released to us upon approval of the assignment of the Alaskan leases to the purchaser. This amount has been record as in “other” accounts  receivable on our March 31, 2010 unaudited consolidated balance sheet.

A $4.0 million payment from the first 75% of 8/8ths of the proceeds from any oil and gas production from the Alaskan leases.

Subsequent to our receipt of the $4.0 million payment, we will thereafter receive an overriding royalty interest of 10% of 8/8ths in and to the Alaskan leases issued by the State of Alaska and the Alaska Mental Health Trust (which comprise over 99% of the Alaskan leases), and an overriding royalty interest of 7% of 8/8ths in and to the Alaskan leases issued by Cook Inlet Region, Inc., comprised of conventional oil and gas production and coal bed methane production.

The purchaser has agreed to pay all of the costs of maintaining the Alaskan leases at least through the end of the primary terms thereof.

Amounts recorded pursuant to this transaction had been previously classified as unevaluated costs on our December 31, 2009 balance sheet.

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On March 31, 2010, J. Chris Steinhauser resigned from his positions as the Chief Financial Officer, Vice President of Finance and Secretary of the Company to pursue other interests, effective as of March 31, 2010. The resignation notification submitted by Mr. Steinhauser did not reference any disagreement with the Company on any matter relating to the Company’s operations, policies and practices. Mr. Steinhauser will continue to serve on the Company’s Board of Directors.

On April 26, 2010 we extended our Vice President of Exploration, David V. Creel’s employment agreement through December 31, 2010, all other provisions per the terms of the original employment agreement remain unchanged.

Liquidity and Capital Resources

We had a working capital deficit of $1,371,001 at March 31, 2010 versus $1,174,225 at December 31, 2009. Our working capital deficit increased during three months ended March 31, 2010 due primarily to the issuance of dividends on our preferred shares, as well as the repayment of debt.

We have historically financed our business activities through March 31, 2010 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 in to satisfy working capital requirement and invested in oil and natural gas properties and the gas treatment plant totaling $55,395 and $515,721 for the three months ended March 31, 2010 and 2009, respectively.

Our cash balance at March 31, 2010 was $1,194,129 compared to a cash balance of $2,429,891 at December 31, 2009. The change in our cash balance is summarized as follows:

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 2010” for a description of our expected capital expenditures for 2010. 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 pursuant to short and long term promissory notes to finance our activities.

As of March 31, 2010, we have a working capital deficit of $1,371,001, and for the three months ended March 31, 2010, our cash used in operating activities amounted to $907,162.  Further, we estimate our minimum investment needs during the remainder of 2010 to be $3,528,000 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, our results of natural gas operations amounted to a loss of $1,011,719 for the three months ended March 31, 2010.  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

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seismic operations for the year of 2010 and future periods.  Exploratory and developmental drilling is scheduled during 2010 and future periods on our undeveloped properties.   We are attempting to raise additional cash through the sale or farmout of certain of our unproved properties.   We 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.

As discussed in the “Outlook for 2010”, we are forecasting capital expenditures of $3.5 million during 2010. We will need to obtain adequate sources of cash to fund our anticipated capital expenditures through the end of 2010 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 2009 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.

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, 2009.  There were no material changes to our contractual obligations since December 31, 2009 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 March 31, 2010, 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, other gas financial instruments  in 2010.

Outlook for 2010 Capital

Depending on capital availability, we are forecasting capital spending of up to approximately $3,528,000 during the year 2010, allocated as follows:

1.               Madisonville Project, Madison County, Texas — Approximately $3,028,000 may be expended in the Madisonville Field area as follows: $1,433,000 million for capital maintenance and repair on new gas treatment plant; $945,000 toward the fracture stimulation and hook up costs of the Wilson Well; and $650,000 for the Mitchell well workover.

2.               California— Approximately $500,000 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 our 2010 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. Higher crude prices could also help keep natural gas prices high by keeping alternative fuels, such as heating oil and residual fuel, expensive.

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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 2010 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.

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, 2009 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, 2009 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.

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 March 31, 2010.  Based on this evaluation, we have concluded that, as of March 31, 2010, 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, on September 11, 2009, our subsidiary, Redwood Energy Production, L.P. filed an Original Petition for Declaratory Judgment against Devon Energy Production Company (“Devon”) regarding certain overriding royalty interests and related revenue amounts claimed by Devon.  The Company previously accrued all amounts owed pursuant to these overriding royalty interests as royalty owners payable.  In the opinion of management based on consultation with legal counsel, these proceedings are not expected to have a material adverse effect on our financial condition 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, 2009, referred to as our 2009 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 2009 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.

None

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

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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 May 13, 2010.

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