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**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

 

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**Form 10-K**

** **

**x**      **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934**

** **

**For the fiscal year ended December 31, 2009**

** **

**OR**

** **

**o****         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

 

**For the transition period from                    to                     **

 

**Commission File Number  001-16749**

 

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**GeoPetroResources Company**

(Exact name of registrant as specified in its charter)

 

| **California**                                            | ** ** | **94-3214487**                       |
|-----------------------------------------------------------|------------|--------------------------------------|
| (State of incorporation)                                  |       | (IRS Employer Identification Number) |
|                                                      |       |                                 |
| **One Maritime Plaza, Suite 700  San Francisco, CA** | ** ** | **94111**                            |
| (Address of principal executive offices)                  |       | (Zip Code)                           |

 

**(415) 398-8186**

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) ofthe Act:

 

| **Title of Each Class** | ** ** | **Name of Each Exchange on Which Registered** |
|----------------------------------------|------------|-----------------------------------------------------------------------------|
| Common Stock, No Par Value             |       | NYSE Amex US                                                                |

 

Securities registered pursuant to Section 12(g) ofthe Act: **None**

 

Indicateby check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act.   Yes o No x

 

Indicateby check mark if the registrant is not required to file reports pursuant to Section 13or Section 15(d) of the Act.   Yes o No x

 

Indicateby check mark whether the registrant (1) has filed all reports required tobe filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject tosuch filing requirements for the past 90 days.   Yes x No o

 

Indicateby check mark whether the registrant has submitted electronically and posted onits corporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 ofthis chapter) during the preceding 12 months (or for such shorter period thatthe registrant was required to submit and post such files).   Yes o No o

 

Indicateby check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein and will not be contained, to the bestof registrant’s knowledge, in definitive proxy or information statementsincorporated by reference in Part III of this Form 10-K or anyamendment to this Form 10-K. o

 

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, or a non-accelerated filer. See definition of “acceleratedfiler and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

| Large accelerated filer o    |   | Accelerated filer o         |
|------------------------------|--------|-----------------------------|
|                         |   |                        |
| Non-accelerated filer  ̈ |   | Smaller Reporting Company x |

 

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

 

Theaggregate market value of the registrant’s common stock held by non-affiliateswas approximately $13,102,558 based on the closing sale price of $0.47 pershare as reported by the American Stock Exchange on June 30, 2009.

 

Thenumber of shares of the registrant’s common stock outstanding on March 30,2010 was 34,284,646.

 

**DOCUMENTS INCORPORATED BY REFERENCE**

 

Portionsof the registrant’s Proxy Statement relating to the 2010 Annual Meeting ofShareholders to be filed on or before April 30, 2010, are incorporated byreference into Part III of this Form 10-K.

 

 

 

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**GEOPETRORESOURCES COMPANY**

 

**TABLE OFCONTENTS**

 
| ** **                                 | ** **                                                                                                              | **Page**   |
|--------------------------------------------|-------------------------------------------------------------------------------------------------------------------------|------------|
| **PART I**                            | ** **                                                                                                              | **2**      |
| ** **                                 | ** **                                                                                                              | ** ** |
| Item 1.                                    | Business                                                                                                                | 2          |
| Item 1A.                                   | Risk Factors                                                                                                            | 8          |
| Item 1B.                                   | Unresolved Staff  Comments                                                                                              | 19         |
| Item 2.                                    | Properties                                                                                                              | 19         |
| Item 3.                                    | Legal Proceedings                                                                                                       | 32         |
| Item 4.                                    | Reserved                                                                                                                | 32         |
|                                       |                                                                                                                    |       |
| **PART II**                           | ** **                                                                                                              | **33**     |
| Item 5.                                    | Market for the  Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases  of Equity Securities | 33         |
| Item 6.                                    | Selected Consolidated  Financial Data                                                                                   | 35         |
| Item 7.                                    | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                             | 36         |
| Item 7A.                                   | Quantitative and  Qualitative Disclosures About Market Risk                                                             | 47         |
| Item 8.                                    | Financial  Statements and Supplementary Data                                                                            | 48         |
| Item 9.                                    | Changes in and  Disagreements With Accountants on Accounting and Financial Disclosure                                   | 48         |
| Item 9A.                                   | Controls and  Procedures                                                                                                | 48         |
| Item 9B.                                   | Other Information                                                                                                       | 48         |
|                                       |                                                                                                                    |       |
| **PART III**                          | ** **                                                                                                              | **49**     |
| Item 10.                                   | Directors,  Executive Officers and Corporate Governance                                                                 | 49         |
| Item 11.                                   | Executive  Compensation                                                                                                 | 49         |
| Item 12.                                   | Security  Ownership of Certain Beneficial Owners and Management and Related Shareholder  Matters                        | 49         |
| Item 13.                                   | Certain  Relationships and Related Transactions and Director Independence                                               | 49         |
| Item 14.                                   | Principal  Accountant Fees and Services                                                                                 | 49         |
|                                       |                                                                                                                    |       |
| **PART IV**                           | ** **                                                                                                              | **50**     |
| Item 15.                                   | Exhibits and  Financial Statement Schedules                                                                             | 50         |
|                                       |                                                                                                                    |       |
| **Signatures**                             | **51**                                                                                                                  |
| ** **                                 | ** **                                                                                                              |
| **Index to Financial  Statements**         | **F-1**                                                                                                                 |
| ** **                                 | ** **                                                                                                              |
| **Glossary of Oil  and Natural Gas Terms** | **52**                                                                                                                  |

 

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**Forward-Looking Statements**

 

*ThisAnnual Report on Form 10-K contains forward-looking statements within themeaning of Section 27A of the Securities Act as of 1933, as amended, and Section 21Eof the Securities Exchange Act of 1934, as amended and we intend that suchforward-looking statements be subject to the safe harbors created thereby.  These statements are related to future eventsor our future financial performance.  Wehave attempted to identify forward-looking statements with terminology,including “anticipate,” “believe,” “can,” “continue,” “could,” “estimate,” “expect,”“intend,” “may,” “plan,” “will,” or similar expressions as they relate to usand our business, industry and markets. All statements other than statements of historical fact are statementsthat could be deemed forward-looking statements, such as those statements thataddress activities, events or developments that we expect, believe oranticipate will or may occur in the future. These statements are based oncertain assumptions and analyses made by us in light of our experience andperception of historical trends, current conditions, expected futuredevelopments and other factors we believe are appropriate in the circumstances.Such forward looking statements are subject to change based on factors beyondour control. Certain factors that may affect our financial condition andresults of operations are discussed in Item 1A “Risk Factors” , Item 7 “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” andItem 7A “Quantitative and Qualitative Disclosures About Market Risk” of thisAnnual Report on Form 10-K, and may be discussed from time to time in ourreports filed with the Securities and Exchange Commission subsequent to thisreport.  We assume no obligation, nor dowe intend to update these forward-looking statements, unless required by law.Unless the context requires otherwise, references in this Annual Report on Form 10-Kto “GeoPetro,” “Company”, “we,” “us” and “our” refer to GeoPetro ResourcesCompany and its consolidated subsidiaries.*

 

**PART I**

 

**Item 1.*Business***

 

We were incorporated inthe State of Wyoming in August 1994 under the name GeoPetro Company as anoil and gas exploration, development drilling and production company. In June 1996,we merged with our wholly-owned subsidiary, GeoPetro Resources SubsidiaryCompany, a California corporation, and the resulting merged company isincorporated in the state of California under the California GeneralCorporation Law under the name GeoPetro Resources Company.

 

Our principal andregistered office is located at One Maritime Plaza, Suite 700, SanFrancisco, California, USA 94111.  Wemaintain a website located at www.geopetro.com.

 

**Intercorporate Relationships**

** **

We hold 100% of theshares of Redwood Energy Company, a Texas corporation, “**Redwood.**” Redwood is the general partner of, and holds a 5% interest in, RedwoodEnergy Production, L.P., “**Redwood LP**”,a Texas limited partnership. We are the sole limited partner of Redwood LPand own the remaining 95% partnership interest in Redwood LP. Redwood alsoholds a 100% interest in Madisonville Midstream LLC, “**MadisonvilleMidstream**”, a Texas  limitedliability company.

 

In addition, we hold a12% interest in Continental-GeoPetro (Bengara II) Ltd., “**C-G Bengara**” which is a British VirginIslands company and a 50% interest in CG Xploration Inc., “**CG Xploration**”, which is a Delawarecorporation.

 

We also hold 100% of theshares of GeoPetro Canada Ltd., “**GeoPetroCanada**”, an Alberta company, 100% of the shares of GeoPetroAlaska LLC “**GeoPetro Alaska**”,an Alaska limited liability company, and 100% of the shares of South TexasGeoPetro, LLC, “**South Texas GeoPetro**”, a Texaslimited liability company.

 

OurCompany also holds 100% of the shares of GeoPetro International Ltd., a BritishVirgin Islands company.

 

**GENERAL DEVELOPMENT OF THE BUSINESS**

** **

Duringthe past three years, we have conducted leasehold acquisition, exploration anddrilling activities on our North American and Indonesian prospects. Theseprojects currently encompass approximately 377,506 gross (163,590net) acres, consisting of mineral leases, production sharing contracts andexploration permits that give us the right to explore for, develop and produceoil and natural gas. Most of these properties are in the exploration, appraisalor development drilling phase and have not begun to produce revenue from thesale of oil and natural gas. Excluding minor interest and dividend income, ouronly cash inflows until 2003 were the recovery of capital invested in projectsthrough sale or other divestiture of interests in oil and gas prospects toindustry partners.

 

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InDecember 2000, we acquired working interests in oil and natural gas leasesin the Madisonville Field in Madison County, Texas, including interests in theRodessa Formation. Also included in the acquisition was the Magness Well, anexisting well that had been drilled, cased and production tested in the RodessaFormation. In October 2001, we re-completed and tested the Magness Wellover a 12-day period. In October 2002, we drilled, completed andsuccessfully tested an injection well to dispose of waste products resultingfrom the treating process for gas produced from the Rodessa Formation. TheMadisonville Field gas treatment plant and associated pipelines, which werebuilt specifically for this project, were placed into service in May 2003,and the Magness Well began production in late May 2003. Since 2003,substantially all of our revenue has been generated from natural gas salesderived from the Madisonville Field, and the Madisonville Project was ourprimary source of revenue in 2009. The first development well in theMadisonville Field, the Fannin Well, was drilled in 2005 and was tested atrates of up to 25.7 MMcf/d. In 2006, we drilled the Wilson and Mitchellwells. Presently, the Fannin, Mitchell and Magness wells are producing whilethe Wilson well is shut-in awaiting a fracture stimulation. We own a 100%working interest in the four wells. Historically, our wells have beenproduction constrained by the gas treatment plant at the Madisonville Field,which had a design treating capacity limit of approximately 18,000 Mcf per day.In 2005, we entered into an agreement with the then plant owner, MadisonvilleGas Processing, LP (“MGP”), an unaffiliated third party, which required, amongother things, that MGP expand the design treating capacity of the plant from18,000 to 68,000 Mcf per day to treat additional volumes from our producingwells. In late 2007, MGP began operations of the additional treatingfacilities and the additional treating capacity at such facilities; however,full operations were never reached due to the presence of diamondoids in thegas stream produced from the Rodessa Formation. On December 31, 2008, GeoPetro acquired the MGP gas treatment plant, as wellas the related gas gathering pipelines and facilities.   This acquisition has allowedthe Company to improve operating efficiencies by consolidating the upstream andmidstream portions of Madisonville project. By owning the midstream portion ofthe Madisonville project, we not only expect better net price realizations andoperational efficiencies (i.e. improved volume realizations), but we also willcontrol the timing and design of the current expansion of the plant facilitiesas well as future expansions, if needed.  See “Properties — Description of the Properties — Texas — TheMadisonville Midstream Gas Treatment Plant and Gathering Facilities.”

 

InFebruary 2010, we sold our entire working interest in our Alaskan CookInlet Project for cash and retained certain royalties.  See “Properties — Description of theProperties — Alaska — Alaskan Cook Inlet Project.”

 

Asof March 31, 2010, we have 34,284,646 shares of common stock and 7,523,000shares of Series B convertible preferred stock outstanding.

 

**GrowthStrategy**

** **

Our growth strategy is tomaximize shareholder value through the exploration and development drilling ofoil and natural gas prospects. To carry out this philosophy we employ thefollowing business strategies:

 

·       identify and pursue potential projectswhich individually have the potential to be “company makers” which we define asprojects which could generate a minimum unrisked net present value of$50 million net to our interest using a 10% discount factor;

 

·  perform geological, engineering andgeophysical evaluations;

 

·  gain control of key acreage;

 

·  generate high quality drillableexploration and development drilling prospects;

 

·       retain a large working interest in thoseprojects which involve low risk appraisal or development drilling, exploitationor appraisal of proved, probable and possible reserves; and

 

·       minimize early investment and explorationrisk in higher risk exploratory prospects through farmouts to other oil andnatural gas companies and maintain meaningful interests with a “carry” throughthe exploration phase.

 

**RisksAssociated With Foreign Operations**

** **

Ourbusiness activities in Indonesia, Canada and the United States are subjectto political and economic risks, including: loss of revenue, property andequipment as a result of unforeseen events like expropriation, nationalization,war, terrorist attacks and insurrection; risks of increases in import, exportand transportation regulations and tariffs, taxes and governmental royalties;renegotiation of contracts with governmental entities; changes in laws andpolicies governing operations of foreign-based companies in Indonesia; exchangecontrols, and numerous other factors. While we expect these risks are greaterin Indonesia, 

 

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especiallypolitical risk, any one or more of such political or economic conditions couldchange in the United States or Canada to our detriment. For a relateddiscussion of the risks attendant with our foreign operations, see “RiskFactors.”

 

**Financial Information AboutGeographic Areas**

 

Please see the notes tothe financial statements for information concerning oil and gas propertieslocated in the United States and foreign countries.

 

**Regulations**

** **

Domestic exploration,production and sale of oil and gas are extensively regulated at both thefederal and state levels. Our business is and will be directly or indirectlyaffected by numerous governmental laws and regulations applicable to the energyindustry, including:

 

·  Federal environmental laws and regulations

 

·  State environmental laws and regulations

 

·  Local environmental laws and regulations

 

·  Federal energy laws and regulations

 

·  Conservation laws and regulations

 

·  Tax and other laws and regulations pertaining to theenergy industry

 

Legislation, rules andregulations affecting the oil and gas industry are under constant review foramendment or expansion, frequently increasing the regulatory burden. Anychanges in the existing legislation, rules or regulations could adverselyaffect our business. The regulatory burdens are often costly to comply with andcarry substantial penalties for failure to comply.

 

Asof December 2009, we have re-completed an existing producing well anddrilled three additional wells and an injection well in the MadisonvilleProject as operator. In addition, we may drill oil, gas and disposal wells inthe future as the operator and will be required to obtain local government andother permits to drill such wells. There can be no assurance that such permitswill be available on a timely basis or at all. Texas and other states havestatutes or regulations pertaining to conservation matters which, among othermatters, regulate the unitization or pooling of gas properties and the spacing,plugging and abandonment of such wells and set limits on the maximum rates ofnatural gas that can be produced from gas wells.

 

Our operations and activities are subject to numerousfederal, state and local environmental laws and regulations. These laws andregulations:

 

·       Require the acquisition of permits

 

·       Restrict the type, quantities andconcentration of various substances that can be discharged into the environment

 

·       Limit or prohibit drilling and otheractivities on wetlands and other designated, protected areas

 

·       Regulate the generation, handling,storage, transportation, disposal and treatment of waste materials

 

·       Impose criminal or civil liabilities forpollution resulting from oil and natural gas operations

 

We expect that with theincrease in our exploratory and development drilling activities, the impact ofenvironmental laws and regulations on our business and operations will alsoincrease. We may be required in the future to make substantial outlays of moneyto comply with environmental laws and regulations. Additional changes inoperating procedures and expenditures to comply with future environmental lawscannot be predicted.

 

Other than our U.S.projects, we do not operate oil and gas properties in which we own an interest.In those instances, we are not in the position to exert direct control overcompliance with most of the rules and regulations discussed above. We aresubstantially dependent on the operators of our non-operated oil and gasproperties to monitor, administer and oversee such compliance. The failure ofthe operator to comply with such rules and regulations could result insubstantial liabilities to us.

 

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Asthe operator of the Madisonville Project, among other various environmentallaws and regulations, we are subject to the U.S. Comprehensive EnvironmentalResponse, Compensation and Liability Act (“**CERCLA**”) andany comparable legislation adopted by Texas which imposes strict, joint andseveral liability on owners and operators of properties and on persons whodispose or arrange for the disposal of “hazardous substances” found on or underthe sites of such properties.

 

UnderCERCLA, one owner, lessee or other party, having responsibility for and aninterest in a site requiring cleanup may, under certain circumstances, berequired to bear a disproportionate share of liability for the cost of suchcleanup if payments cannot be obtained from other responsible parties. TheResource Conservation and Recovery Act (“**RCRA**”) andcomparable rules adopted by Texas and other states regulate thegeneration, management and disposal of hazardous oil and gas waste.

 

TheTexas Railroad Commission has been delegated the responsibility and authorityto regulate and prevent pollution from oil and gas operations, including theprevention of pollution of surface or subsurface water resulting from thedrilling of oil and gas wells and the production of oil and gas. In addition toregulating the generation, management and disposal of hazardous oil and gaswaste, the Texas Railroad Commission has been delegated authority to regulateunderground hydrocarbon storage, saltwater disposal pits and injection wells.

 

The drilling of oil andgas wells in Texas requires operators to obtain drilling permits, file anorganization report and a performance bond or other form of financial security,such as a letter of credit, and obtain a permit to maintain pits to store anddispose of drilling fluids, saltwater and waste as well as other types of pitsfor other purposes. The issuance of such permits is conditioned upon the TexasRailroad Commission’s determination that these pits will not result in waste orpollution of surface or subsurface water.

 

Other states in which wehave an interest in oil and gas properties may impose similar or more stringentregulations than imposed under CERCLA or RCRA.

 

Inre-completing the existing well on the Madisonville Project, we were requiredto drill a well for injection or disposal of produced waste gas from wells.Injection wells are subject to regulation under the Safe Drinking Water Act (“**SDWA**”) and the regulations and procedures which have beenadopted by the Environmental Protection Agency (“**EPA**”)under that Act. Generally, enforcement procedures under the SDWA areadministered by the EPA unless such authority has been delegated by the EPA toa state which has primary enforcement responsibility based on the EPA’sdetermination that the state has adopted drinking water regulations no lessstringent than the national primary drinking water regulations and meetscertain other criteria. Underground injection wells not used for theunderground injection of natural gas for storage are generally unlawful and subjectto penalties under the SWDA unless authorized by:

 

·       permit issued by the EPA or a statehaving primary enforcement responsibility, or

 

·       rule pursuant to an undergroundinjection control program established by a state or the EPA.

 

Tothe extent our pipelines transport natural gas in interstate commerce, therates, terms and conditions of that transportation service are subject toregulation by the Federal Energy Regulatory Commission, or FERC, pursuant to Section 311of the Natural Gas Policy Act of 1978, or NGPA, which regulates, among otherthings, the provision of transportation services by an intrastate natural gaspipeline on behalf of an interstate natural gas pipeline.  Under the Energy Policy Act of 2005, the FERChas authority to impose penalties for violations of the Natural Gas Act, up to$1 million per day for each violation and disgorgement of profits associatedwith any violation.

 

Theregulatory burden on the natural gas and oil industry increases our cost ofdoing business.  Future developments,such as stricter requirements of environmental or health and safety laws andregulations affecting our business or more stringent interpretations of, orenforcement policies with respect to, such laws and regulations, couldadversely affect us. To meet changing permitting and operational standards, wemay be required, over time, to make site or operational modifications at ourfacilities, some of which might be significant and could involve substantialcapital expenditures. There can be no assurance that material costs orliabilities will not arise from these or additional environmental matters thatmay be discovered or otherwise may arise from future requirements of law.   See “Risk Factors — Risks Related to OurBusiness”

 

**ForeignRegulations**

** **

Weown 12% of C-G Bengara which in turn owns an interest in an oil and gas projectlocated in Indonesia. We have farmed out our interest in this project to athird party who is the operator of this project. In exploring for, drilling anddeveloping this property, this operator will be required to comply with theenvironmental, conservation, tax and other laws and regulations 

 

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ofIndonesia. We own non-operated working interests in oil and gas projectslocated in Canada.  In exploring for,drilling and developing these properties, these operators will be required tocomply with the environmental, conservation, tax and other laws and regulationsin Canada.

 

**Technology**

 

Weparticipate in projects utilizing economically feasible exploration technologyin our exploration and development drilling activities to reduce risks, lowercosts, and more efficiently produce oil and gas. We believe that theavailability of cost effective 2-D and 3-D seismic data makes its use inexploration and development drilling activities attractive from a riskmanagement perspective in certain areas.

 

Briefly,through the use of a seismograph, a seismic survey sends pulses of sound fromthe surface down into the earth, and records the echoes reflected back to thesurface. By calculating the speed at which sound travels through the variouslayers of rock, it is possible to estimate the depth to the reflecting surface.It then becomes possible to infer the structure of rock deep below the earth’ssurface. We evaluate substantially all of our exploratory prospects using 2-Dseismic data. In addition, we own a license as to approximately 12 squaremiles of 3-D seismic data covering our leasehold and adjacent lands in theMadisonville Project.

 

Theuse of seismic technology does not entirely remove the risk of exploration anddevelopment drilling of oil and natural gas deposits. It is important toconsider the following:

 

·       we may not recognizesignificant geological features due to errors in interpretation, processinglimitations, the presence of certain geological environments that are out ofour control or other factors;

 

·       seismic generally becomesless reliable with increasing depth of the geological horizon; and

 

·       the use of this technologymay increase our finding cost.

 

**PrincipalProducts**

** **

Ourprincipal products are the production of natural gas from properties in whichwe own an interest. Since our inception, we have realized only limitedproduction of natural gas from the properties in which we own an interest. Wehave working interests in various undeveloped oil and gas properties. See****“Properties”****for a general description of these properties.

 

Duringthe last three fiscal years, 100% of our revenues have been derived from thesale of natural gas. Substantially all of our natural gas sales have beengenerated by three producing wells, the Magness #1, Fannin #1 and Mitchell#1 wells, located in the Madisonville Field in East Texas. Natural gas producedby the wells is delivered to a gathering pipeline and transported to a nearbygas treatment plant where it is treated to remove impurities. On December 31,2008, we purchased this natural gas treatment plant and related gatheringpipeline from Madisonville Gas Processing, LP (“MGP”), an unaffiliated thirdparty.   Prior to the plant beingpurchased, our untreated natural gas was sold at the well head to MGP.  Upon completion of the purchase of the treatmentplant and gathering pipeline facilities, all future natural gas sales willoccur upon delivery to our common carriers.  From the plant, the natural gas is transported approximately nine milesto one of two common carrier pipelines from which point it is delivered to thegreater Dallas, Texas area. The price received for the natural gas is theHouston Ship Channel price index less certain adjustments for the quality ofthe gas delivered and gathering and transportation costs.

 

Forfinancial information regarding our business activities, please see ourFinancial Statements beginning on page F-1 of this annual report.Substantially all of our revenue is produced from natural gas sales in theMadisonville Field located in East Texas.

 

**Reserves**

** **

The volume of productionfrom oil and natural gas properties generally declines as reserves aredepleted, with the rate of decline depending on reservoir characteristics. Ourproved reserves will decline as reserves are produced from our propertiesunless we are able to acquire or develop new reserves.

 

**Acquisitionof Producing Properties**

** **

We may supplement ourexploration efforts with acquisitions of producing oil and gas properties. Wemay seek to acquire producing properties that are underperforming relative totheir potential.

 

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**Patents,Trademarks, Licenses, Franchises and Concessions Held**

** **

Permitsand licenses are important to our operations, since they allow the search forthe extraction of any oil, gas and minerals discovered on the areas covered.See****“Properties” for a generaldescription of the permits and licenses under which we operate. Provided weestablish a commercial discovery thereon, the Bengara PSC in Indonesia grantsus the right to produce oil and gas from the PSC area until 2027.

 

**Seasonalityof Business**

** **

Our business is notseasonal.

 

**WorkingCapital Items**

** **

The majority of ourcurrent assets are in the form of cash received from the sale of natural gasfrom our Madisonville Project in Texas, amounts received from issuance oflong-term notes, bridge loans, and from the sale of common and preferred stockin private placements. We use this cash to pay for the cost of our operations,service of debt facilities, and other administrative activities. For furtherinformation see, “Management’s Discussion and Analysis of Financial Conditionand Results of Operations.”

 

**Customers**

** **

Substantially all of ourrevenues to date have been derived from sales to two customers, Luminant EnergyCompany, and ETC Katy Pipeline, Ltd., of natural gas produced from ourMadisonville Project in Texas. We have not committed any forward sales of ournatural gas. We contract to sell the gas with spot-market based contracts thatvary with market forces. No other customer accounts for in excess of 10% of ourrevenues.  The loss of either of thesecustomers could result in the loss of our revenues, which would have a materialadverse effect on our results of operations. See “Risk Factors”.

 

**Competition**

** **

Thenatural gas and oil industry is intensely competitive and speculative in all ofits phases. We encounter competition from other natural gas and oil companiesin all areas of our operations. In seeking suitable natural gas and oilproperties for acquisition, we compete with other companies operating in ourareas of interest, including large natural gas and oil companies and otherindependent operators, which have greater financial resources and in manyinstances, have been engaged in the exploration and production business for amuch longer time than we have. Many of our competitors also have substantiallylarger operating staffs than we do. Many of these competitors not only explorefor and produce natural gas and oil but also market natural gas and oil andother products on a regional, national or worldwide basis. These competitorsmay be able to pay more for productive natural gas and oil properties andexploratory prospects and define, evaluate, bid for and purchase a greaternumber of properties and prospects than us. In addition, these competitors mayhave a greater ability to continue exploration activities during periods of lowmarket prices. Our ability to acquire additional properties and to discoverreserves in the future will depend on our ability to evaluate and selectsuitable properties and to consummate transactions in a highly competitiveenvironment.

 

Theprices of our natural gas production are controlled by market forces. However,competition in the natural gas and oil exploration industry also exists in theform of competition to acquire leases and obtain favorable transportationprices. Our Company is relatively small and may have difficulty acquiringadditional acreage and/or projects and may have difficulty arranging for thetransportation of our production. We also face competition in obtaining naturalgas and oil drilling rigs and in sourcing the manpower to run them and providerelated services.

 

**Employees**

** **

Currently,we have 20 employees, all of whom are full time. We use the services ofindependent consultants and contractors to perform various professionalservices, including geologic, geophysical, petroleum, reservoir &drilling engineering, land, legal, environmental and tax services. On thoseproperties where we are not the operator, we rely on outside operators todrill, produce and market our natural gas and oil.

 

**AvailableInformation**

** **

***We maintain a website located at http://www.geopetro.com andelectronic copies of our annual, quarterly and current reports, and anyamendments to those reports, as well as our code of ethics, are available freeof charge under the Investor***

 

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*** ***

***Relations link onour website.  This information isavailable on our website, as soon as practicable after such material is filedwith, or furnished to, the Securities and Exchange Commission.***

*** ***

**Item 1A.*Risk Factors***

 

In addition torisks and uncertainties in the ordinary course of business that are common toall businesses, important factors that are specific to our industry and ourcompany could materially impact our future performance and results of operations.We have provided below a list of these risk factors that should be reviewedwhen considering our securities. These are not all the risks we face and otherfactors currently considered immaterial or unknown to us may impact our futureoperations.

 

**Risks Related toOur Business**

** **

***As of December 31,2009, we have gross capitalized costs totaling $70 million as proved andunproved oil and gas properties and gas processing plant whereas we havegenerated revenues of only $40 million since January 1, 2003 and revenuesof only $4.1 million during the fiscal year ended December 31, 2009.***

** **

Since inception, our activities have been primarilyrelated to acquiring and exploring leasehold interests in oil and natural gasproperties in Texas, California, Alaska, Canada, Indonesia and Australia. Weincur substantial acquisition and exploration costs and overhead expenses inour operations, and until 2003, excluding minor interest and dividend income,our only significant cash inflows were the recovery of capital invested inprojects through sale or other divestitures of interests in oil and gasprospects to industry partners. As a result, we have sustained an accumulateddeficit through December 31, 2009 of $38.2 million. Our productionactivities were commenced in May 2003. Since May 2003, over 98% ofour revenue has been generated from natural gas sales derived from wells in theMadisonville Field in Texas. It is possible that in the future we will beunable to continue to generate revenues from our sales of natural gas from ourMadisonville Field wells because our proved reserves decline as reserves areproduced from the wells. The drilling of exploratory oil and natural gas wellsis highly speculative and often unproductive. Our participation in futuredrilling activities to explore, develop and exploit the properties in which wehave an interest, or in which we may acquire interests, may be unsuccessful,may fail to generate positive cash flow, and may not enable us to maintainprofitability in the future.

 

***Wemay be unable to integrate successfully the operations of the Madisonville GasTreatment Plant with our operations and we may not realize all the anticipatedbenefits of the Madisonville Gas Treatment Plant.***

 

We formerly contractedwith Madisonville Gas Processing, LP, (“MGP”) which owned and operatedgathering pipelines and a dedicated natural gas treatment plant (which we referto as the Madisonville Gas Treatment Plant), to treat impurities in the naturalgas generated by our Madisonville Project. Effective December 31, 2008, we acquired the Madisonville GasTreatment Plant from MGP through our indirect wholly-owned subsidiary,Madisonville Midstream LLC.  We plan tocomplete the expansion of the Madisonville Gas Treatment Plant’s treatmentcapacity from 18 MMcf/d to 68 MMcf/d. Operations in the additional facilities were suspended by MGP in December 2007in order to deal with the presence of diamondoids in the gas stream producedfrom the Rodessa Formation.  During March 2009,  the Fannin, Magness and Mitchell wells areproducing at a combined restricted rate of approximately 6.5 MMcf/d while theWilson  well is shut-in.    There can be no assurance that we will beable to accomplish the expansion and achieve a full treatment capacity of 68MMcf/d.

 

***Even if we are able to successfully complete the expansion of theMadisonville Gas Treatment Plant from 18 MMcf/d to 68 MMcf/d, third parties mayseek access to the plant through regulatory proceedings, which could limit ouruse of the Plant and disrupt our production operations.***

 

Third parties have, andmay in the future, seek access to the Madisonville Gas Treatment Plant throughregulatory proceedings, which could restrict our access to the Plant, disruptour production operations and negatively impact our revenues.  An example of such a proceeding is thecomplaint filed by Crimson Exploration Inc. (“Crimson”) with the Texas RailroadCommission described under “Properties — Description of the Properties — Texas— The Madisonville Gas Treatment Plant and Gathering Facilities.”  On August 9, 2006, the Texas RailroadCommission issued an order requiring MGP to ratably process, take, transport orpurchase natural gas produced by Crimson into the Madisonville Gas TreatmentPlant.  Since Crimson now has the rightto have its natural gas treated at the Plant, our ability to treat our ownnatural gas will be reduced to the extent of Crimson’s usage.  Crimson is not currently utilizing any of thePlant’s capacity.  Crimson’s usage couldincrease in the future.

 

Substantiallyall of our revenues have been generated from natural gas sales derived fromwells in the Madisonville Field, and 100% of our natural gas generated from theMadisonville Field wells is treated at the Madisonville Midstream Gas TreatmentPlant, which is 100% indirectly owned by the Company.  If our ability to treat natural gas at theMadisonville Midstream Gas Treatment Plant is limited for any reason, includingbut not limited to increased demands by third parties, our revenues may beadversely affected.

 

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***Substantiallyall  of our current revenues aregenerated by our interest in the Madisonville Project. Delays or interruptionsof the Madisonville Project natural gas drilling and production operationsincluding, but not limited to, events beyond our control or the failure ofthird parties on which we rely to provide key services, could negatively impactour revenues.***

** **

Substantially all of our oil and natural gasrevenues for the years ended December 31, 2009 and 2008 were derived fromthe Madisonville Project. In connection with that project, we have contractedwith Gateway Processing Company, (“Gateway”) which operates a sales pipelinefor natural gas.

 

The failure of Gateway to perform its contractualobligations to us could impose delays or interruptions in our productionoperations and prevent us from generating revenues. In addition, events whichare beyond our control, or that of Gateway, could affect our productionoperations. Such events include, but are not limited to:

 

·       events referredto as force majeure, such as an act of God, act of a public enemy, war,blockade, public riot, lightning, fire, storm, flood, explosion and any othercauses whether of the kind enumerated or otherwise not reasonably within thecontrol of Gateway.

 

·       the inabilityto secure raw materials or equipment,

 

·       transportationaccidents, and

 

·       labor disputesand equipment failures.

 

***We donot own all of the land on which our pipelines and facilities are located, andwe are therefore subject to the possibility of not being able to retainnecessary land use and associated increased costs.***

 

Wehave the right to operate our pipelines on land owned by third parties forspecified periods of time.   Our loss ofthese rights, through our inability to renew rights-of-way contracts, leases orotherwise, could result in the suspension of our operations, or increased costsrelated to continuing operations elsewhere, which would have a material adverseeffect on our business, results of operations and financial condition.

 

***Ifthird-party pipelines and other facilities interconnected to our natural gaspipelines and processing facilities become partially or fully unavailable totransport natural gas, our revenues could be adversely affected.***

 

Wedepend upon third party pipelines and other facilities to provide deliveryoptions from the Madisonville Midstream Gas Treatment Plant to ourcustomers.  If any of these third partypipelines become unavailable to transport the natural gas produced at theMadisonville Gas Treatment Plant, or if the gas quality specifications forthese pipelines or facilities change, we would be required to find alternatemeans to transport our natural gas out of the Madisonville Gas Treatment Plant,which could increase our costs, reduce the revenues we might obtain from thesale of our natural gas or reduce our ability to process natural gas at thePlant.

 

***In excess of 90% of our revenuesto date have been derived from sales by MGP to two customers. The loss of oneor both these customers could have a material adverse impact on our oil and gasrevenues.***

 

100%of our natural gas sales and revenues for the years ended December 31,2009 and 2008 were derived from the Madisonville Project. During 2009 and 2008,100% of our revenues have been derived from sales by MGP to two customers,Luminant Energy Company, LLC, and ETC Katy Pipeline, Ltd. The loss of, ormaterial nonpayment by one of these customers could impact the price we receivefor our gas sold due to lessened competition. The loss of, or materialnonpayment by, both customers could result in a loss of our revenue.  Ourcustomers may be subject to their own operating risks which could increase therisk that they could default on their obligation to us.

 

***Unless we replace our oiland natural gas reserves, our reserves and production will decline.***

*** ***

The volume of production from oil and natural gasproperties generally declines as reserves are depleted, with the rate ofdecline depending on reservoir characteristics. Our proved reserves will declineas reserves are produced from our properties unless we are able to acquire ordevelop new reserves. The business of exploring for, developing or acquiringreserves is capital intensive. For example, as of December 31, 2009 wehave capitalized costs totaling $70 million as proved and unproved oil and gasproperties and gas processing plant. To the extent cash flow from operations isreduced and external sources of capital

 

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becomelimited or unavailable, our ability to make the necessary capital investment tomaintain or expand our asset base of oil and natural gas reserves will be impaired.Even if we are able to raise capital to develop or acquire additionalproperties, no assurance can be given that our future exploitation anddevelopment drilling activities will result in the discovery of any reserves.

 

***Our exploration and developmentdrilling activities may not be commercially successful. The drilling ofexploratory oil and natural gas wells is expensive, highly speculative andoften unproductive.***

 

Exploration for oil and natural gas on unprovenprospects is expensive, highly speculative and involves a high degree of risk,including the risk that no commercially productive oil or natural gasreservoirs will be encountered. Reserves are dependent on our ability tosuccessfully complete drilling activity on proven prospects.

 

The cost of drilling, completing and operating wellsis often uncertain, and drilling operations may be curtailed, delayed orcancelled as a result of a variety of factors, including:

 

·  unexpecteddrilling conditions, pressure or irregularities in formations;

 

·  subsurfaceconditions or formations encountered during the drilling of wells, whethernatural or mechanical, including but not limited to blowout, igneous rock,salt, saltwater flow, loss of circulation, loss of hole, abnormal pressures, orany other impenetrable substance or adverse condition, which renders furtherdrilling of a well impossible or impractical.

 

·  equipmentfailures or accidents, adverse weather conditions;

 

·  compliance withgovernmental requirements; and

 

·  shortages ordelays in the availability of drilling rigs, the delivery of equipment, andavailability of qualified manpower.

 

***Our evaluations of the oil and gas prospects of ourproperties may be wrong.***

** **

With the exception of the Madisonville Project, theproperties in which we have an interest are prospects in which the presence ofoil and natural gas reserves in commercial quantities has not been established.Any decision to engage in exploratory drilling or other activities on any ofthese properties will be dependent in part on the evaluation of data compiledby petroleum engineers and geologists and obtained through geophysical testingand geological analysis.

 

Reservoir engineering, geophysics and geology arenot exact sciences and the results of studies and tests used to make suchevaluations are sometimes inconclusive or subject to varying interpretations.As such, there is no certain way to know in advance whether any of ourprospects will yield oil and natural gas in commercial quantities. Further, itis possible that we will participate in the drilling of more dry holes thanproductive wells or that all or substantially all of the wells drilled will bedry holes. The drilling of dry holes on prospects in which we have an interestcould adversely affect their values and our decision to undertake furtherexploration and development drilling of such prospects. It is not certain orpredictable whether, and no assurance can be made that, the wells drilled onthe properties in which we have an interest will be productive or, if productive,that we will recover all or any part of our investment in the properties. Insum, our participation in future drilling activities may not be successful and,if unsuccessful, such failure will negatively impact our revenues and have amaterial adverse effect on our results of operations and financial condition.Our natural gas sales and revenues were $4,077,355 and $6,152,542 for the yearsended December 31, 2009 and 2008, respectively. Future revenues coulddecline from those levels if our future drilling efforts are not successful.Furthermore, as of December 31, 2009 we have net capitalized coststotaling $31 million as proved and unproved oil and gas properties and gasprocessing plant. Should our future drilling activities be unsuccessful, we maythen be required to record an impairment charge equal to a portion of, or all,of the capitalized costs resulting in an immediate adverse impact on ourresults of operations and financial position.

 

***Our business may beharmed by failures of third party operators on which we rely.***

*** ***

Our ability to manage and mitigate the various risksassociated with certain of our exploration and operations in Alberta, Canada,and Indonesia is limited since we rely on third parties to operate ourprojects. We are a non-operating interest owner in our Canadian and Indonesianproperties. With respect to our interests in Canada and Indonesia, we haveentered into agreements with third party operators for the conduct andsupervision of drilling, completion and production operations. In the eventthat commercial quantities of oil and natural gas are discovered on one of ourproperties, the success of the oil and natural gas 

 

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operationson that property depends in large measure on whether the operator of theproperty properly performs its obligations. The failure of such operators andtheir contractors to perform their services in a proper manner could result inmaterially adverse consequences to the owners of interests in that particularproperty, including us.

 

***Our percentage share of oil and gasrevenues from our Indonesian property is diminished by the terms of ourproduction sharing contract in the Bengara Block.***

 

C-G Bengara owns 100% of the underlying rights toexplore for and produce oil and natural gas within the Bengara Block.  We have a 12% interest in C-G Bengara. C-GBengara is subject to a production sharing contract, which means generally thatC-G Bengara is entitled to receive, from production proceeds, 100% ofexpenditures in the block as “cost recovery.” Once these costs are recovered,C-G Bengara’s production share will be reduced to approximately 26.7% of oilproduced and 62.5% of all natural gas produced. We are entitled to 12% of C-GBengara’s reduced share of any such production. See the discussion under “Properties-Indonesia — Terms of Participation in the Bengara Block” for more informationconcerning the production sharing contract.

 

***Drilling and completionequipment, services, supplies and personnel are scarce and may not be availablewhen needed, which could significantly disrupt or delay our operations.***

*** ***

From time to time,there has been a general shortage of drilling rigs, equipment, supplies andoilfield services in North America and Indonesia.  In addition, the costs and delivery times ofrigs, equipment and supplies have risen when short supply of equipment existedin the past. There can be no assurance that sufficient drilling and completionequipment, services and supplies will be available when needed. Shortages coulddelay our proposed exploration, development drilling, and sales activities,which could have a material adverse effect on our results of operations. Ournatural gas sales were $4.08 million for the year ended December 31, 2009.Future revenues could decline from those levels if we experience delays in ourproposed exploration, development drilling, and sales activities. The demandfor, and wage rates of, qualified rig crews have risen in the drilling industrydue to the increasing number of active rigs in service. If the demand forqualified rig crews continues to rise in the drilling industry, then the oiland gas industry may experience shortages of qualified personnel to operatedrilling rigs. This could delay our drilling operations and adversely affectour financial condition and results of operations.

 

***Our working interest in properties,and our ability to realize any profits from such properties, will be diminishedto the extent that we enter into farmout arrangements with unaffiliated thirdparties.***

 

We have previously entered into, and may in thefuture enter into, farmout arrangements with third parties willing to drillnatural gas and oil wells on leaseholds in which we originally acquired workinginterests, in exchange for our assignment of part or all of our leaseholdinterests. As a consequence of these arrangements, our retained interests inproperties which are subject to farmout arrangements have been or may bediminished. Our opportunity to realize revenues and profits fromproperties which are successfully developed under farmout arrangements will bediminished to the extent of our reduced interests.

 

***Competition with otheroil and natural gas exploration and development drilling companies for viableoil and natural gas properties may limit our success.***

*** ***

It is likely that in seeking future propertyacquisitions, we will compete with companies which have substantially greaterfinancial and management resources. Our competition comes primarily from threesources:

 

(a)                                  those competitors that are seeking oiland gas fields for expansion, further drilling, or increased production throughimproved engineering techniques;

 

(b)                                 income-seeking entities purchasing apredictable stream of earnings based upon historic production from fields beingacquired; and

 

(c)                                  junior companies seeking explorationopportunities in unknown, unproven territories.

 

Our competitors may be able to pay more forproductive oil and natural gas properties and may be able to define, evaluate,bid for and purchase a greater number of properties and prospects than we can.Our ability to acquire additional properties in the future will depend upon ourability to conduct efficient operations, evaluate and select suitableproperties, implement advanced technologies and consummate transactions in ahighly competitive environment.

 

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***Estimates of oil and natural gasreserves are inherently imprecise. Any material inaccuracies in these reserveestimates or underlying assumptions will affect materially the quantities andpresent value of our reserves.***

 

Estimates of proved oil and natural gas reserves andthe future net cash flows attributable to those reserves are prepared byindependent petroleum engineers and geologists. There are numerousuncertainties inherent in estimating quantities of proved oil and natural gasreserves and cash flows attributable to such reserves, including factors beyondour control and that of our engineers. Reserve engineering is a subjectiveprocess of estimating underground accumulations of oil and natural gas thatcannot be measured in an exact manner. Different reserve engineers may makedifferent estimates of reserves and cash flows based on the same availabledata. The accuracy of an estimate of quantities of reserves, or of cash flowsattributable to such reserves, is a function of the available data, assumptionsregarding future oil and natural gas prices and expenditures for futuredevelopment drilling and exploration activities, and of engineering andgeological interpretation and judgment. Additionally, reserves and future cashflows may be subject to material downward or upward revisions, based uponproduction history, development drilling and exploration activities and pricesof oil and natural gas. Actual future production, revenue, taxes, developmentdrilling expenditures, operating expenses, underlying information, quantitiesof recoverable reserves and the value of cash flows from such reserves may varysignificantly from the assumptions and underlying information set forth herein.

 

***Competitive pressures may force usto implement new technologies at substantial cost and our limited financialresources may limit our ability to implement such technologies at the same rateas our competitors.***

 

The oil and gas industry is characterized by rapidand significant technological advancements and introductions of new productsand services utilizing new technologies. Other oil and gas companies may havegreater financial, technical and personnel resources that allow them to enjoytechnological advantages and may in the future allow them to implement newtechnologies before we do. There can be no assurance that we will be able torespond to such competitive pressures and implement such technologies on atimely basis or at all. One or more of the technologies currently utilized byus or implemented in the future may become obsolete.

 

***We will require additional capitalto fund our future activities. Our ability to pursue our business plan may berestricted by our access to additional financing.***

 

Until such time as the properties in which we owninterests are generating sufficient cash flow to fund planned capitalexpenditures, we will be required to raise additional capital through theissuance of additional securities or otherwise sell or farmout interests in ouroil and natural gas properties to third parties. If and when the properties inwhich we own interests become productive and have adequate reserves, we mayborrow funds to finance our future oil and natural gas operations andexploratory and development drilling activities. We may not be able to raiseadditional funds in the future from any source or, if such additional funds aremade available to us, we may not be able to obtain such additional financing onterms acceptable to us. To the extent such funds are not available from any ofthose sources, our operations and activities will be limited to thoseoperations and activities we can afford with the funds then available to us.Our larger competitors, by reason of their size and relative financialstrength, may be more easily able to access capital markets than us.

 

***The volatility in crude oil andnatural gas prices could adversely affect our financial results and ability toraise additional capital.***

 

Our revenues, cash flows and profitability aresubstantially dependent on prevailing prices for both oil and natural gas.Decreases in natural gas prices will decrease revenues and cash flows from theMadisonville Project and our other producing properties, if any, and decreasesin oil and natural gas prices could deter potential investors from investing inour company and generally impede our ability to raise additional financing tofund our exploration and development drilling activities. Historically, oil andnatural gas prices and markets have been volatile, and they are likely tocontinue to be volatile in the future. Prices for oil and natural gas aresubject to wide fluctuations in response to relatively minor changes in thesupply of, and demand for, oil and natural gas, market uncertainty and avariety of additional factors that are beyond our control. These factorsinclude, but are not limited to, political conditions in the Middle East andother regions, internal and political decisions of OPEC and other oil andnatural gas producing nations to decrease or increase production of crude oil,domestic and foreign supplies of oil and natural gas, consumer demand, weatherconditions, domestic and foreign government regulations and taxation,transportation costs, the price and availability of alternative fuels, theimpact of energy conservation efforts and overall economic conditions.

 

***Risksassociated with recent economic trends have adversely affected, and couldfurther adversely affect our financial performance.***

 

As widelyreported, the global financial markets have been experiencing extremedisruption in the past year, including severely diminished liquidity and creditavailability. Concurrently, we have experienced a global recession. We believethese conditions have adversely impacted our financial position as of December 31,2009 and our liquidity for the twelve months ended December 31, 2009.  Our financial condition and performance couldbe further negatively impacted if either of these conditions continues to existfor a sustained period of time, or if there is further deterioration infinancial markets and major 

 

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economies. We are unableto predict the likely duration and severity of the current disruption infinancial markets and adverse economic conditions in the U.S. and abroad.

 

***We are subject to a number ofoperational risks beyond our control against which we may not have, or be ableto obtain insurance.***

 

Our operations are subject to the many risks andhazards incident to exploring and drilling for, and producing and transporting,oil and natural gas, including among other risks:

 

·       blowouts,fires, craterings, pollution and equipment failures that may result in damageto or destruction of wells, pipelines, producing formations, productionfacilities and equipment;

 

·       damage to pipelines, facilities and propertiescaused by hurricanes, tornados, floods and other natural disasters

 

·       personalinjuries or death due to accidents, human error or acts of God;

 

·       unavailabilityof materials and equipment to drill and complete or re-complete wells;unfavorable weather conditions; engineering and construction delays;

 

·       fluctuations inproduct markets and prices; proximity and capacity of pipeline, and trucking ortermination facilities to our oil and natural gas reserves; hazards resultingfrom unusual or unexpected geological or environmental conditions;environmental regulations and requirements;

 

·       accidentalleakage of toxic or hazardous materials, such as petroleum liquids or drillingfluids into the environment, remediation and clean-up costs; and

 

·       politicalinstability and civil unrest, insurrections or disruptions in foreign countriesin which some of our interests are located.

 

If one or more of these events occurs, we couldincur substantial liabilities to third parties or governmental entities, thepayment of which could have a material adverse effect on our financialcondition and results of operations, or we could lose properties in which wehave invested significant sums (totaling $70 million) which are capitalized asproved and unproved oil and gas properties and gas processing plant as of December 31,2009.

 

***A loss not covered by insurance could result in substantial expenses tous.***

 

We do not insure fully against all business riskseither because such insurance is not available or because premium costs areprohibitive.  We are not insured againstall environmental accidents that might occur which may include toxic tortclaims. If a significant accident or event occurs that is not fully insured, ifwe fail to recover all anticipated insurance proceeds for significant accidentsor events for which we are insured, or if we fail to rebuild facilities damagedby such accidents or events, our operations and financial condition could beadversely affected. In addition, we may not be able to maintain or obtaininsurance of the type and amount we desire at reasonable rates. As a result ofmarket conditions, premiums and deductibles for certain of our insurancepolicies have increased substantially, and could escalate further. For example,following Hurricanes Katrina and Rita, insurance premiums, deductibles andco-insurance requirements increased substantially, and terms generally are lessfavorable than terms that could be obtained prior to such hurricanes.  In some instances, certain insurance couldbecome unavailable or available only for reduced amounts of coverage.  A loss not fully covered by insurance could resultin expenses to us and could have a material adverse effect on our financialposition and results of operations. Uninsured losses in excess of $1.0 millionwould be materially adverse to our financial position and results ofoperations.

 

***We are subject to extensive government regulations that can change fromtime to time, compliance with which are costly and could negatively impact ourproduction, operations and financial results.***

 

The oil and gas industry is subject to extensivegovernment regulations in the countries in which we operate. Matters subject toregulation include discharge permits for drilling operations, drilling bonds,reports concerning operations, unitization and pooling of properties andtaxation. Historically, our costs of complying with these regulations have notexceeded $100,000 per year. From time to time, regulatory agencies have imposedprice controls and limitations on production by restricting the rate of flow ofoil and natural gas wells below actual production capacity in order to conservesupplies of oil and natural gas. We are also subject to changing and extensivetax laws, the effects of which cannot be predicted. Legal requirements arefrequently changed and subject to interpretation, and we are unable to predictthe ultimate cost of compliance with these requirements or 

 

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theireffects on our operations. Future laws, or existing laws or regulations, ascurrently interpreted or reinterpreted or changed in the future, could resultin increased operating costs, fines and liabilities, in amounts which areunknown at this time, any of which could materially adversely affect our resultsof operations and financial condition.

 

***Our industry is subject to extensiveenvironmental regulation that may limit our operations and negatively impactour production.***

 

Extensive national, state, provincial and local environmental laws andregulations in the United States and foreign jurisdictions affect nearlyall of our operations.  Environmentallaws to which we are subject in the U.S. include, but are not limited to, (1) theClean Air Act and comparable state laws that impose obligations related to airemissions, (2) the Resource Conservation and Recovery Act of 1976 (RCRA),and comparable state laws that impose requirements for the handling, storage,treatment or disposal of solid and hazardous waste from our facilities, (3) theComprehensive Environmental Response, Compensation and Liability Act (CERCLA)and comparable state laws that regulate the cleanup of hazardous substancesthat may have been released at properties currently or previously owned oroperated by us or at locations to which our hazardous substances have beentransported for disposal, and (4) the Clean Water Act, and comparablestate laws that regulate discharges of wastewater from our facilities to stateand federal waters. Failure to comply with these laws and regulations or newlyadopted laws or regulations may trigger a variety of administrative, civil andcriminal enforcement measures, including the assessment of monetary penalties,the imposition of remedial requirements, and the issuance of orders enjoiningfuture operations or imposing additional compliance requirements on suchoperations. Certain environmental laws, including CERCLA and analogous statelaws, impose strict, joint and several liability for costs required to clean upand restore sites where hazardous substances or hydrocarbons have been disposedor otherwise released.  Moreover, it isnot uncommon for neighboring landowners and other third parties to file claimsfor personal injury and property damage allegedly caused by the release ofhazardous substances, hydrocarbons or other waste products into theenvironment.

 

Environmental legislation may require that we:

 

·       acquire permitsbefore commencing drilling;

 

·       restrictspills, releases or emissions of various substances produced in associationwith our operations;

 

·       limit orprohibit drilling activities on protected areas such as wetlands or wildernessareas;

 

·       takereclamation measures to prevent pollution from former operations;

 

·       take remedialmeasures to mitigate pollution from former operations, such as pluggingabandoned wells and remedying contaminated soil and groundwater;

 

·       take remedialmeasures with respect to property designated as a contaminated site.

 

There is inherent risk of incurring environmentalcosts and liabilities in connection with our operations due to our handling ofnatural gas and other petroleum products, air emissions and water dischargesrelated to our operations, and historical industry operations and wastedisposal practices.  The costs of any ofthese liabilities are presently unknown but could be significant.  We may not be able to recover all or any ofthese costs from insurance.

 

We are not presently aware of any environmentalliabilities or able to predict the ultimate cost of liabilities not yetrecognized.  We have not established aseparate reserve fund for the purpose of funding any possible futureenvironmental liability.  As a result, wemay not be able to satisfy these obligations, if they occur.  Any such costs incurred will be funded out ofour cash flow from operations.  If we areunable to fully fund the cost of remedying an environmental obligation, wemight be required to suspend operations or enter into interim compliancemeasures pending satisfaction of the liability, which could have an adverseaffect on our financial condition and results of operations.  We have recorded an asset requirementobligation in connection with the estimated future costs to plug certain wellsat our Madisonville Project in Texas upon abandonment totaling approximately$65,000 as of December 31, 2009. See “Business — Regulation.”

 

***The effects of future environmentallegislation on our business is unknown but could be substantial.***

 

Environmental legislation is evolving in a mannerexpected to result in stricter standards and enforcement, larger fines andliability and potentially increased capital expenditures and operating costs.Changes in, or enforcement of, environmental laws may result in a curtailmentof our production activities, or a material increase in the costs ofproduction, development drilling or exploration, any of which could have amaterial adverse effect on our financial condition and results of operations orprospects. In addition, many countries, as well as several states in the UnitedStates have agreed to regulate emissions of “greenhouse 

 

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gases.”  Methane, a primary component of natural gas,and carbon dioxide, a byproduct of burning natural gas, are greenhousegases.  Regulation of greenhouse gasescould adversely impact some of our operations and demand for products in thefuture.  See “Business — Regulations.”

 

***Potentialregulations regarding climate change could alter the way we conduct ourbusiness.***

 

Governments around theworld are beginning to address climate change matters. This may result in newenvironmental regulations that may unfavorably impact us, our suppliers and ourcustomers. The cost of meeting these requirements may have an adverse impact onour financial condition, results of operations and cash flows.

 

***Should we fail to comply with allapplicable FERC administered statutes, rules, regulations and orders, we couldbe subject to substantial penalties and fines.***

 

Under the Energy Policy Act of 2005, the FederalEnergy Regulatory Commission, or FERC, has authority to impose penalties forviolations of the Natural Gas Act, up to $1 million per day for each violationand disgorgement of profits associated with any violation.  FERC has recently proposed and adoptedregulations that may subject our facilities to reporting and postingrequirements.  Additional rules andlegislation pertaining to these and other matters may be considered or adoptedby FERC from time to time.  Failure tocomply with FERC regulations could subject us to civil penalties.

 

***We may incur significant costs andliabilities as a result of pipeline integrity management program testing andany related pipeline repair or preventative or remedial measures.***

 

The United States Department of Transportation, orDOT, has adopted regulations requiring pipeline operators to develop integritymanagement programs for transportation pipelines located where a leak orrupture could do the most harm in “high consequence areas.”  The regulations require operators to:

 

·                  Perform ongoing assessments of pipeline integrity;

 

·                  Indentify and characterize applicable threats to pipeline segments thatcould impact a high consequence area;

 

·                  Improve data collection, integration and analysis;

 

·                  Repair and remediate the pipeline as necessary; and

 

·                  Implement preventive and mitigating actions.

 

***Political and/or economic conditionsin Indonesia, Canada or the United States could change in manners thatnegatively affect our operations and prospects in those countries.***

 

Our business activities in Indonesia, Canada and theUnited States are subject to political and economic risks, including: lossof revenue, property and equipment as a result of unforeseen events likeexpropriation, nationalization, war, terrorist attacks and insurrection;increases in import, export and transportation regulations and tariffs, taxesand governmental royalties; renegotiation of contracts with governmentalentities; changes in laws and policies governing operations of foreign-basedcompanies; exchange controls, currency fluctuations and other uncertaintiesarising out of foreign government sovereignty over international operations;laws and policies affecting foreign trade, taxation and investment; and thepossibility of being subject to the exclusive jurisdiction of foreign courts inconnection with legal disputes and the possible inability to subject foreignpersons to the jurisdiction of courts in the United States.

 

***Terrorist attacks could have an adverse effect on our oil and naturalgas operations, especially overseas.***

 

To date, our operations have not been disrupted byterrorist activity. It is uncertain how terrorist activity will affect us inthe future, or what steps, if any, the Indonesian, Canadian or Americangovernment may take in response to terrorist activities. The attack on theNew York World Trade Center in 2001 and the subsequent wars in Afghanistanand Iraq have increased the likelihood that U.S. citizens and U.S. ownedinterests may be targeted by terrorist groups operating both in theUnited States and in foreign countries, especially in Indonesia.

 

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***We could lose our entire Production Sharing Contract (“PSC”), if BPMigas ascertains we have not discovered commercially producible hydrocarbons.***

 

It is possible that BP Migas could terminate ourentire Production Sharing Contract (“PSC”) if it is determined that thehydrocarbons we have discovered are not in commercially produciblequantities.  Our Indonesian PSC requiresus and our partners to submit to and receive approval from BP Migas for a “Planof Development”  by specified dates inorder to maintain our oil and natural gas rights. See “Properties—Descriptionof the Properties—Indonesia.” If we do not establish commerciality and receivean approved Plan of Development for the PSC, or successfully renegotiate theterms, all or part of our contract may be terminated. If this contract isterminated, we would also lose all of our investment in that overseas prospect.If we forfeit our interest in the contract area, it will be necessary to recordan impairment write-down equal to the net capitalized costs recorded for thearea forfeited. This could have a material adverse impact on our financialcondition and results of future operations in future periods. If approval of aPlan of Development is not obtained and if further deferrals of such obligationsare not secured, we will need to record an impairment charge equal to theamount of costs capitalized which were approximately $584,000  as of December 31, 2009, and we may loseall of our rights in the Bengara Block.

 

***We may not be able to sell our naturalgas production in Indonesia, limiting our ability to obtain a return on ourinvestment there.***

 

Our Indonesian operations lack a local market fornatural gas, and if we produce natural gas in Indonesia, it will most likelyhave to be transported to an area where there is a demand. If no market fornatural gas develops locally, we may incur costs for transportation. If we arenot able to sell our natural gas production at a commercially acceptable priceor at all, we may not be able to obtain a return on our investment in ourIndonesian property.

 

***We could lose our ownership interests in our properties due to a titledefect of which we are not presently aware.***

 

As is customary in the oil and gas industry, only aperfunctory title examination, if any, is conducted at the time propertiesbelieved to be suitable for drilling operations are first acquired. Beforestarting drilling operations, a more thorough title examination is usuallyconducted and curative work is performed on known significant title defects. Wetypically depend upon title opinions prepared at the request of the operator ofthe property to be drilled. The existence of a title defect on one or more ofthe properties in which we have an interest could render it worthless and couldresult in a large expense to our business. Industry standard forms of operatingagreements usually provide that the operator of an oil and natural gas propertyis not to be monetarily liable for loss or impairment of title. The operatingagreements to which we are a party provide that, in the event of a monetaryloss arising from title failure, the loss shall be borne by all parties inproportion to their interest owned.

 

***Our acquisition activities aresubject to uncertainties and may not be successful nor  provide a return to us on our investments.***

 

We have grown primarily through acquisitions andintend to continue acquiring undeveloped oil and gas properties. Although weperform a review of the properties proposed to be acquired, such reviews aresubject to uncertainties. It generally is not feasible to review in detailevery individual property involved in an acquisition. Ordinarily, managementreview efforts are focused on the higher-valued properties; however, even adetailed review of all properties and records may not reveal existing orpotential problems; nor will it permit us to become sufficiently familiar withthe properties to assess fully their deficiencies and capabilities. Inspectionsare not always performed on every well, and potential problems, such asmechanical integrity of equipment and environmental conditions that may requiresignificant remedial expenditures, are not necessarily observable even when aninspection is undertaken.

 

***We are dependent upon our key officers and employees and our inabilityto retain and attract key personnel could significantly hinder our growthstrategy and cause our business to fail.***

 

Whileno assurances can be given that our current management resources will enable usto succeed as planned, a loss of one or more of our current directors, officersor key employees could severely and negatively impact our operations and delayor preclude us from achieving our business objectives. Stuart Doshi and DavidCreel, two members of our senior management team, have a combined experience ofapproximately 80 years in the oil and gas industry.  We could suffer the loss of key individualsfor one reason or another at any time in the future. There is no guarantee thatwe could attract or locate other individuals with similar skills or experienceto carry out our business objectives. We maintain “key man” insurance withrespect to our Chief Executive Officer, Stuart Doshi.

 

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***Some of our directors may become subject toconflicts of interest which could impair their abilities to act in our bestinterest.***

 

Nick DeMare,one of our directors, is a director, officer and/or significant shareholder ofother natural resource companies and David Anderson, another one of ourdirectors, is a director and officer of Dundee Securities Corporation, aninvestment banking firm that was the lead underwriter of our public offering ofcommon stock in Canada and concurrent previous private placement of commonshares with qualified institutional buyers in the U.S. Their association withthese other companies in the oil and gas business may give rise to conflicts ofinterest from time to time. For example, they could be presented with businessopportunities in their capacities as our directors, which they could, in turn,offer to the other companies for whom they also serve as directors, rather thanto us, whose interests might be competitive with ours. Our directors are requiredby law to act honestly and in good faith with a view to our best interests andto disclose any interest which they may have in any project or opportunity tous; however, their interests in the other companies may affect their judgmentand cause such directors to act in a manner that is not necessarily in our bestinterests.

 

***Our directors and officers hold significantpositions in our shares and their interests may not always be aligned withthose of our other shareholders.***

 

Asof December 31, 2009 our directors and officers beneficially ownapproximately 18.7% of our outstanding common stock. This shareholding levelwill allow the directors, officers and certain beneficial owners to have asignificant degree of influence on matters that are required to be approved byshareholders, including the election of directors and the approval ofsignificant transactions. The short-term interests of our directors, officersand certain beneficial owners may not always be aligned with the long-terminterests of our public shareholders, and vice versa. Because our directors,officers and certain beneficial owners have a significant degree of influenceon matters that are required to be approved by our shareholders, they couldinfluence the approval of transactions.

 

***Our failure to manage internal oracquisition-based growth may cause operational difficulties and negativelyaffect our financial performance.***

 

Weexpect to experience internal and/or acquisition-based growth, which may bringmany challenges. Growth in the number of employees, sales and operations willplace additional pressure on already limited resources and infrastructure. Noassurances can be given that we will be able to effectively manage this orfuture growth. Our growth may place a significant strain on our managerial,operational, financial and other resources. Our success will depend upon ourability to manage our growth effectively which will require that we continue toimplement and improve our operational, administrative and financial and accountingsystems and controls and continue to expand, train and manage our employeebase. Our systems, procedures and controls may not be adequate to support ouroperations and our management may not be able to achieve the rapid executionnecessary to exploit the market for our business model. If we are unable tomanage internal and/or acquisition-based growth effectively, our business,results of operations and financial condition will be materially adverselyaffected.

 

***Risks associated with recent economic trendscould adversely affect our financial performance.***

 

In2010 we will need to raise capital.  Dueto the tight credit markets and prolonged downturn in the stock market, fundsmay not be available, or may be available only on unfavorable terms. Due to thedecrease in our stock price, we may need to sell more shares to raise the sameamount of money than we would have in the past, resulting in greater dilutionto existing shareholders than would be the case if our stock price was higherand this trend could continue.  We have scheduled exploratory anddevelopment well drilling and workover activity during 2010 and future periodson our proved and unproved properties. It is anticipated that these activitiestogether with others that we may undertake will impose financial requirementswhich will exceed our existing working capital. We may raise additional equityand/or debt capital, and we may farmout certain of our projects to finance ourcontinued participation in planned activities; however, if additional financingis not available, we may be compelled to reduce the scope of our businessactivities. If we are unable to fund planned expenditures, it may be necessaryto:

 

·                                          farm-out our interest in proposed wells;

 

·                                          sell a portion of our interest in prospectsand use the sale proceeds to fund our participation for a lesser interest;

 

·                                          forfeit our interest in wells that wepropose to drill; and

 

·                                          reduce general and administrativeexpenses.

 

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**Risks Related to Our Common Stock**

 

***The shareholding position of holders of ourcommon stock could be diluted by future issuances and conversions of othersecurities.***

 

Ifour options and warrants are exercised for common shares, holders of our commonstock will experience immediate and, depending on the magnitude of theexercises, substantial dilution. As of March 31, 2010, 34,284,646 sharesof our common stock are outstanding, 7,523,000 shares of our Series BPreferred stock are outstanding, 1,561,547 shares of our common stock are issuable upon exercise of warrants and2,004,000  shares of our common stock areissuable upon exercise of options and 7,523,000 shares of our common stock areissuable upon conversion of the series B Preferred Stock.

 

Investorsmay be subject to further dilution if we sell additional common shares or issueadditional common shares in connection with future financings. If a significantnumber of our common shares are sold in the public market, the market price ofour common shares could be depressed. This could hamper our ability to raisecapital by issuing additional equity securities.

 

***Our results maybe affected by fluctuations in currency exchange rates.***

 

Ourfinancial statements are reported in U.S. dollars and all of our revenue,and most of our operating costs, are currently denominated inU.S. dollars; however, we have operations outside the United Statesand we plan to expend money in Indonesia and Canada, where our operating costswill be denominated in local currencies. Fluctuations in exchange rates mayincrease our relative cost of operating in these countries, and may thereforehave a negative effect on our financial results.

 

***Non- U.S. holders of our common shares maybe subject to U.S. federal income tax on the sale of our common shares andpurchasers may have IRS withholding requirements***

 

Sincewe believe that we are a United States real property holding corporation, gainrecognized by a non-U.S. holder on the sale of our common shares will besubject to U.S. federal income tax at normal graduated rates, and a purchaserwill be required to withhold for the benefit of the IRS 10% of the purchaseprice, unless certain trading requirements are met. There is an exemption fromU.S. federal income tax for non-U.S. holders of 5% or less of our common shares(and therefore no tax withholding requirements) if our common shares are “regularlytraded on an established securities market.”  In the event that 100 orfewer persons own 50% or more of our common shares (which had been, may now beand may continue to be, the case), temporary Treasury Regulations provide thatour common shares will be “regularly traded on an established securities market”for a calendar quarter if the established securities market is located in theUnited States and our common shares are regularly quoted by more than onebroker or dealer making a market in our common shares; our common shares arecurrently listed on the NYSE Amex (which constitutes an established UnitedStates securities market for this purpose) and are being regularly quoted.There can be no assurance, however, that our common shares will continue to beregularly traded on an established securities market for this purpose in anyparticular calendar quarter so as to avoid U.S. federal income tax on the saleof our common shares by non-U.S. holders of 5% or less of our common shares andthe withholding requirement on the purchaser.

 

Atsuch time that it is no longer the case that 100 or fewer persons own 50% ormore of our common shares, under temporary Treasury Regulations, our commonshares would also be “regularly traded” on an established securities market fora calendar quarter if:  (a) our common shares trade, other than in deminimis quantities, on at least 15 days during the calendar quarter; (b) theaggregate number of our common shares traded during the calendar quarter is atleast 7.5% of the average number of our common shares outstanding during suchcalendar quarter (reduced to 2.5% if there are 2,500 or more recordshareholders); and (c) in the event that our common shares are traded onan established securities market located outside the United States, the commonshares are registered under Sec. 12 of the Securities Exchange Act of 1934. See“Material Income Tax Consequences — Dispositions of Common Shares” for a moredetailed discussion.

 

***There is a limited public market for ourcommon shares, and the ability of our shareholders to dispose of their commonshares may be limited.***

 

Ourcommon shares have been trading on the NYSE Amex (formerly the American StockExchange) since February 15, 2007. We cannot foresee the degree ofliquidity that will be associated with our common shares. A holder of ourcommon shares may not be able to liquidate his, her or its investment in ashort time period or at the market prices that currently exist at the time theholder decides to sell. The purchase and sale of relatively small common sharepositions may result in disproportionately large increases or decreases in theprice of our common shares. A trade involving a large number of common sharescould have an exaggerated effect on the reported market price of our commonshares.

 

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***Our stock price may fluctuatesignificantly.***

 

Thestock market in general and the market for natural gas and oil explorationcompanies have experienced price and volume fluctuations that are oftenunrelated or disproportionate to the operating results or asset values ofcompanies. These broad market and industry factors may seriously impact themarket price and trading volume of our common shares regardless of our actualoperating performance. The market price of our common stock could alsofluctuate significantly as a result of:

 

·       actual oranticipated quarterly variations in our operating results and our reserveestimates;

 

·       changes inexpectations as to our future financial performance or changes in financialestimates, if any, of public market analysts;

 

·       announcementsrelating to our business or the business of our competitors;

 

·       conditionsgenerally affecting the oil and natural gas industry, including changes in oiland natural gas prices;

 

·       speculation inthe press or investment community;

 

·       general marketand economic conditions;

 

·       the success ofour operating strategy; and

 

·       the operatingand stock price performance of other comparable companies.

 

***The sale of large numbers of our commonstock may depress the market price of our common stock.***

 

Thesale of a substantial number of shares of our common stock in the publicmarket, or the perception that substantial sales may occur, could cause themarket price of our common stock to decrease. Substantially all of the sharesof our common stock are freely transferable or will be transferable incompliance with restrictions under the Securities Act of 1933, as amended.  In 2010, we will need to raise additionalworking capital and investors may be subject to further dilution if we selladditional common shares or issue additional common shares in connection withfuture financings. If a significant number of our common shares are sold in thepublic market, the market price of our common shares could be depressed. Thiscould hamper our ability to raise capital by issuing additional equitysecurities.

 

***We will continue to incur significantexpenses as a result of being a public company, which may negatively impact ourfinancial performance.***

 

Wehave incurred and will continue to incur significant legal, accounting,insurance and other expenses as a result of being a public company. TheSarbanes-Oxley Act of 2002, as well as related rules implemented by theSecurities and Exchange Commission, or SEC, and the NYSE Amex, have requiredchanges in corporate governance practices of public companies. Compliance withthese laws, rules and regulations has increased our expenses, includingour legal and accounting costs, and made some activities more time-consumingand costly. As a result, it may be more difficult for us to attract and retainqualified persons to serve on our board of directors or as officers.Furthermore, any additional increases in legal, accounting, insurance andcertain other expenses that we may experience in the future could negativelyimpact our financial performance and have a material adverse effect on ourresults of operations and financial condition***.***

 

**Item 1B.*Unresolved Staff Comments***

 

None.

 

**Item 2.*Properties***

 

Our principal executiveoffice consists of 2,956 square feet and is located at One Maritime Plaza, Suite 700,San Francisco, CA 94111 until April 30, 2010.  The new principal executive office contains4,201 square feet and is located at 150 California Street, Suite 600, SanFrancisco, CA 94111 effective May 1, 2010 thru April 30, 2017.

 

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**Descriptionof the Properties**

 

Our current oil andnatural gas exploration, appraisal and development drilling activities arefocused in four distinct project areas as follows:

 

·       **United States—Texas**(East Texas and onshore South Texas regions),**Alaska** (onshore Cook Inlet area) and **California** (onshore San Joaquin basin);

 

·       **Canada—Alberta** (central Alberta basin);

 

·       **Indonesia**—onshore and offshore East KalimantanProvince; and

 

·       **Australia**—onshorein two permit areas located in the South Perth basin.

 

We do not fully insureagainst all business risks either because such insurance is not available orbecause premium costs are prohibitive. This is a common practice in the oil andgas industry. We believe our property is adequately insured in view of thenature of our operations and industry practices in this regard.

 

***Texas***

*** ***

*MadisonvilleProject, Madison County, East Texas*

* *

We own and operate theinterest in the Madisonville Project in Madison County, Texas. We own workinginterests in approximately 4,557 gross and net acres of leases in the RodessaFormation interval, as well as approximately 4,447 gross and net acres ofleases as to depths below the Rodessa Formation interval. We also own a licenseas to 12.5 square miles of 3-D seismic data over theMadisonville Field.

 

The Madisonville Field,located approximately 100 miles north of Houston, has produced oil and naturalgas from four different horizons above the Rodessa Formation for over50 years. The field was discovered in 1945 with the Boring No. 1well, which was drilled to the Rodessa Formation. The well blew out at anuncontrolled rate for three days during a test; however, due to hydrogensulphide, carbon dioxide and nitrogen in the Rodessa Formation natural gas, thegas reserves were never developed. Over 125 wells were drilled in theMadisonville Field to shallower intervals above the Rodessa Formation. In 1994,nearly 50 years after the initial discovery, United Meridian Corporation (“**UMC**”) drilled the Magness Well as the firstfollow-up well into the Rodessa Formation to the Boring No. 1 well. TheMagness Well had 139 feet of net pay but the natural gas was found tocontain 28% impurities.

 

UMC previously productiontested the Magness Well in 1994 through perforations in the lower most ten feetof the indicated Rodessa Formation pay interval. The well tested at a rate of12 MMcf/d from this limited interval on a 22/64ths inch choke withflowing wellhead pressures increasing from 3,915 to 3,919 pounds per squareinch. In 2001, we re-entered and recompleted the Magness Well. A total of139 feet of interval has been perforated in the Rodessa Formation atapproximately 12,000 feet of depth for this well. The well was productiontested over a 12-day period in 2001 on various choke sizes with flowing ratesranging up to approximately 20.8 MMcf/d. We own a 100% working interest(75.1333% net revenue interest) in the Magness Well located in the surroundingproduction unit consisting of 684 gross and 629 net acres. The Magness Wellcommenced production in May of 2003.

 

The first development well,the Fannin Well, was drilled and completed in 2004. We own a 100% workinginterest (69.9162% net revenue interest) in the Fannin Well located in thesurrounding production unit consisting of 704 gross and net acres. A total of146 feet of indicated pay was perforated in the well and a flow test ofthe well was completed in December 2004 from the Rodessa Formation atrates of up to 25.7 MMcf/d. We commenced production from the Fannin Wellin early 2006.

 

The Madisonville Field isa geologic feature encompassing approximately 5,800 acres at the Rodessalimestone at about 11,800 feet of depth. A 3-D seismic program shot inearly 1998 confirmed the size of the structure and slightly increased its sizeover earlier interpretations.

 

Our working interestcovers the Rodessa Formation at approximately 12,000 feet of depth. TheRodessa reserves are being developed through the recompletion of the MagnessWell and the drilling of additional proved undeveloped locations. Productionbegan in May 2003 and stabilized at a rate of 18 MMcf/d of raw gasfrom the Magness Well. In 2006, we drilled the Wilson and Mitchell wells. Weown a 100% working interest (70% net revenue interest) in the Wilson andMitchell wells.  The Magness, Fannin andMitchell wells are currently producing at a combined restricted rateof approximately 6.5 MMcf/d while the Wilson well is shut-in. Current netsales production is approximately 3.0 MMcf/d. In addition, we own aworking interest in certain leases and farmout rights which cover depths belowthe Rodessa Formation.

 

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The hydrogen sulphide,carbon dioxide and nitrogen combined comprise about 28% of the gas content. Theuntreated natural gas is delivered to the Madisonville Midstream Gas TreatmentPlant where all the natural gas impurities are removed before delivery to thesales pipeline. As a result of the costs to treat the natural gas, we receive anet price that is substantially lower than we would otherwise receive if the gasdid not contain the 28% of impurities. In addition, the high concentrations ofhydrogen sulphide and carbon dioxide result in higher capital and operatingcosts for our wells. For example, the hydrogen sulphide and carbon dioxide arecorrosive to the wellbores. This means we have to utilize higher gradespecification well tubing and casing which is more expensive than what we wouldutilize absent the impurities. In addition, we continuously treat the wellboreswith chemicals designed to inhibit the corrosive effects of the impurities. Wealso maintain field personnel at or near the wellsites who monitor the wells ona twenty four hour basis and equip the wellsites with extensive safetyequipment systems due to the toxic properties of the hydrogen sulphide andcarbon dioxide. These factors and others result in higher capital and operatingcosts for our wells in the Madisonville Project.

 

*The Madisonville Midstream Gas Treatment Plant and Gathering Facilities*

* *

In order to produce theproved gas reserves from the Rodessa Formation, we developed an onsite plan totreat and remove impurities from the Madisonville Project natural gas in orderto meet pipeline-quality specifications. On June 15, 2001, we, through oursubsidiary Redwood LP, entered into an agreement, which agreement wassubsequently amended and restated, together with certain related agreements(collectively, the “**Hanover Agreement**”),with Hanover Compression Limited Partnership pursuant to which Hanovercommitted to fund, construct and operate a dedicated natural gas treatmentplant to process our Rodessa Formation natural gas.  The Hanover Agreement also provided for theinstallation by Gateway of field gathering pipelines and an approximatelynine-mile sales pipeline with an estimated capacity of approximately70 MMcf/d to transport the Madisonville Field natural gas to a majorpipeline.  By April of 2003, theconstruction and installation of Hanover’s natural gas treatment plant andGateway’s associated pipeline and gathering facilities were completed. Gasproduction from the Magness Well commenced in May 2003. We received thefirst revenues from the sale of natural gas from the Madisonville Project in July 2003.

 

On July 25, 2005,MGP purchased the natural gas treatment plant from Hanover and purchased thegathering pipelines upstream of the gas treatment plant from Gateway.Concurrent with MGP’s purchase of the gas treatment plant and gatheringpipelines, we, through our subsidiary Redwood LP, Gateway and MGP terminatedthe Hanover Agreement and entered into a new agreement, (the “**MGP Agreement**”), to treat and transport ourgas production from the Madisonville Project. As a result of the MGP Agreement,MGP committed to install and make operational additional treating facilitiescapable of treating 50 MMcf/d, which combined with the capacity of thecurrent in-service treating facilities would represent a total treatingcapacity of 68 MMcf/d for the Madisonville treatment plant. The MGPAgreement provided that the newly installed gas treatment facilities would beelectrically driven. Currently, the existing in-service treatment plantutilizes some of the natural gas produced and delivered from our well(s). Theconversion to electricity on the expanded portion of the treatment plant isexpected to reduce shrinkage of our natural gas that occurs in the treatingprocess.

 

Originally,the MGP Agreement required MGP to complete the additional treating facilitiesby March 1, 2006.  However, due toevents of force majeure, construction of the additional treating facilities wasdelayed.  In early November 2007,MGP began testing the additional treatment facilities by accepting 20 MMcf/d atthe inlet.   Subsequently in December 2007, MGP suspended the operations of theadditional treatment facilities inorder to make modifications to more effectively deal with the presence ofdiamondoids in the gas stream produced from the Rodessa Formation. A diamondoidis a rare, naturally occurring compound that can segregate out of the gasstream upon a decrease in temperature and pressure and as such, could causeoperational problems for the nitrogen rejection portion of theadditional treating facilities.  MGP obtained a detailed laboratorycomposition analysis of the diamondoids which indicated that removal ofthe diamondoids will require flowing the natural gas stream through a dieselcontactor after the gas stream has had the hydrogen sulfide and carbon dioxideremoved.  MGP also conducted a field pilot test whichsuccessfully confirmed the laboratory results.  Through this contactor process, the dieselwill absorb the diamondoids from the gas stream prior to entry into thenitrogen removal tower.

 

During2008, MGP analyzed various options forremoving the diamondoids;  however, they didnot complete the necessary plantsystem modifications.  On December 31, 2008, wepurchased the gas treatment plant and related gathering pipelines from MGP inexchange for the assumption of secured bank debt, payment of certainoutstanding payables of MGP and shares of GeoPetro’s common stock.  The secured bank debt we incurred as part of the Plantacquisition totaled $6.7 million and is in the form of a 3 year loan with thelender, Bank of Oklahoma, National Association (“BOK”).  The loan agreement provides for minimumquarterly principal payments of $150,000 and supplemental principal amountspayable upon GeoPetro achieving certain cash flow thresholds.  The Company has pledged its Madisonvillenatural gas reserves as well as the Plant assets as collateral for theloan.  There is a loan fee of $60,000payable annually for any yearly period during which any principal remains 

 

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outstanding under theloan.  There is no prepaymentpenalty.  GeoPetro and its wholly ownedsubsidiary Redwood Energy Production, LP (“Redwood”) are guarantors of theloan.

 

Theeffective date of the acquisition was December 31, 2008 and the currentowner of the Plant is GeoPetro’s wholly-owned, indirect subsidiary,Madisonville Midstream LLC (“MM”).  We expect to complete installation of thesystem modifications required in the new plant in 2010.  In the meantime, the existing, in serviceportion of the plant continues to operate with a capacity of approximately 18million cubic feet per day of inlet gas.

 

Ournatural gas deliveries to our gas treatment plant may be affected by thirdparty demands for access to the plant. On August 9, 2006, the TexasRailroad Commission issued an order requiring the Plant to ratably process,take, transport or purchase natural gas produced by Crimson into theMadisonville gas treatment plant. There is no guarantee that we will be able tomaintain full access to treatment capacity of up to 68 MMcf/d at theMadisonville Plant at all times because, for example, Crimson now has the rightto have its natural gas treated at the plant, which may reduce the plant’sability to treat all of our natural gas, unless the plant’s capacity is furtherexpanded.

 

Todate, Crimson has drilled and completed two wells to a depth of approximately12,635 feet. Crimson has also drilled an injection well for disposal of wasteproducts resulting from the treatment of their natural gas.  Crimson has not delivered any natural gas tothe treatment plant since August 2009.

 

*OtherInterests in the Madisonville Project*

 

Ourworking interest in the Madisonville Project is subject to a net profitsinterest in favor of the third party that sold us our working interests in theMadisonville Project. The net profits interest is 12.5% (proportionatelyreduced to our interest) of the net operating profits until payout is achieved.After payout, the net profits interest increases to 30% (proportionatelyreduced to our interest). “Payout”, for purposes of the net profits interest,is defined and achieved at such time as we have recouped from net operatingcash flows our total net investment in the Madisonville Project plus a 33% cashon cash return.

 

***Alaska***

 

*TheCook Inlet Alaska Project*

 

Over the past five years,we acquired a 100% working interest in approximately 123,000 acres onshore inthe Cook Inlet region of Alaska (the “Alaskan Leases”). The leasehold positionconsists of two separate target areas, the Point MacKenzie Prospect and theTrading Bay Prospect, which have been selected for oil and gas exploration. ThePoint MacKenzie Prospect is located twelve miles northwest of Anchorage. TheTrading Bay Prospect is located fifty miles west of Anchorage across the CookInlet. GeoPetro believes that the acreage may contain significant accumulationsof conventional oil and gas and coal bed methane.

 

On February 26,2010, we sold our entire working interest in the Alaskan Leases to Linc Energy(Alaska) Inc. (“Linc”).  Linc is awholly-owned subsidiary of Linc Energy Ltd., an Australian-based companypublicly traded on the Australian Stock Exchange.

 

Linc will acquire all ofthe Alaskan Leases for the following consideration:

 

a.               A cash payment of $1.0 million will be deposited byLinc in an escrow account, to be released to us upon approval of theassignments of the Alaskan Leases to Linc.

 

b.              In addition, we will receive a $4.0 million paymentfrom the first 75% of 8/8ths of the proceeds from any oil and gas productionfrom the Alaskan Leases.

 

c.               After we have received the $4.0 million paymentspecified in paragraph (b) above, we will thereafter receive an overridingroyalty interest of 10% of 8/8ths in and to the Alaskan Leases issued by theState of Alaska and the Alaska Mental Health Trust (which comprise over 99% ofthe Alaskan Leases), and an overriding royalty interest of 7% of 8/8ths in andto the Alaskan Leases issued by Cook Inlet Region, Inc. on conventionaloil and gas production and coal bed methane production.

 

d.              Linc has agreed to pay all of the costs of maintainingthe Alaskan Leases at least through the end of the primary terms thereof.

 

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e.               Following the lessors’ approval of the assignments ofthe Alaskan Leases into Linc, Linc will diligently commence and prosecute thedrilling of the Frontier Spirit #1 exploration well to evaluate a conventionaloil and gas prospect identified and developed by us.

 

The initial reservetarget in the Cook Inlet Project was identified by us after we reprocessedcertain 2-D seismic data acquired from AMOCO on the Point MacKenzie Block. Theprospect is estimated to cover approximately eighteen sections (11,500 acres)under structural closure, and will target conventional gas reserves in theMiddle and Lower Tyonek Formations reaching to a depth of approximately 8,000feet.  We have constructed a drill padand access road at the Frontier Spirit #1 location which will be located lessthan two miles from the Enstar 20” natural gas pipeline. The Frontier Spirit #1well is expected to be drilled by Linc in 2010.

 

Preliminary log analysisand seismic data indicate the Point MacKenzie and Trading Bay Blocks may containconventional accumulations of natural gas reserves in Tertiary sandstones inaddition to the prospect identified at the Frontier Spirit #1 location.Structural anticlines and/or domes occur on the lease blocks and may containlarge undrilled gas reservoirs. Sandstone units also pinch-out toward themargins of the basin and may have formed stratigraphic traps on the leaseblocks. In the past, oil and gas exploration has focused on oil production andanticlinal gas traps, but stratigraphic accumulations have been largelyunexplored in the Cook Inlet.

 

Additional potential onthe Alaskan Leases may be realized from the development of coal bed methanereserves. The coals occur in seams which are commonly 20 feet thick and can beas thick as 70 feet. Accessible onshore areas have 200 to 300 feet of aggregatecoal thickness shallower than 5,000 feet. Estimated gas content for these coalsranges from 80 to 250 standard cubic feet per ton. Testing for coal bed methanehas been restricted to a very small number of bore holes and is almostcompletely unknown for most of the inlet.

 

***California***

*** ***

*LokernProject*

* *

We have 100% workinginterests in 1,280 lease acreage in the Lokern Project, located in the southernSan Joaquin basin, near Bakersfield, California. The primary explorationobjective is the Miocene Stevens formation. The secondary objectives includethe Miocene Reef Ridge and Pliocene Etchegoin sands. The Stevens formation isUpper Miocene age.

 

The Lokern Project isbeing developed in part as a result of positive results from the Machii-RossAckerman show well drilled in 1979 on acreage currently controlled by us. Basedon log analysis, we believe this well had approximately 240 feet of potentialnet oil pay and an additional 150 feet of potential pay in the Stevenszone. The Machii-Ross Ackerman well was drilled to a depth of 15,078 feet byMachii-Ross Petroleum Company and was plugged and abandoned as a dry hole. Webelieve, based on our log analysis, that the well may have been a bypassedproducer.

 

We expect that a wellwill be drilled, either by us or through a farmout arrangement with a thirdparty, to a depth of 18,000 feet in 2011.

 

Based on our review oftitle information from public authorities and other publicly available sources,we believe that we have a 100% working interest in the Lokern Project. As iscustomary in the U.S. oil and gas industry, we will not conduct a thoroughtitle review with respect to our interest in the Lokern Project until we havemade a definitive decision to drill in a particular lease area.

 

***Alberta***

*** ***

*SwanHills Project*

* *

TheSwan Hills Project is located in the Central Alberta Basin, Alberta, Canada.The primary exploration objective is the Swan Hills Formation at approximately9,000 feet. Secondary objectives will include the shallower Gilwood, Nordeggand Falher formations.

 

We,through our wholly-owned subsidiary, GeoPetro Canada, have reviewed 3-D seismicdata over the prospect and plan to participate in the drilling of a test well.We have a 33% non-working interest in approximately 4,480 gross leasedacres (1,493 net acres).

 

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***Indonesia***

 

C-G Bengara owns 100% ofthe underlying rights to explore for and produce oil and natural gas within thecontract area designated as the Bengara II Block, which rights have beengranted under a production sharing contract dated December 4, 1997 (the “**Bengara II PSC**”) with Pertamina. Previouslywe owned 40% of CG Bengara and Continental Energy Corporation (“**Continental**”) owned the remaining 60% and, through it, therights to the Bengara II PSC. On September 29, 2006, we executed adefinitive agreement to sell 70% of our interest in C-G Bengara to CNPCHK(Indonesia) Limited (“**CNPC**”). We haveretained a 12% stake in C-G Bengara and the Bengara II PSC. Continental haslikewise sold its interest and retained an 18% interest in C-G Bengara and theBengara II PSC.

 

TheBengara Block is located in the Tarakan Basin, mostly onshore but partiallyoffshore astride the Bulungan River Delta in the Indonesian province of EastKalimantan. It originally covered a single contiguous area of approximately1.2 million gross acres, of which 300,000 gross acres were relinquishedin 2001 and an additional 300,000 gross acres were relinquished in 2007 byC-G Bengara in accordance with the terms of the Bengara II PSC. C-GBengara has tendered an additional relinquishment such that the remainingacreage within the Bengara II PSC total approximately 240,000 acres, or 970square kilometers as discussed below.

 

*TheMakapan Gas Field*

* *

Since 1938, only twowells have been drilled in the Bengara Block prior to 2007, one of whichresulted in the discovery of the Makapan Gas Field. The Muara Makapan No. 1well was drilled in 1988 by P.T. Deminex Indonesia from a swamp bargepositioned on one of the Bulungan River Delta mouth channel distributaries. Thewell was drilled to a total depth of 10,800 feet and tested 19.5 MMcf/dtogether with 600 bbls of 54 degree API condensate per day from a33 feet thick sandstone section near 6,000 feet. The well was pluggedand abandoned as a natural gas discovery. Several other gas zones indicated onlogs were not tested. The well was not produced nor were any confirmation wellsdrilled due to the lack of a local natural gas market at the time the well wasdrilled. The Makapan Gas Field gas is a “Wet’ gas with a high LPG fractionwhich may be commercial to extract at the wellhead for a third revenue source inaddition to the gas and condensate. The Makapan Gas Field lies mostly offshorein very shallow water, less than 10 feet, amidst numerous islands of theBulungan River Delta.

 

*Explorationin the Bengara Block*

* *

We believe that the keyto successful prospecting in the Bengara Block will be the identification oftraps and understanding sand distribution.

 

Nearly 2,200 linekilometers of 2-D seismic data available within the Bengara Block appear to beadequate for both detailed and reconnaissance interpretation purposes. Somelocalized areas may benefit from reprocessing. New seismic data is required inplaces where insufficient data exists and for prospect confirmation in otherlocations.

 

Several separate andunique geologic plays within the Bengara Block, as well as a number ofprospects and leads, have been identified. Some well-defined prospects presentimmediate drilling targets. Exploration within the Bengara Block is in itsformative stages and it is premature to make meaningful resource or reserve estimates.However, the existing exploration work to date indicates that there may bepotential petroleum accumulations in the Bengara Block. Analysis of sourcerocks indicates a propensity for both oil and natural gas.

 

*Terms of Participation in the Bengara Block*

 

The Bengara II PSCis a “standard terms” PSC employed by BP Migas for all oil and natural gasconcessions in Indonesia. Generally, the joint venture participants areentitled to receive, from production proceeds, 100% of expenditures in theblock as “cost recovery”. Once these costs are recovered, C-G Bengara isentitled to a production share of approximately 26.7% of oil produced and 62.5%of all natural gas produced. We will be entitled to 12% of C-G Bengara’s shareof any such production. Sharing terms for certain categories of oil varyslightly as defined in the Bengara II PSC. The term of the contractis thirty years from December 1997 or a shorter period if C-G Bengaraelects to terminate its obligations under the contract or if no commercial hydrocarbonsare discovered within the contract area. At the end of six years, unlessmutually extended by C-G Bengara and BP Migas, the contract expires ifno commercially producible hydrocarbons have been discovered in thecontract area. C-G Bengara and BP Migas have mutually extended the earlytermination provisions until December 3, 2011. C-G Bengara may terminatethe contract at any time by relinquishing all of its rights and obligationsunder the contract area. C-G Bengara is required to relinquish 25% of thecontract area within the first three years of the contract, a further 25% ofthe contract area within six years from the commencement of the contract and anadditional area within the first ten years so that the area retained thereaftershall not be in excess of 970 square kilometers, or 20% of the originaltotal contract area, whichever is less. C-G 

 

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Bengara may designate which areas are to berelinquished subject to approval by BP Migas. C-G Bengara’s obligationto relinquish parts of the original contract area under these provisionsdoes not apply to the surface area of any field in which petroleum hasbeen discovered. To date, acreage has been relinquished by C-G Bengara inaccordance with the terms of the Bengara II PSC such that the remainingacreage within the Bengara II PSC totals approximately 240,000 acres, or 970square kilometers.  The remaining 240,000acres is considered by C-G Bengara to be the most prospective portion of theoriginal 1.2 million acre block.

 

C-G Bengara is requiredto pay to BP Migas specified amounts based on achieving certain cumulativeproduction quantities of crude oil from the contract area when and ifcommercial production is established. These production bonuses are as follows:

 
| **Cumulative Production** | ** ** | **Cash Bonus Due** | ** ** |
|--------------------------------|------------|------------------------------|------------|
| 25,000,000 boe                 |       | $                            | 500,000    |   |
| 60,000,000 boe                 |       | $                            | 1,500,000  |   |
| 100,000,000 boe                |       | $                            | 2,500,000  |   |

 

In order to maintain theBengara II PSC in effect, C-G Bengara was required to complete the workprograms and expenditures totaling $25 million during the first ten years ofthe contract.  C-G Bengara has fulfilledsuch minimum work and cash expenditure requirements.

 

Upon establishingcommercial production, if ever, C-G Bengara and BP Migas shall shareratably in the first 20% of oil and natural gas produced in the contract areawithin a given year according to the percentages specified below. After thefirst 20% of production, C-G Bengara is entitled to receive 100% of productionuntil cost recovery has been achieved. Cost recovery generally includes 100% ofthe operating and drilling costs and depreciation of fixed assets applicable tooil and natural gas operations within the contract area. After C-G Bengara hasreceived oil and natural gas production with a value sufficient to achieve costrecovery in a given year, C-G Bengara and BP Migas shall then shareratably in the production according to the percentages specified below:

 
| **Description** | ** ** | **BP Migas** | ** ** | **C-G Bengara** | ** ** | **Our net share** | ** ** |
|-----------------|------------|-------------------|------------|----------------------|------------|-----------------------------|------------|
| Oil production  |       | 73.2143           | %          | 26.7857              | %          | 3.2143                      | %          |
| Gas production  |       | 37.5              | %          | 62.5                 | %          | 7.5                         | %          |

 

Uponthe completion of five years after commercial production commences,C-G Bengara is further subject to a domestic market obligation. Thisobligation requires C-G Bengara to sell and deliver to BP Migas, to meetIndonesia’s domestic crude oil needs, a specified quantity of crude oil at aprice which is only 15% of the market price of the oil. However, for new fields,for a period of five years starting on the month of the first delivery of crudeoil produced from a new field, the fee per barrel for such crude oil suppliedto the Indonesian domestic market shall be the market price, with the conditionthat the excess over the 15% of market price shall preferably be used to assistfinancing of continued exploration efforts in the contract area.

 

Uponthe first commercial discovery of oil or natural gas in the contract area,BP Migas has the right to demand that 10% of C-G Bengara’s undividedinterest in the total rights and obligations under the Bengara II PSCbe offered to itself or an entity owned by Indonesian nationals. The 10%interest shall be offered at a dollar amount equal to 10% of C-G Bengara’scumulative costs incurred in the contract area.

 

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*Current and Planned Activities in the Bengara Block*

 

Inaccordance with the terms of our agreement dated September 29, 2006pursuant to which we sold 70% of our interest in C-G Bengara to CNPC, CNPC:

 

1.                                       Purchased14,000 and 21,000 shares of C-G Bengara from us and Continental, respectively,at a cost of $1 per share. As a result of the transaction, we and Continentalown 6,000 and 9,000 C-G Bengara shares, respectively, retaining a 12% and18% interest in C-G Bengara, respectively.

 

2.                                       Paid the sum of$18.7 million (the “**Earning Obligation**”)into a special joint venture account at a Hong Kong international bank. Thefunds were expended exclusively to pay for exploration and/or appraisaldrilling in the Bengara II PSC area.

 

3.                                       Agreed toprovide development loans to pay 100%, and thereby “carry” our share andContinental’s share of all C-G Bengara’s exploitation, drilling, anddevelopment expenditures attributable to the Bengara II PSC, after the EarningObligation funds are expended and a Plan of Development has been approved by BPMigas, until an additional amount of U.S. $41.3 million over and above theEarning Obligation funds has been expended.

 

4.                                       Agreed to pay acash bonus totaling $5,000,000, in the proportions of $2,000,000 to us and$3,000,000 to Continental, respectively, contingent upon and within fourteenbusiness days of the receipt by C-G Bengara of the written approval fromgovernmental authorities approving the development of the first commercial oilor gas discovery within the Bengara II PSC contract area.

 

During 2007, C-G Bengaradrilled a total of four wells on the Bengara II PSC: the Seberaba-1, theSeberaba-3, the Seberaba-4, and the Punga-1. The technical information providedby drilling and testing results to date confirm the presence of an oilaccumulation. However the data is not yet adequate to conclusively demonstratethe extent of the oil accumulation or that it has sufficient size of oilreserves to economically justify a full commercial development. Furthertechnical information is required prior to commencing development.  C-G Bengara has prepared a preliminary planof development for the Seberaba discovery based upon drilling and testingresults from the Seberaba-1 and 3 wells. In addition to these well testresults, C-G Bengara believes additional technical information is needed priorto finalizing the formal plan of development and submitting it for approval toIndonesian oil and gas authorities. Approval of the formal plan of developmentwill automatically invoke the final 20-year production period of the Bengara-IIPSC through December 4, 2027.

 

During2009 C-G Bengara awarded a contract to a seismic acquisition contractor toconduct a seismic acquisition program in the Bengara-II Block.  Work is presently underway to acquire a totalof 120 square kilometers of 3D seismic and 844 line kilometers of 2D seismic atan estimated acquisition cost of $ 28.5 million. The primary objective of the3D seismic program is to further define and delineate the Seberaba oildiscovery and the Makapan gas/condensate discovery. CGB2 is eyeing a jointdevelopment of Makapan gas with Seberaba oil to achieve economies of scale andprovide a gas source for fuel, pressure maintenance, and artificial lift ofoil.

 

Alarge part of the 2D seismic program is also intended to provide additionaldefinition of other exploration prospects in the Bengara-II Block to firm upnew exploration drilling targets for a proposed 2010/2011 drilling program. Alarge portion of the seismic acquisition program shall be conducted in thelogistically difficult and higher cost “transition zone” between a shallowmarine offshore and onshore setting. The eastern portion of the Block islocated mostly onshore but partially offshore in the shallow waters of theSulawesi Sea and the Bulungan River delta.

 

C-G Bengara has received approval of the Indonesian governmentfor an extension of time under the Bengara-II PSC to appraise, assess, andjustify the economic feasibility of commercial development of the apparent oildiscovery made on the Seberaba prospects during exploratory drilling in 2007 asnoted above.  The extension is validuntil December 3, 2011 and may be extended for subsequent yearssubject to further approval based on an annual review of progress and resultsof appraisal work.

 

*CGXploration*

* *

InNovember 2005, we and Continental formed CG Xploration to pursue newventure oil and gas exploration and production projects and obtain newexploration concessions in Indonesia. CG Xploration Inc. isincorporated in Delaware and is owned 50% by us and 50% by Continental.CG Xploration Inc. may acquire new venture opportunities on behalf ofourselves and Continental. To date, CG Xploration has not completed anyacquisitions.

 

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***Australia***

 

On June 20, 2007, the Company agreed to sell andtransfer all of its remaining property interests in Australia to an unrelatedparty for cash consideration and a Petroleum Sales Royalty Payment equal to 25%of the future annual earnings before interest, taxes, depreciation andamortization from the property interests. Specifically, the agreement providesthat the Company will be paid consideration for the sale and transfer of itsproperty interests as follows:

 

1.      Initial cash consideration of $175,000was received on November 19, 2007;

 

2.      a second cash payment of $175,000 upon asuccessful flow test of petroleum from a well located on the propertyinterests. A successful flow test is defined for purposes of this agreement tobe a test of at least 7 million standard cubic feet of natural gas for acontinuous and uninterrupted 24 hour period (or an equivalent oil/condensaterate based on a conversion ratio of 6000 cubic feet of gas to a barrel of oilor condensate); and,

 

3.      a Petroleum Sales Royalty Payment equalto 25% of the future annual earnings before interest, taxes, depreciation andamortization from the property interests up to a total amount of $2,200,000.

 

**ProvedReserves Disclosures**

 

**RecentSEC Rule-Making Activity*** *  In December 2008, theSEC announced that it had approved revisions designed to modernize the oil andgas company reserves reporting requirements. The most significant amendments tothe requirements that impact us included the following:

 

·                  Commodity Prices**—**Economic producible reserves and discounted cash flows are now based on a12-month average net natural gas price unless contractual arrangementsdesignate the price to be used.

 

·                  Disclosure of Unproved Reserves — Probable and possible reserves may be disclosed separately on avoluntary basis.  We are not presentlydisclosing probable and possible reserves, but may do so in the future.

 

·                  Proved Undeveloped Reserves Guidelines — Reserves may be classified asproved undeveloped if there is a high degree of confidence that the quantitieswill be recovered and they are scheduled to be drilled within the next fiveyears, unless the specific circumstances justify a longer time.

 

·                  Reserves Estimation Using New Technologies — Reserves may be estimated throughthe use of reliable technology in addition to flow tests and productionhistory.

 

·                  Reserves Personnel and Estimation Process — Additional disclosure is requiredregarding the qualifications of the chief technical person(s) who overseethe reserves estimation process.  We are also required to provide ageneral discussion of our internal controls used to assure the objectivity ofthe reserves estimate.

 

·                  Disclosure by Geographic Area — Reserves in foreign countries orcontinents must be presented separately if they represent more than 15% of ourtotal oil and gas proved reserves.  Wepresently do not report reserves in foreign countries or continents, but may doso in the future as a result of our exploration activities.

 

·                  Non-Traditional Resources — The definition of oil and gas producing activities has expandedand focuses on the marketable product rather than the method of extraction.

 

We adopted the rules effectiveDecember 31, 2009.

 

*Effectof Adoption -  *Application of the new reserve rules resulted inthe use of a lower natural gas price at December 31, 2009 than would haveresulted under the previous rules. The new pricing methodology rules resultedin a lower net present value (PV-10) of economically producible reserves.  The prices under the new rules were $3.11 per Mcf for natural gas adjusted for energycontent, quality and basis differentials. Under the new rules, this resulted ina year-end ceiling test write-down of $19.8 million associated with the US fullcost pool.  Had we used the price prevailing on December 31,2009 of $5.45 per Mcf for natural gas, therewould have been no year-end ceiling test write-down. Under full costaccounting, a ceiling test is performed to ensure that unamortized capitalizedcosts in each cost center (country) do not exceed their fair value. Impairment is recognized when the carrying value is greater than the discountedfuture cash flows.  In the event of impairment, the amount by which thecarrying value exceeds the estimated fair value of the long-lived asset ischarged to earnings. The present value of estimated future net revenues iscomputed by applying current oil and gas prices to estimated future productionof proved oil and gas 

 

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reserves, less estimatedfuture expenditures to be incurred in developing and producing the provedreserves assuming the continuation of existing economic conditions.

 

Use of new 12-monthaverage pricing rules at December 31, 2009 also resulted in adecrease in economically producible proved reserves of approximately 1.03 Bcf.Use of the old year-end prices rules would have resulted in a decrease inproved reserves of approximately 0.53 Bcf at December 31,2009. Therefore, the total impact of the new price methodology rules resultedin negative reserves revisions of 0.5 Bcf.

 

Theuse of the new pricing methodologyhad an insignificant impact on our depletion expense in the fourth quarter of2009.

 

**InternalControls Over Reserves Estimates*** * Our policies regarding internal controlsover the recording of reserves estimates requires reserves to be in compliancewith the SEC definitions and guidance and prepared in accordance with generallyaccepted petroleum engineering principles.

 

TheCompany engaged the independent petroleum engineering firm, MHA PetroleumConsultants, LLC (“MHA”) to prepare the Company’s reserve estimates at December 31,2009, 2008 and 2007. MHA is a Denver based group of approximately 30professional engineers and geologists providing a wide range of technicalservices to the petroleum industry.  Within MHA, the technical personsprimarily responsible for preparing the estimates set forth in the MHA reservesreport incorporated herein are Mr. John Arsenault and Mr. DennisHoller.  Mr. Arsenault has been practicing consulting petroleumengineering at MHA since 2006, and has over 23 years of practicalexperience in petroleum engineering, with over 10 years experience in theestimation and evaluation of reserves. Mr. Holler has been practicingconsulting petroleum geology at MHA since 2001.  Mr. Holler has over35 years of practical experience in petroleum geology, with over25 years experience in the estimation and evaluation of reserves. Bothtechnical principals meet or exceed the education, training, and experiencerequirements set forth in the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information promulgated by the Society ofPetroleum Engineers; both are proficient in judiciously applying industrystandard practices to engineering and geosciences evaluations as well asapplying SEC and other industry reserves definitions and guidelines. MHAevaluated properties representing 100% of our reserves, valued at the totalestimated future net cash flows before income taxes, discounted at 10% (“PV-10”),for all periods presented below. Senior members of our management review thefinal reserve report to ensure the accuracy and completeness of all inputs intothe report. MHA’s report to management, which summarizes the scope of workperformed and its conclusions, has been included in this report as Exhibit 99.1

 

**ProvedUndeveloped Reserves (PUDs) -** As of December 31, 2009, our PUDs totaled8.4 Bcf of natural gas.

 

·                  *PUD Locations - *100% of our PUDs at year-end 2009 wereassociated with a location in the Madisonville Field.

 

·                  *Changes in PUDS -  *Changes in PUDs that occurred during theyear were due to two reasons.  The first reason is that one Probablelocation from the year end 2008 report was moved to a PUD in the year end 2009report.  This change was based on the overall Proved volumetrics for thefield (which did not change year over year), and a decline in the volumesassigned for existing Proved Developed locations because of reservoirgeometry.  The second reason is that the hydraulic fracture treatment forthe existing Wilson well in conjunction with the necessary plant upgrade tohandle the increased volume of gas have been moved into the PUD category becauseof the relatively large expense required to achieve the predicted rates.

 

·                  *Development Costs -  *No*c*ostswere incurred* *relating tothe development of PUDs in 2009 and 2008.

 

·                  Estimated future development costs relating to thedevelopment of PUDs are projected to be approximately $6.6 million in 2010 and2011.

 

·                  *Drilling Plans -  *Our PUD development is scheduled in 2010and 2011.   Initial production from the PUD reserves is expected tobegin in 2010.

 

For more information seethe following:

 

·                  Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations — Comparison of Results of Operations for theyear ended December 31, 2009 and 2008 for a discussion of thefinancial impact of the SEC revisions;

 

·                  Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations — Critical AccountingPolicies and Estimates — Reserves for further discussion of our reservesestimation process;

 

·                  Item 8. Financial Statements andSupplementary Data — Supplementary Oil and Gas Information (Unaudited) foradditional information regarding estimates of crude oil and natural gasreserves, including estimates of proved, proved developed, and provedundeveloped reserves, the standardized measure of discounted future net cashflows, and the changes in the standardized measure of discounted future netcash flows.

 

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*OtherReserves Information    *Since January 1, 2009, no crude oil ornatural gas reserves information has been filed with, or included in any reportto, any federal authority or agency other than the SEC and the AlbertaSecurities Commission.  We filedreports with the Alberta Securities Commission in March 2009 that includedtotal proved reserves using forecasted (escalated) natural gas prices inclusiveof royalties and net profits interests as of December 31, 2008 totaling46,168 MMcf. The total net proved reserves using period-end (un-escalated)natural gas prices, excluding royalties and net profits interests, as of December 31,2008 was 20,470 MMcf. The difference between the two numbers represents provedreserves attributable to royalties and net profits interests as well as thedifferent natural gas price scenarios.

 

Ourestimated total net proved reserves of natural gas and oil as of December 31,2009 and 2008, and the present values of estimated future net revenuesattributable to those reserves as of those dates, are presented in thefollowing tables.

 

**“Proveddeveloped oil and gas reserves”** means reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.Additional oil and gas expected to be obtained through the application of fluidinjection or other improved recovery techniques for supplementing the naturalforces and mechanisms of primary recovery should be included as “proveddeveloped reserves” only after testing by a pilot project or after the operationof an installed program has confirmed through production response thatincreased recovery will be achieved.

** **

**“Proveddeveloped nonproducing reserves”** means reserves expected to be recovered fromzones behind casing in existing wells.

** **

*“***Proved oil and gas reserves***” -*Proved oil and gas reserves are thosequantities of oil and gas, which, by analysis of geoscience and engineeringdata, can be estimated with reasonable certainty to be economicallyproducible—from a given date forward, from known reservoirs, and under existingeconomic conditions, operating methods, and government regulations—prior to thetime at which contracts providing the right to operate expire, unless evidenceindicates that renewal is reasonably certain, regardless of whether deterministicor probabilistic methods are used for the estimation. The project to extractthe hydrocarbons must have commenced or the operator must be reasonably certainthat it will commence the project within a reasonable time.

 

(a)                                  Thearea of the reservoir considered as proved includes:

 

i.                  The area identified by drilling andlimited by fluid contacts, if any; and

 

ii.               Adjacent undrilled portions of thereservoir that can, with reasonable certainty, be judged to be continuous withit and to contain economically producible oil or gas on the basis of availablegeoscience and engineering data.

 

(b)                                 Inthe absence of data on fluid contacts, proved quantities in a reservoir arelimited by the lowest known hydrocarbons (LKH) as seen in a well penetrationunless geoscience, engineering, or performance data and reliable technologyestablishes a lower contact with reasonable certainty.

 

(c)                                  Wheredirect observation from well penetrations has defined a highest known oil (HKO)elevation and the potential exists for an associated gas cap, proved oilreserves may be assigned in the structurally higher portions of the reservoironly if geoscience, engineering, or performance data and reliable technologyestablish the higher contact with reasonable certainty.

 

(d)                                 Reserveswhich can be produced economically through application of improved recoverytechniques (including, but not limited to, fluid injection) are included in theproved classification when:

 

i.                  Successful testing by a pilot project inan area of the reservoir with properties no more favorable than in thereservoir as a whole, the operation of an installed program in the reservoir oran analogous reservoir, or other evidence using reliable technology establishesthe reasonable certainty of the engineering analysis on which the project orprogram was based; and

 

ii.               The project has been approved fordevelopment by all necessary parties and entities, including governmentalentities.

 

(e)                                  Existingeconomic conditions include prices and costs at which economic producibility froma reservoir is to be determined. The price shall be the average price duringthe 12-month period prior to the ending date of the period covered by thereport, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless pricesare defined by contractual arrangements, excluding escalations based uponfuture conditions.

 

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The2009 and 2008 estimates were prepared by MHA Petroleum Consultants, independentreservoir engineers, and are part of their reserve reports on our natural gasand oil properties. MHA Petroleum Consultants’ estimates were based on a reviewof geologic, economic, ownership and engineering data that we provided. Inestimating the reserve quantities that are economically recoverable, MHAPetroleum Consultants used end-of-period natural gas prices for the 2008estimates. Prices used for the year ended December 31, 2009 estimates werethe simple arithmetic average of the natural gas price in effect on the firstday of each month in 2009. In accordance with U.S. Securities and ExchangeCommission regulations, no price or cost escalation or reduction wasconsidered. All of our proved reserves are attributable to our MadisonvilleProject in Madison County, Texas.

 
| ** **                     | ** ** | **AS OF DECEMBER 31,** | ** ** |
|--------------------------------|------------|---------------------------------------|------------|
| ** **                     | ** ** | **2009**                              | ** ** | **2008** | ** ** |
| ** **                     | ** ** | **(MMcf)**                            | ** ** | **(MMcf)** | ** ** |
| Proved developed               |       | 3,650                                 |       | 17,300 |   |
| Proved developed non-producing |       | 6,611                                 |       | 3,170 |   |
| Proved undeveloped             |       | 8,371                                 |       | — |   |
|                           |       |                                  |       |   |   |
| Total                          |       | 18,632                                |       | 20,470 |   |

 

In accordance withSecurities and Exchange Commission regulations, estimates of our provedreserves and future net revenues are made using sales prices which are heldconstant throughout the life of the properties, except to the extent a contractspecifically provides for escalation. Estimated quantities of proved reservesand future net revenues are affected by natural gas and oil prices, which havefluctuated significantly in recent years.

 

***Standardized Measure ofDiscounted Future Net Cash Flows***

*** ***

For purposes of thefollowing disclosures, estimates were made of quantities of proved reserves andthe periods during which they are expected to be produced. Future cash flowsfor the 2008 estimates were computed by applying year-end prices to estimatedannual future production from proved gas reserves. Future cash flows for the2009 estimates were computed by applying the simple arithmetic average of thenatural gas price in effect on the first day of each month in 2009 to estimatedannual future production from proved gas reserves. The price assumptions usedfor natural gas are indicated below. Future development drilling and productioncosts were computed by applying year-end costs to be incurred in producing andfurther developing the proved reserves. Future income tax expenses werecomputed by applying, generally, year-end statutory tax rates (adjusted forpermanent differences, tax credits and allowances) to the estimated net futurepre-tax cash flows. The discount was computed by application of a 10% discountfactor. The calculations assume the continuation of existing economic,operating and contractual conditions. However, such arbitrary assumptions havenot proven to be the case in the past. Other assumptions of equal validitycould give rise to substantially different results.

 
| ** **                                                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| ** **                                                | ** ** | **(in thousands)**                    | ** ** |
| Future cash inflows                                       |       | 50,652                                     |       | $ | 107,063 |   |
| Future production costs                                   |       | (17,157                                    | )          | (34,414 | ) |
| Future development costs                                  |       | (7,849                                     | )          | (5,075 | ) |
| Future income taxes                                       |       | —                                     |       | (7,977 | ) |
| Future net cash flows                                     |       | 25,646                                     |       | 59,597 |   |
| 10% annual discount                                       |       | (6,005                                     | )          | (12,282 | ) |
| Standardized measure of discounted future net cash  flows |       | $                                          | 19,641     |   | $ | 47,315 |   |
|                                                           |            |                                            |            |  |  |  |  |

 

The standardized measurevalues shown in the aforementioned table are not intended to represent thecurrent market value of the estimated proved oil and gas reserves owned by us.

 

***Pricing Assumptions***

*** ***

**SEC regulations require that thegas prices used in the MHA Petroleum Consultants reserve reports includedherewith are the period-end prices for natural gas at December 31,2008.  SEC regulations require that thegas price used for the December 31, 2009 MHA Petroleum Consultants reservereport is the simple arithmetic average of the natural gas price in effect onthe first day of each month in 2009. These prices are projected withoutinflation for the life of the wells included in the reserve reports. Thepricing assumptions are listed below and represent the weighted average pricefor natural gas at December **31st delivered at the Houston Ship Channel before anyreductions for transportation and processing fees.

 

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| **AVERAGE PRICE** | ** ** | **YEAR-END PRICE** | ** ** |
|------------------------|------------|-------------------------|------------|
| **2009 REPORT**   | ** ** | **2008 REPORT**    | ** ** |
| **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)**  | ** ** |
|                   |       |                    |       |
| $                      | 3.11       |                    | $          | 5.25 |   |
|                        |            |                         |            |  |  |

 

**DrillingActivities**

** **

**The following indicates the numberof natural gas wells drilled during the periods indicated.**

 
| ** **                        | ** ** | **Productive** | ** ** | **Dry** | ** ** | **Total Wells** | ** ** |
|-----------------------------------|------------|----------------|------------|---------|------------|----------------------|------------|
| ** **                        | ** ** | **Gross**      | ** ** | **Net** | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Year ended December 31, 2009 |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Exploratory                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |
| Development                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |
|                              |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Year ended December 31, 2008 |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Exploratory                       |       | 0              |       | 0       |       | 3                    |       | 1.15 |   | 3 |   | 1.15 |   |
| Development                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |

 

**Acreageand Productive Wells**

** **

Thefollowing table sets forth our ownership interest in undeveloped acreage,developed acreage and productive wells in the areas indicated where we own aworking interest as of December 31, 2009. Gross represents the totalnumber of acres or wells in which we own a working interest. Net represents ourproportionate working interest resulting from our ownership in gross acres orwells. Productive wells are wells in which we have a working interest and thatare capable of producing natural gas or oil. Wells that are completed in morethan one producing horizon are counted as one well.

 
| ** **            | ** ** | **Undeveloped acreage** | ** ** | **Developed acreage** | ** ** | **Producing Wells** | ** ** | **Non-Producing Wells** | ** ** |
|-----------------------|------------|-------------------------|------------|-----------------------|------------|---------------------|------------|-------------------------|------------|
| **Acreage  Holdings** | ** ** | **Gross Acres**         | ** ** | **Net Acres**         | ** ** | **Gross Acres**     | ** ** | **Net Acres**           | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|                  |       |                    |       |                  |       |                |       |                    |       |   |   |   |   |   |   |   |   |
| Indonesia             |       | 239,692                 |       | 28,763                |       | —              |       | —                  |       | — |   | — |   | — |   | — |   |
| Canada                |       | 4,480                   |       | 1,493                 |       | —              |       | —                  |       | — |   | — |   | — |   | — |   |
| Texas                 |       | 5,484                   |       | 5,484                 |       | 3,520               |       | 3,520                   |       | 3 |   | 3 |   | 1 |   | 1 |   |
| California            |       | 1,280                   |       | 1,280                 |       | —              |       | —                  |       | — |   | — |   | — |   | — |   |
| Alaska                |       | 123,050                 |       | 123,050               |       | —              |       | —                  |       | — |   | — |   | — |   | — |   |
| Total                 |       | 373,986                 |       | 160,070               |       | 3,520               |       | 3,520                   |       | 3 |   | 3 |   | 1 |   | 1 |   |

 

Thefollowing table sets forth as of December 31, 2009, the expiration periodsof the gross and net undeveloped acreage:

 
| ** **                             | ** ** | **Undeveloped Acreage** | ** ** |
|----------------------------------------|------------|-------------------------|------------|
| ** **                             | ** ** | **United States**       | ** ** | **Indonesia** | ** ** | **Canada** | ** ** |
| ** **                             | ** ** | **Gross**               | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Twelve months ended                    |       |                    |       |   |   |   |   |   |   |   |   |   |   |
| December 31, 2010                 |       | 2,490                   |       | 2,490 |   | — |   | — |   | — |   | — |   |
| December 31, 2011                 |       | 1,685                   |       | 1,685 |   | 239,692 |   | 28,763 |   | — |   | — |   |
| December 31, 2012                 |       | 124,151                 |       | 124,151 |   | — |   | — |   | 4,480 |   | 1,493 |   |
| December 31, 2013                 |       | 1,310                   |       | 1,310 |   | — |   | — |   | — |   | — |   |
| December 31, 2014  and thereafter |       | 177                     |       | 177 |   | — |   | — |   | — |   | — |   |
|                                   |       | 129,813                 |       | 129,813 |   | 239,692 |   | 28,763 |   | 4,480 |   | 1,493 |   |

 

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**Table of Contents**

 

**Volumes,Prices and Production Costs**

** **

Substantially all of ourproduction is derived from our Madisonville Project in Madison County, Texas.The following table sets forth information with respect to our productionvolumes, average prices received and average production costs for the periodsindicated:

 
| ** **                  | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------|------------|-----------------------------|------------|
| ** **                  | ** ** | **2009**                    | ** ** | **2008** | ** ** |
| Production:                 |       |                        |       |   |   |
| Natural gas (MMcf) (1)      |       | 1,278                       |       | 1,275 |   |
| Natural gas (MMcf/d) (1)    |       | 3.50                        |       | 3.49 |   |
|                        |       |                        |       |   |   |
| Average Sales Prices (2)    |       |                        |       |   |   |
| Natural gas ($per Mcf) (2)  |       | $                           | 3.19       |   | $ | 4.82 |   |
|                        |       |                        |       |   |   |
| Lease Operating Expense     |       |                        |       |   |   |
| ($per Mcf) (3)              |       | $                           | 0.66       |   | $ | 1.16 |   |
|                        |       |                        |       |   |   |
| Plant Operating Expense (4) |       |                        |       |   |   |
| ($per Mcf)                  |       | $                           | 3.71       |   | — |   |

 

 

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(1)     Productionvolumes for 2009 represent actual plant throughput.  Sales volumes net to our interests in theMadisonville gas wells for the year ended December 31, 2009 amounted to807 MMcf, or 2.2MMcf/d.

 

(2)                Representssales price realized net of treatment, gathering and transportation costs in2008 since we sold the gas at the wellhead to an unaffiliated purchaser.  Commencing January 1, 2009, we moved thepoint of sale of the gas to the outlet of the gas treatment plant since wepurchased the gas treatment plant and related gathering systems effective December 31,2008.  Accordingly, the sales pricereflected for the year ended December 31, 2009 represents the sales pricerealized before deducting treatment, gathering and transportation costs, and isbased up on plant throughput.

 

(3)   Lease operating expense perMcf is based on lease operating expense and sales volumes net to our interestsin the Madisonville gas wells.

 

(4)   Plantoperating expense per Mcf is based on total plant operating expense and actualplant throughput.

 

**Business Risks** and Other Special Considerations

** **

Refer to “Risk Factors”in this report for a discussion of business risks and other specialconsiderations.

 

**Item 3. *Legal Proceedings***

 

Fromtime to time, we are party to litigation or other legal and administrativeproceedings that we consider to be a part of the ordinary course of ourbusiness. Currently, we are not involved in any legal proceedings nor are weparty to any pending or threatened claims that could, individually or in theaggregate, reasonably be expected to have a material adverse effect on ourfinancial condition, cash flow or results of operations, except as follows:

 

On September 11,2009, the Company’s subsidiary, Redwood Energy Production, L.P. filed anOriginal Petition for Declaratory Judgment against Devon Energy ProductionCompany (“Devon”) regarding certain overriding royalty interests and relatedrevenue amounts claimed by Devon.  The Company previously accrued allamounts owed pursuant to these overriding royalty interests as royalty ownerspayable.  In the opinion of management based on consultation with legalcounsel, these proceedings are not expected to have a material adverse effecton our financial condition or results of operations.

 

**Item 4. *Reserved***

 

Not applicable.

 

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**PART II**

 

**Item 5.**          ***Market for the Registrant’s Common Equity, Related Shareholder Mattersand Issuer Purchases of Equity Securities***

 

Ourcommon stock trades on the NYSE Amex under the symbol “GPR”.   On March 30, 2010, the last reportedsale price for our common stock on the NYSE Amex was $0.61. The following tablesets forth the high and low sale prices of our common shares as reported on theNYSE Amex for the periods presented.

 
| ** **     | ** ** | **NYSE Alternext US  (1)** | ** ** |
|----------------|------------|--------------------------------------|------------|
| ** **     | ** ** | **High**                             | ** ** | **Low** | ** ** |
| **2009**       |       |                                 |       |   |   |
| Fourth Quarter |       | $                                    | 1.05       |   | $ | 0.57 |   |
| Third Quarter  |       | $                                    | 1.35       |   | $ | 0.33 |   |
| Second Quarter |       | $                                    | 0.78       |   | $ | 0.33 |   |
| First Quarter  |       | $                                    | 1.27       |   | $ | 0.21 |   |
| **2008**       |       |                                 |       |   |   |
| Fourth Quarter |       | $                                    | 2.28       |   | $ | 0.48 |   |
| Third Quarter  |       | $                                    | 4.12       |   | $ | 1.90 |   |
| Second Quarter |       | $                                    | 4.29       |   | $ | 2.25 |   |
| First Quarter  |       | $                                    | 3.58       |   | $ | 2.00 |   |

 

----

(1)                    Ourcommon stock commenced trading on the American Stock Exchange on February 15,2007. On December 1, 2008, the American Stock Exchange was merged with theNYSE Exchange.

 

(2)                    Asof March 12, 2010, there were 301 holders of record of our common shares.

 

**Incentive Stock Plan and Stock OptionPlan**

 

Effective as of September 10,2001, the board of directors approved an incentive stock plan, providing forawards under the terms and provisions of such plan of incentive stock options,stock appreciation rights and restricted stock awards to officers, directorsand employees of GeoPetro and its consultants (the “Stock Incentive Plan”). Theplan provides, among other provisions, the following:

 

The maximum number ofCommon Shares which may be awarded, optioned and sold under the plan is5,000,000 (subject to adjustment for stock splits, stock dividends and certainother adjustments to GeoPetro’s common stock); and the per share exercise pricefor Common Shares to be issued pursuant to the exercise of an option shall beno less than the fair market value of GeoPetro’s Common Shares as of the dateof grant.

 

The Stock Incentive Planprovides for the granting to employees incentive stock options within themeaning of Section 422 of the United States Internal Revenue Code of1986, as amended, and for the granting of non-statutory stock options todirectors who are not employees and consultants. In the case of employees whoreceive incentive stock options which are first exercisable in a particularcalendar year and the aggregate fair market value of which exceeds $100,000,the excess of the $100,000 limitation shall be treated as a nonstatutory stockoption under the Stock Incentive Plan.

 

The Stock Incentive Planis being administered by the Board of Directors. The Board of Directorsdetermines the terms of the options granted, including the number of CommonShares subject to each option, the exercisability and vesting requirements ofeach option, and the form of consideration payable upon the exercise of suchoption (i.e., whether cash or exchange of existing Common Shares in a cashlesstransaction or a combination thereof). The Stock Incentive Plan will continuein effect for 10 years from September 10, 2001 (i.e., the datefirst adopted by the Board), unless sooner terminated by the board ofdirectors.

 

In 2004, we implemented anew 2004 Stock Option and Appreciation Rights Plan (the “Stock Option Plan”)providing for awards of incentive stock options, non-qualified stock optionsand stock appreciation rights. The Stock Option Plan replaced the StockIncentive Plan as to new award grants effective in 2004 or thereafter to ourdirectors, officers, employees and consultants. Outstanding awards issued underthe Stock Incentive Plan will continue to be outstanding in accordance withtheir terms and the terms of the Stock Incentive Plan, but will count towardthe limits in the number of shares of common stock available to be issued underthe Stock Option Plan, which is 5,000,000. The exercise price of stock optionsgranted under the Stock Option Plan may not be less than 110% of the fair marketvalue of our common stock on the date of grant.

 

**Dividends**

 

The holders of Series Bpreferred stock are entitled to receive ratably such cash dividends, as weredeclared from time to time by the board of directors out of funds legallyavailable therefor and, when declared, dividends were paid at the rate of $0.06per share per annum, paid on a calendar quarter basis.  During 2009, we incurred $179,045 individends associated with the Series B preferred stock, of which $68,583had been paid as of December 31, 2009.

 

The holders of our commonstock shall be entitled to receive ratably such lawful dividends as may bedeclared by the Board of Directors. We have never paid any dividends, whethercash or property, on our common stock. For the foreseeable future it isanticipated that any earnings which may be generated from our operations willbe used to finance our growth and that dividends will not be paid to commonstockholders.

 

**Use of Proceeds**

 

On our registrationstatement on Form S-1 (Reg. No. 333-135485) we registered up to16,499,991 shares of our common stock, no par value per share, including5,943,105 shares of common stock issuable upon exercise of warrants andoptions, for resale by selling shareholders. The registration statement wasdeclared effective by the Securities and Exchange Commission in February 2007.The offering commenced on in February 2007 and has not terminated. On ourregistration statement on Form S-1 

 

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(Reg. No. 333-146557) we registered up to2,002,599 shares of outstanding common stock and the resale of up to 780,857shares of common stock issuable upon exercise of warrants, for resale byselling shareholders. The registration statement was declared effective by theSecurities and Exchange Commission in October 2007. The offering commencedin October 2007 and has not terminated. We will not receive any proceedsfrom the sale of our common stock by the selling shareholders under theregistration statements; however, if all warrants and options to acquire ourcommon stock being registered thereunder are exercised, we will realize cashproceeds of approximately $12,168,321, which we expect to use for generalworking capital purposes and the drilling of wells in our Texas, California,Canadian and Indonesian prospects.

 

If less than the $12,168,321proceeds are realized from the exercise of such warrants and options, theproceeds will be spent in the following order of priority:

 

1.                       MadisonvilleProject, Madison County, Texas — Approximately $3,028,000 may be expended inthe Madisonville Field area as follows: $1,433,000 million for capitalmaintenance and repair on new gas treatment plant; $945,000 toward the fracturestimulation and hook up costs of the Wilson Well; and $650,000 for the Mitchellwell workover.

 

2.                       California—Approximately $500,000 to be utilized for land and permitting costs.

 

We do not know if, or howmany, of the warrants or options will be exercised. This is our best estimateof our use of proceeds generated from the possible exercise of warrants oroptions based on the current state of our business operations, our currentplans and current economic and industry conditions. Any changes in theprojected use of proceeds will be made at the sole discretion of our board ofdirectors.

 

**UnregisteredSales of Securities**

 

During October 2009,we issued 3,401,996 shares of Series B Preferred Stock for total grossproceeds of 2,551,500 pursuant to preferred stock purchase agreements with 31accredited investors.  We issued the Series B Convertible PreferredStock in reliance on the exemption from registration provided for under Section 4(2) ofthe Securities Act, and Rule 506 of Regulation D thereunder. We relied onthe exemption from registration provided for under Section 4(2) ofthe Securities Act based in part on the representations made by the investors,including the representations with respect to the investors’ status as accreditedinvestors, as such term is defined in Rule 501(a) of the SecuritiesAct, and the their investment intent with respect to the shares purchased. Wepaid $134,600 in cash and issued 170,190 warrants (exercisable at $1.00 pershare) as finders fees and commissions in connection with this offering.

 

During October 2009,GeoPetro raised $720,000 (before fees) by issuing an unsecured subordinatedpromissory note to an accredited investor, having the following terms:  (i) 10% annual simple interest payableat maturity, (ii) principal and any unpaid outstanding interest shall bepayable October 31, 2010, (iii) subordinated to the BOK loan and (iv) beunsecured.  The note purchaser alsoreceived a warrant to purchase 36,000 shares of GeoPetro common stock for $1.00per share, exercisable for three years. The issuance of the promissory note and warrant was not registered underthe Securities Act of 1933, in reliance on Section 4(2) of the Actand Rule 506 of Regulation D thereunder. The person acquiring the note and warrant was an accredited investor, asdefined in Rule 501(a) of Regulation D.  The issuance of the promissory note andwarrant involved no public offering. GeoPetro did not engage in general solicitation or advertising inconnection with the issuance and sale of the promissory note and warrant, anddid not engage an underwriter.

 

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**Item 6. *SelectedConsolidated Financial Data***

 

Thefollowing selected consolidated financial data should be read in conjunctionwith “Management’s Discussion and Analysis of Financial Condition and Resultsof Operations” and our consolidated financial statements and the related notesto those statements included elsewhere in this report. The consolidatedstatements of operations data for the years ended December 31, 2009 and2008 and the balance sheet data as of December 31, 2009 and 2008 arederived from our audited consolidated financial statements included elsewherein this report. The consolidated statements of operations data for the yearsended December 31, 2007, 2006 and 2005 and the balance sheet data as of December 31,2007, 2006, and 2005 are derived from our audited consolidated financialstatements not included in this report.  Historical results are not necessarily indicative of the results to beexpected in the future, and the results for the years presented should not beconsidered indicative of our future results of operations.

 
| ** **                                                 | ** ** | **For The Years Ended December 31,** | ** **  |
|------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                 | ** ** | **2009**                                                      | ** **  | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Consolidated Statement of  Operations:**                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Revenues**                                               |       | $                                                             | 4,077,355   |   | $ | 6,152,542 |   | $ | 6,890,777 |   | $ | 6,716,360 |   | $ | 7,975,990 |   |
| **Plant operating expense**                                |       | 4,832,548                                                     |        | — |   | — |   | — |   | — |   |
| **Lease operating expense**                                |       | 606,266                                                       |        | 1,484,267 |   | 1,558,900 |   | 1,602,932 |   | 878,176 |   |
| **General and administrative**                             |       | 2,767,385                                                     |        | 2,717,121 |   | 2,807,091 |   | 2,347,447 |   | 1,551,747 |   |
| **Net profits expense**                                    |       | —                                                        |        | 579,941 |   | 679,337 |   | 632,708 |   | 856,837 |   |
| **Impairment expense**                                     |       | 20,843,305                                                    |        | 69,856 |   | 1,111,151 |   | 38,849 |   | — |   |
| **Depreciation and depletion  expense**                    |       | 1,595,597                                                     |        | 1,553,418 |   | 2,269,995 |   | 2,406,612 |   | 1,832,693 |   |
| **Earnings (loss) from operations**                        |       | (26,567,746                                                   | )           | (252,061 | ) | (1,535,697 | ) | (312,188 | ) | 2,856,537 |   |
| **Net income (loss)**                                      |       | (25,808,260                                                   | )           | (174,825 | ) | (1,616,804 | ) | (482,406 | ) | 2,640,471 |   |
| **Net income (loss) attributable  to common shareholders** |       | $                                                             | (25,987,305 | ) | $ | (174,825 | ) | $ | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   |
|                                                       |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Share:**                             | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Basic**                                                  |       | $                                                             | (0.76       | ) | $ | (0.01 | ) | $ | (0.05 | ) | $ | (0.04 | ) | $ | 0.10 |   |
| **Diluted**                                                |       | $                                                             | (0.76       | ) | $ | (0.01 | ) | $ | (0.05 | ) | $ | (0.04 | ) | $ | 0.09 |   |
|                                                       |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Weighted Average Number of  Common Shares Outstanding:** | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Basic**                                                  |       | 34,284,646                                                    |        | 32,511,251 |   | 29,830,447 |   | 25,990,868 |   | 20,890,841 |   |
| **Diluted**                                                |       | 34,284,646                                                    |        | 32,511,251 |   | 29,830,447 |   | 25,990,868 |   | 24,001,888 |   |
|                                                       |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Production Data:**                                       | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural gas (Mcf)**                                      |       | 1,278,434                                                     |        | 1,275,445 |   | 2,005,359 |   | 2,229,059 |   | 1,991,105 |   |
| **Natural gas (Mcf/d)**                                    |       | 3,503                                                         |        | 3,494 |   | 5,494 |   | 6,107 |   | 5,455 |   |
|                                                       |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Production Data reduced by net  profits interests:**     |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Natural gas (Mcf)**                                      |       | 1,118,630                                                     |        | 1,116,014 |   | 1,754,689 |   | 1,950,427 |   | 1,742,217 |   |
| **Natural gas (Mcf/d)**                                    |       | 3,065                                                         |        | 3,058 |   | 4,807 |   | 5,344 |   | 4,773 |   |
|                                                       |       |                                                          |        |   |   |   |   |   |   |   |   |
| **Average Sales Prices:**                                  | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural gas (per Mcf)**                                  |       | $                                                             | 3.19        |   | $ | 4.82 |   | $ | 3.44 |   | $ | 3.01 |   | $ | 4.01 |   |

 
| ** **                                | ** ** | **For the Years Ended December 31,** | ** **  |
|-------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                | ** ** | **2009**                                                      | ** **  | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Balance Sheet Information:**            | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current assets                            |       | $                                                             | 3,044,731   |   | $ | 1,023,090 |   | $ | 5,723,680 |   | $ | 2,366,081 |   | $ | 1,718,893 |   |
| Total assets                              |       | 34,004,213                                                    |        | 54,076,005 |   | 44,116,606 |   | 39,061,478 |   | 25,014,826 |   |
| Current liabilities                       |       | 4,218,956                                                     |        | 3,174,742 |   | 2,361,827 |   | 3,604,342 |   | 3,574,466 |   |
| Current portion of Long-term liabilities  |       | 1,549,829                                                     |        | 600,000 |   | — |   | — |   | — |   |
| Long-term liabilities                     |       | 6,051,654                                                     |        | 7,078,548 |   | 53,726 |   | 48,842 |   | 26,641 |   |
| Redeemable Series AA Preferred Stock |       | —                                                        |        | — |   | — |   | 5,924,068 |   | 5,924,068 |   |
| Series B Preferred Stock             |       | 5,448,602                                                     |        | — |   | — |   | — |   | — |   |
| Accumulated Deficit                       |       | $                                                             | (38,172,919 | ) | $ | (12,185,614 | ) | $ | (12,010,789 | ) | $ | (10,393,985 | ) | $ | (9,382,179 | ) |

 

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Notes to Selected FinancialData:

 

(a)          For each of the yearspresented the Company has not paid dividends to any of its common stockholders.

 

(b)         See Item 2. “Properties—Texas- Madisonville Midstream Gas Treatment Plant and Gathering Facilities”for discussion of the acquisition of the MGP Gas Treatment Plant.

 

**Item 7.*Management’s Discussion and Analysis ofFinancial Condition and Results of Operations***

 

*The following discussion and analysis should beread in conjunction with accompanying financial statements and related notesincluded elsewhere in this report. It contains forward looking statements thatreflect our future plans, estimates, beliefs and expected performance. Theforward looking statements are dependent upon events, risks and uncertaintiesthat may be outside our control. Our actual results could differ materiallyfrom those discussed in these forward looking statements.*

 

*Factors that could cause or contribute to suchdifferences include, but are not limited to, market prices for natural gas andoil, economic and competitive conditions, regulatory changes, estimates ofproved reserves, potential failure to achieve production from developmentdrilling projects, capital expenditures and other uncertainties, as well asthose factors discussed below and elsewhere in this report, particularly in “RiskFactors” and “Cautionary Notes Regarding Forward Looking Statements”, all ofwhich are difficult to predict and which expressly qualify all subsequent oraland written forward-looking statements attributable to us or persons acting onour behalf. In light of these risks, uncertainties and assumptions, the forwardlooking events discussed may not occur. We do not have any intention orobligation to update forward-looking statements included in this report afterthe date of this report, except as required by law.*

 

**Overview**

 

Weare an oil and gas company in the business of exploring and developing oil andnatural gas reserves on a worldwide basis. Since inception, we have conductedleasehold acquisition, exploration and drilling activities on our NorthAmerican, Australian and Indonesian prospects. These projects currentlyencompass approximately 377,506 gross (163,590 net) acres, consisting ofmineral leases, production sharing contracts and exploration permits that giveus the right to explore for, develop and produce oil and natural gas. Most ofthese properties are in the exploration, appraisal or development drillingphase and have not begun to produce revenue from the sale of oil and naturalgas. Excluding minor interest and dividend income, our only significant cashinflows until 2003 were the recovery of capital invested in projects throughsale or other divestiture of interests in oil and gas prospects to industrypartners.

 

Since2003, substantially all of our revenue has been generated from natural gassales derived from the Magness #1, the Fannin #1, and the Mitchell #1 wells inthe Madisonville Field in East Texas under spot gas purchase contracts atmarket prices. Natural gas sales from the Madisonville Field are expected toaccount for substantially all of our revenues for 2010. We expect the majorityof our capital expenditures in 2010 will be for the Madisonville Project.

 
| ** **                                        | ** ** | **For The Years Ended December 31,** | ** **  |
|---------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                        | ** ** | **2009**                                                      | ** **  | **2008** | ** ** |
| **Consolidated Statement of  Operations:**        | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| **Revenues**                                      |       | $                                                             | 4,077,355   |   | $ | 6,152,542 |   |
| **Plant operating expense**                       |       | 4,832,548                                                     |        | — |   |
| **Lease operating expense**                       |       | 606,266                                                       |        | 1,484,267 |   |
| **General and administrative**                    |       | 2,767,386                                                     |        | 2,717,121 |   |
| **Net profits expense**                           |       | —                                                        |        | 579,941 |   |
| **Impairment expense**                            |       | 20,843,305                                                    |        | 69,856 |   |
| **Depreciation and depletion  expense**           |       | 1,595,597                                                     |        | 1,553,418 |   |
| **Loss from operations**                          |       | (26,567,746                                                   | )           | (252,061 | ) |
| **Net loss**                                      |       | (25,808,260                                                   | )           | (174,825 | ) |
| **Net loss attributable to common  shareholders** |       | $                                                             | (25,987,305 | ) | $ | (174,825 | ) |

 

**Revenue and Operating Trends in2009**

 

Asdiscussed in the “Properties — Texas — Madisonville Project” section of thisannual report, in order to produce the gas reserves from the Rodessa Formation,we developed an onsite plan to treat and remove impurities from theMadisonville Project natural gas in order to meet pipeline-qualityspecifications. In 2003, a third party completed the construction andinstallation of a 

 

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naturalgas treatment plant with a designed capacity of 18 million cubic feet of gasper day (“MMcf/d”) and associated pipeline and gathering facilities.

 

In2005 we secured a commitment from MGP to install and make operationaladditional treating facilities capable of treating 50 MMcf/d, which combinedwith the capacity of the current in-service treating facilities will representa total designed treating capacity of 68 MMcf/d for the Madisonville treatmentplant.   In early November 2007, MGPbegan testing the additional treatment facilities by accepting 20 MMcf/d at theinlet.   Subsequently in December 2007, MGP suspended the operations of theadditional treatment facilities inorder to make modifications to more effectively deal with the presence ofdiamondoids in the gas stream produced from the Rodessa Formation.

 

During2008, MGP analyzed various options forremoving the diamondoids; however, they did not complete the necessary plant system modifications.  On December 31, 2008, wepurchased the gas treatment plant and related gathering pipeline from MGP inexchange for assumption of secured debt, payment of certain outstandingpayables 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, indirectsubsidiary, Madisonville Midstream LLC (“MM”). We expect to completeinstallation of the system modifications required in the new plant in2010.  In the meantime, the existing, inservice portion of the plant continues to operate with a design capacity of upto approximately 18 MMcf/d of inlet gas.

 

Whilethere can be no assurance, with acquisition of the gas treatment plant, ourgoal is to make the necessary upgrades to the plant and increase the productionrates from our wells which may result in higher net production and increasedrevenue during 2010 as compared to 2009 and prior periods. To accomplish theplant upgrades, we will need to raise capital in 2010. Due to the unsettledstate of the capital markets, funds may not be available, or may not beavailable on favorable terms.

 

Priorto December 31, 2008, the price received for natural gas was determinedpursuant to certain agreements which were in effect with MGP.  Pursuant to these agreements, MGP purchasedthe Company’s untreated natural gas in the Madisonville Field for each of theproducing wells and charged the Company a fixed fee to gather, treat, transportand market its natural gas, provided however, that such fees would not exceedthe value of the natural gas.  Hydrogensulphide, carbon dioxide and nitrogen combined comprise about 28% of the gascontent. The untreated natural gas is delivered to the Gas Treatment Plantwhere substantially all the natural gas impurities are removed before deliveryto the sales pipeline. As a result of the costs to gather, treat, transport andmarket the natural gas, we received a net price that is substantially lowerthan we would otherwise receive if the gas did not contain the 28% ofimpurities.

 

Dueto weak natural gas prices prevailing for most of 2009, the costs to gather,treat, transport and market the natural gas exceeded the value of the naturalgas produced during most of the year.

 

**Industry Overview for the year ended December 31, 2009**

 

During 2009 weexperienced significantly deteriorating natural gas prices throughout of theyear, with a rebound in prices by the end of the year. The Houston Ship Channelprice, the index price prevailing in the locale of our Madisonville Project inMadison County, Texas, as quoted in Gas Daily as of December 31, 2009 wasper $5.72 Mcf versus $5.25 per Mcf as of December 31, 2008. Natural gasprices were volatile during 2009 due to over-supply and recessionary concernsearlier in the year and later in the year due to seasonal weather driven demandspurred by unusually cold winter temperatures in many parts of the US.

 

**Company Overview in 2009**

 

Ournet loss after taxes for the year ended December 31, 2009 was $25,808,260.From our inception, through mid-2003, we only received nominal revenues fromour oil and natural gas activities, while incurring substantial acquisition andexploration costs and overhead expenses which have resulted in an accumulateddeficit through December 31, 2009 of $38,172,919. Commencing in May 2003,we placed our Madisonville Project into production. Substantially all of ourrevenues for the year ended December 31, 2009 were derived from ourMadisonville Project, from three producing wells, the UMC Ruby Magness #1 well(the “Magness Well”), the Angela Farris Fannin #1 well (the “Fannin Well”), andthe Mitchell #1 well (the “Mitchell Well”).

 

**Comparison of Results of Operations for the year ended December 31,2009 and 2008**

 

During the twelve monthsended December 31, 2009, we had gross natural gas revenues from thetreatment plant of $4,006,939 and revenues from treating third party gas in thePlant of $70,416. During this period, our gross production from our wells was1,278,434 Mcf (production net of royalties of 922,393 Mcf) and our averagenatural gas price realized was $3.19 per 

 

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Mcf.  During thetwelve months ended December 31, 2008, we had oil and natural gas revenuesof $6,152,542, and our net production was 1,275,445 Mcf of natural gas at anaverage price of $4.82 per Mcf. Revenues decreased in the twelve months ended December 30,2009 as compared to the prior year period due to lower production volumes andlower natural gas prices. The 27.68% lower net production volumes for thetwelve months ended December 31, 2009 as compared to the same period of2008 was due to natural declines in the wells. Average natural gas prices wereapproximately 34% lower for the twelve months ended December 31, 2009versus the same period in 2008.The average natural gas price of $4.82 per Mcffor the 2008 period was net of treating, gathering, marketing andtransportation fees (collectively the “Fees”) in accordance with our contractswith MGP and Gateway ADAC Pipeline, LLC.  The average natural gas price of$3.19 per Mcf for the 2009 period was not “net” of the aforementioned Feessince the contracts that were in place with MGP were terminated as of December 31,2008.

 

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

 

Our results of operationsfor the twelve months ended December 31, 2009 include the operatingresults of the Plant, but our results of operations for the twelve months endedDecember 31, 2008 do not include the operating results of the natural gastreatment plant because such acquisition closed on December 31, 2008. Thefollowing condensed pro forma information gives effect to the acquisition as ifit had occurred on January 1, 2008. The pro forma information has beenincluded in the notes to the financial statements included elsewhere in thisdocument as required by generally accepted accounting principles and isprovided for comparison purposes only. The pro forma financial information isnot necessarily indicative of the financial results that would have occurredhad the acquisition been effective on the dates indicated and should not beviewed as indicative of operations in the future.

 
| ** **                       | ** ** | **Twelve  Months  Ended********December 31,  2008** | ** ** |
|----------------------------------|------------|----------------------------------------------------------|------------|
| Operating  revenues              |       | $                                                        | 15,066,915 |   |
| Total  operating expenses        |       | $                                                        | 15,954,201 |   |
| Loss  applicable to common stock |       | $                                                        | (1,239,749 | ) |
| Net  loss per share              |       | $                                                        | (0.04      | ) |

 

During the twelve monthsended December 31, 2009, we incurred plant operating expenses of$4,832,548. Our average plant operating cost for the 2009 period was $3.71 perMcf on net throughput of 1,302,618 Mcf. We purchased the gas treatment planteffective on December 31, 2008, thus there was no plant operating expensefor the comparable 2008 period.

 

During the twelve monthsended December 31, 2009, we incurred lease operating expense of $606,266.Our average lifting cost for the 2009 period was $0.66 per Mcf. During thetwelve months ended December 31, 2008, we incurred lease operating expenseof $1,484,267. Our average lifting cost for the 2008 period was $1.16 per Mcf.The average lifting cost per Mcf in 2009 was lower due to cost cutting effortsand a reduction of ad valorem property taxes applicable to the wells.

 

During the twelve monthsended December 31, 2009, we incurred no net profits interest expense becausewe did not generate a net operating profit from our Magness, Fannin, andMitchell wells. During the twelve months ended December 31, 2008, weincurred net profits interest expense of $579,941 associated with the Magness,the Fannin, and the Mitchell wells. The net profit interest is 12.5% of the netoperating profit from our Magness, Fannin, and Mitchell wells.

 

General andadministrative (“**G&A**”)expenses for the twelve months ended December 31, 2009 were $2,767,385compared to $2,717,121 for the twelve months ended December 31, 2008. Thisrepresents a $50,265 or 1.8% increase over the prior year period. The higherG&A expense incurred in 2009 was due primarily to new options issued during2009 and 2008.

 

For the year ended December 31,2009, impairment expense was $20,843,305 versus $69,856 for the same period of2008.  The 2009 impairment write-downswere due to (i) dry holes drilled on our Canadian oil and gas properties,and (ii) writeoff remaining costs related to the South Bengara due toproject cancellation (iii) $19.8 million impairment in the Madisonvilleproject in U.S., which resulted in ceiling test write downs.

 

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For year-end 2009, newSEC rules were implemented requiring that reserve calculations be based onthe un-weighted average first-day-of-the-month prices for the prior twelvemonths, as contrasted with the previous method which utilized period endprices. The prices under the new rules were $3.11per Mcf for natural gas adjusted for energy content, quality and basisdifferentials. Under the new rules, this resulted in a ceiling test write-downof $19,798,390 associated with the US full cost pool.  Had we used theprice prevailing on December 31, 2009 of $5.45 per Mcf for natural gas, there would have been noyear-end write-down. Under full cost accounting, a ceiling test is performed toensure that unamortized capitalized costs in each cost center (country) do notexceed their fair value.  Impairment is recognized when the carrying valueis greater than the discounted future cash flows.  In the event ofimpairment, the amount by which the carrying value exceeds the estimated fairvalue of the long-lived asset is charged to earnings. The present value ofestimated future net revenues is computed by applying current oil and gasprices to estimated future production of proved oil and gas reserves, lessestimated future expenditures to be incurred in developing and producing theproved reserves assuming the continuation of existing economic conditions.

 

Depreciation anddepletion expense for the twelve months ended December 31, 2009 was$1,595,597 as compared to $1,553,418 in the same period of 2008, which amountsprimarily represent depletion of the oil and gas properties for the twelvemonths ended December 31, 2009 and 2008, respectively. The 2.7% increasewas due to gas processing plant depreciation in 2009 which offset decreaseddepletion expense resulting from lower net production in the twelve monthsperiod of 2009 as previously discussed.

 

Loss from operationstotaled $26,567,746 for the twelve months ended December 31, 2009 ascompared to loss from operations of $252,061 for the twelve months ended December 30,2008. The increase in the loss from operations was due primarily to higherimpairment, depreciation and depletion expenses.

 

Other income for thetwelve months ended December 31, 2009 and 2008 consisted of interestincome in the amount of $6,404 and $91,867, respectively, resulting from loweraverage cash balances due to our purchase of the Plant on December 31, 2008.

 

During the twelve monthsended December 31, 2009 and 2008, we incurred interest expense of $735,596and $1,846, respectively. We incurred new debt in late December 2008 andsubsequently during 2009 associated with the plant acquisition and workingcapital requirements.

 

Net loss before taxes forthe twelve months ended December 31, 2009 was $25,809,251 as compared to$162,040 for the twelve months ended December 31, 2008. The increase innet loss during the twelve months ended December 31, 2009 was primarilydue to lower gas prices, lower production volume, higher operating expenses,ceiling test write-off in the US pool due to new SEC requirment.

 

Income tax benefit forthe twelve months ended December 31, 2009 was $991 compared to income taxexpense of $12,785 in the same period of 2008. The increased income tax benefitwas due to refund from 2008 Texas franchise tax overpayment.

 

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**Recent Developments**

 

During the twelvemonths ended December 31, 2009 we borrowed $850,000 pursuant to five separatethree year loans which were convertible into a newly designated class ofpreferred stock of GeoPetro, Series B Convertible Preferred Stock (the “Series BPreferred Stock”) and $1,897,000 pursuant to eleven separate loans.  The$850,000 in loans converted into Series B Preferred Stock on April 30,2009, along with an additional $1,000,000 which was advanced during April fora total subscription in the private placement of 2,466,670 shares for apurchase price of $0.75 per share and an aggregate investment of $1,850,000.The holders of Series B Stock are entitled to receive an annual dividendat the rate of $0.06 per share and are entitled to such number of votes pershare as equals the number of common shares into which each share of Series BStock is convertible. Each share of Series B Stock is convertible, at theoption of the holder, into fully paid and non-assessable common shares on aone-for-one basis, subject to certain adjustments. The Series B Stock willautomatically convert into common shares on a one-for-one share basis effectivethe first trading day after the reported high selling price for the Company’scommon shares on any international, national or regional securities exchange orinter-dealer quotation system including but not limited to, NASDAQ, the PinkSheets or the Over-the-Counter Bulletin Board, is at least $1.50 per share forany ten consecutive trading days. If an automatic conversion occurs within oneyear after the Series B Stock was purchased from the Company, a holderwill receive, on the one-year anniversary date of his, her or its purchase, acash dividend equivalent to a full year of dividends less any dividends paidbefore such conversion.

 

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

 

On September 10,2009, the Company’s subsidiary, Madisonville Midstream, LLC reached anagreement to sell certain idle equipment related to the plant to Gas Processors, Inc.for a sale price of $2.5 million. A nonrefundable deposit of $250,000 wasreceived on September 10, 2009. The remaining balance of $2.25 million wasreceived on September 30, 2009.  Ofthe $2,500,000 sales proceeds, $1,125,000 was applied toward a reduction of theprincipal balance on the Bank of Oklahoma term loan.

 

Between August 3,2009 and October 13, 2009, we entered into preferred stock purchaseagreements for the private placement of 5,049,333 shares of Series BPreferred Stock for a purchase price of $0.75 per share and an aggregateinvestment, before offering costs, of $3,787,000.  Significant rights and preferences attachingto the Series B Preferred Stock are described above.

 

Between August 3,2009 and October 23, 2009, we issued promissory notes for total grossproceeds of $1,000,000 (net proceeds of $960,000).  We issued to the note holders warrantsexercisable to purchase 50,000 shares of our common stock.  Each warrant is exercisable for a three yearterm to purchase one share of our common stock at a price of $1.00 pershare.  The issuance dates, maturitydates and interest rates for these promissory notes are as follows:

 
| **DATE OF** | ** ** | **MATURITY** | ** ** | **INTEREST** | ** ** | **PRINCIPAL** | ** ** |
|-------------|------------|--------------|------------|--------------|------------|---------------|------------|
| **NOTE**    | ** ** | **DATE**     | ** ** | **RATE**     | ** ** | **AMOUNT**    | ** ** |
|        |       |         |       |         |       |          |       |
| 08/13/09    |       | 08/30/10     |       | 10           | %          | $             | 100,000    |   |
| 08/21/09    |       | 08/30/10     |       | 10           | %          | 100,000       |       |
| 09/01/09    |       | 08/30/10     |       | 10           | %          | 30,000        |       |
| 09/16/09    |       | 08/30/10     |       | 10           | %          | 50,000        |       |
| 10/23/09    |       | 10/31/10     |       | 10           | %          | 720,000       |       |
|        |       |         |       |         |       | $             | 1,000,000  |   |

 

On September 11,2009, our subsidiary, Redwood Energy Production, L.P. filed an OriginalPetition for Declaratory Judgment against Devon Energy Production Company (“Devon”)regarding certain overriding royalty interests and related revenue amountsclaimed by Devon.  We have previouslyaccrued all amounts owed pursuant to these overriding royalty interests asroyalty owners payable.  In the opinionof management based on consultation with legal counsel, these proceedings arenot expected to have a material adverse effect on our financial condition orresults of operations.

 

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On February 15,2010, we entered into a new lease for our principal executive office to be locatedat 150 California Street, Suite 600, San Francisco, CA 94111.  The terms of the lease provide for aneighty-four (84) month term. Minimum annual rentals due under this agreementare as follows:

 
| 2010   |   | 95,223  | *         |
|--------|--------|---------|-----------|
| 2011   |   | 145,635 |      |
| 2012   |   | 149,836 |      |
| 2013   |   | 154,037 |      |
| 2014   |   | 158,238 |      |
| 2015   |   | 162,439 |      |
| 2016   |   | 166,640 |      |
| 2017   |   | 56,013  |      |
|   |   |    |      |
| Total  |   | $       | 1,088,061 |   |
|        |        |         |           |  |

 

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

 

On February 26,2010, we sold our entire working interest in our Alaskan leases to Linc Energy(Alaska) Inc. (“Linc”).  Linc is awholly-owned subsidiary of Linc Energy Ltd., an Australian-based companypublicly traded on the Australian Stock Exchange.

 

Linc will acquire all ofthe Alaskan Leases for the following consideration:

 

a.                                       A cash payment of $1.0 million will bedeposited by Linc in an escrow account, to be released to us upon approval ofthe assignments of the Alaskan leases to Linc.

 

b.                                      In addition, we will receive a $4.0million payment from the first 75% of 8/8ths of the proceeds from any oil andgas production from the Alaskan leases.

 

c.                                       After we have received the $4.0 millionpayment specified in paragraph (b) above, we will thereafter receive anoverriding royalty interest of 10% of 8/8ths in and to the Alaskan leasesissued by the State of Alaska and the Alaska Mental Health Trust (whichcomprise over 99% of the Alaskan Leases), and an overriding royalty interest of7% of 8/8ths in and to the Alaskan Leases issued by Cook Inlet Region, Inc.on conventional oil and gas production and coal bed methane production.

 

d.                                      Linc has agreed to pay all of the costsof maintaining the Alaskan leases at least through the end of the primary termsthereof.

 

e.                                       Following the lessors’ approval of theassignments of the Alaskan leases into Linc, Linc will diligently commence andprosecute the drilling of the Frontier Spirit #1 exploration well to evaluate aconventional oil and gas prospect identified and developed by us.

 

**Liquidityand Capital Resources**

 

Our cash balance at December 31, 2009 was$2,429,891 compared to a cash balance of $770,779 at December 31, 2008.The change in our cash balance is summarized as follows:

 
| Cash balance at December 31, 2008       |   | $          | 770,779   |   |
|----------------------------------------------|--------|------------|-----------|--------|
| Sources of cash:                             |   |       |      |
| Cash provided by disposition of equipment    |   | 2,500,000  |      |
| Cash provided by financing activities        |   | 5,280,019  |      |
|                                         |   |       |      |
| Total sources of cash including cash on hand |   | 8,550,798  |      |
|                                         |   |       |      |
| Uses of cash:                                |   |       |      |
| Cash used by operating actives               |   | (4,773,997 | )         |
| Cash used in investing activities:           |   |       |      |
| Oil and natural gas property expenditures    |   | (758,006   | )         |
| Gas processing plant                         |   | (588,904   | )         |
| Total uses of cash                           |   | (6,120,907 | )         |
|                                         |   |       |      |
| Cash balance at December 31, 2009       |   | $          | 2,429,891 |   |

 

We had a working capital deficit of $1,174,225 and$2,151,652 at December 31, 2009 and December 31, 2008, respectively.Our working capital increased during year ended December 31, 2009 dueprimarily to funds raised from private placement from Series B preferredstock.

 

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We have historically financed our businessactivities through December 31, 2009 principally through issuances ofpreferred stocks, issuances of common shares, promissory notes, common sharepurchase warrants in private placements and an initial public offering. Thesefinancings are summarized as follows:

 
| ** **                                                      | ** ** | **Years Ended**            | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                      | ** ** | **December 31, 2009** | ** ** | **December 31, 2008** | ** ** |
|                                                            |       |                            |       |   |   |
| Proceeds from sale of common shares and warrant  exercises, net |       | $                               | —     |   | $ | 375,000 |   |
| Proceeds from sale of Preferred Series B, net              |       | 5,448,602                       |       |   |   |
| Payment on preferred dividends                                  |       | (68,583                         | )          | — |   |
| Repayments of promissory notes                                  |       | (1,825,000                      | )          | — |   |
| Proceeds from promissory notes                                  |       | 1,897,000                       |       | 1,050,000 |   |
| Payment of loan fee                                             |       | (40,000                         | )          | (6,000 | ) |
| Repayment of related party note                                 |       | (132,000                        | )          | — |   |
| Net option exercise                                             |       | —                          |       | — |   |
|                                                            |       |                            |       |   |   |
| Net cash provided by financing activities                       |       | $                               | 5,280,019  |   | $ | 1,419,000 |   |

 

The net proceeds of our equity and note financings have been primarilyinvested in oil and natural gas properties totaling $758,006, and $5,569,417 forthe years ended December 31, 2009 and 2008, respectively.

 

On December 31, 2008, we acquired the gas treatment plant from MGPfor $10,707,982 in combination of cash, debt and common stock. The Companyassumed $7,697,847 of Madisonville Gas Processing LP’s (“MGP”) bank debtrelated to the Company’s acquisition of the Madisonville Gas Treatment Plant(the “Plant”) via a (i) $1 million cash payment applied directly towardsdebt principal reduction, and (ii) a refinancing by GeoPetro of the$6,697,847 remaining balance in the form of a 3 year Amended and Restated TermLoan Agreement with the lender, Bank Oklahoma (“BOK”).  The terms of the three year loan provide forminimum quarterly principal payments of $150,000 and interest payable quarterlyin arrears at prime plus 4% or,  Liborplus 5.5%, at the option of the Company. Additional principal will be payable upon GeoPetro meeting certain netoperating cash flow thresholds during the three year term of the loan.  The loan is secured by a first lien on theMadisonville Midstream Plant and all of the Company’s proved natural gasreserves located at the Madisonville Project. In addition, GeoPetro has agreed to a pay, at the time the loan isrepaid in full, a loan origination fee of (i) $60,000 for any periodduring the three year term during which the loan principal remainsoutstanding.  There is no prepaymentpenalty.  The Amended and Restated TermLoan Agreement, as further amended, contains customary affirmative and negativecovenants including restrictions on incurring additional debt and requiringthat the Company maintain a minimum tangible net worth of at least $18,000,000.

 

On December 31,2008, we issued 1.5 million shares of common stock pursuant to an assetpurchase agreement related to the acquisition of the Madisonville Midstream GasTreatment Plant and related gas gathering pipelines and related facilities fromMadisonville Gas Processing, LP.

 

During December 2008,GeoPetro raised $1,050,000 by issuing promissory notes to accredited investors,each having the following terms:  (i) 8%annual simple interest payable quarterly in arrears, (ii) principal andany unpaid outstanding interest shall be payable at the end of three years, (iii) subordinatedto the BOK loan and (iv) be unsecured. Each note purchaser also received warrants to purchase one share ofGeoPetro common stock for $1.00 per share, exercisable for three years.  One warrant was received for each $10 in faceamount of notes purchased (a total of 105,000 warrants exercisable to purchase105,000 shares of common stock).  GeoPetro also reissued 15,000 warrants at$1.00 per share to be exercised for three years.

 

We raised $850,000 inconvertible notes that were converted into our Series B Preferred Stock onApril 30, 2009, an additional $2,181,710 in our Series B PreferredStock, and issued $1,177,000 in promissory notes. On September 30, 2009,we 

 

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completed the sale of certain idle equipment from ournatural gas processing plant for total cash proceeds of $2.5 million. During October 2009, we issued a promissory note for total gross proceedsof $720,000 (net proceeds of $701,383) and issued an additional 3,401,996shares of Series B Preferred Stock for total gross proceeds of $2,551,500.

 

Ourcurrent cash and cash equivalents and anticipated cash flow from operations maynot be sufficient to meet our working capital, capital expenditures and growthstrategy requirements for the foreseeable future. See “Outlook for 2010” for adescription of our expected capital expenditures for 2010. If we are unable togenerate revenues necessary to finance our operations over the long-term, wemay have to seek additional capital through the sale of our equity orborrowing. As noted in “Recent Developments,” we periodically borrow fundspursuant to promissory notes to finance our activities.

 

Asdiscussed 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 tofund our anticipated capital expenditures through the end of 2010 and to followthrough with plans for continued investments in oil and gas properties. Oursuccess, in part, depends on our ability to generate additional financing andfarmout certain of our projects.  Additionally,as a result of the 2009 economic downturn, the Company may have difficultyraising sufficient funds to meet our projected funding requirements.  See Item 1A.- “Risk Factors — Risks Relatedto Our Business”.

 

Since our inception, wehave participated as a working interest owner in the acquisition of undevelopedleases, seismic options, lease options and foreign concessions and haveparticipated in seismic surveys and the drilling of test wells on ourundeveloped properties. Further leasehold acquisitions, drilling and seismicoperations are planned for 2010 and future periods. In addition, exploratoryand development drilling is scheduled during 2010 and future periods on ourundeveloped properties. It is anticipated that these exploration activitiestogether with others that may be entered into will impose financial requirementswhich will exceed our existing working capital. We may raise additional equityand/or debt capital, and we may farm-out certain of our projects to finance ourcontinued participation in planned activities. However, if additional financingis not available, we may be compelled to reduce the scope of our businessactivities. If we are unable to fund planned expenditures, it may be necessaryto:

 

1.                  farmout our interest in proposed wells;

 

2.                  sell a portion of our interest in prospects and usethe sale proceeds to fund our participation for a lesser interest;

 

3.                  reduce general and administrative expenses;

 

4.                  forfeit our interest in wells that are proposed to bedrilled .

 

**Outlook for 2010 Capital**

 

Dependingon capital availability, we are forecasting capital spending of up toapproximately $3,528,000 during the year 2010, allocated as follows:

 

1.                       MadisonvilleProject, Madison County, Texas — Approximately $3,028,000 may be expended inthe Madisonville Field area as follows: $1,433,000 million for capitalmaintenance and repair on new gas treatment plant; $945,000 toward the fracturestimulation and hook up costs of the Wilson Well; and $650,000 for the Mitchellwell workover.

 

2.                       California—Approximately $500,000 to be utilized for land and permitting costs.

 

Wemay, in our discretion, decide to allocate resources towards other projects inaddition to or in lieu of, those listed above should other opportunities ariseand as circumstances warrant. We currently do not have sufficient workingcapital to fund all of the capital expenditures listed above. We may, in our discretion, fund theforegoing planned expenditures from operating cash flows, asset sales,potential debt and equity issuances and/or a combination of all four. TheMadisonville Project forecasted capital expenditures will play an importantpart in the Company achieving our 2010 cash flow projections. See “Liquidityand Capital Resources.”

 

We expect commodity prices to be volatile,reflecting the current supply and demand fundamentals for North Americannatural gas and world crude oil. Political and economic events around theworld, which are difficult to predict, will continue to influence both oil andgas prices. Significant price changes for oil and gas often lead to changes inthe levels of drilling activity which in turn lead to changes in costs toexplore, develop and acquire oil and gas reserves. Significant change in costscould affect the returns on our capital expenditures. Higher crude prices couldalso help keep natural gas prices high by keeping alternative fuels, such asheating oil and residual fuel, expensive.

 

**IncomeTaxes**

 

As of December 31,2009, GeoPetro had net operating loss (NOL) carryforwards of approximately $31,991,000for federal income tax purposes which begin to expire in 2017.  If the Company were to experience a change inownership under Section 382, the Company may be limited in its ability tofully utilize its net operating losses.

 

However, in accordancewith ASC 718 (formerly SFAS 123(R)), a deferred tax asset has not beenrecognized for the portion of the net operating loss carryforwards that isattributable to excess tax deductions associated with the exercise of stockoptions which do not reduce income taxes payable. Accordingly, approximately$3,536,000 of GeoPetro’s federal NOL has not been benefited for financialstatement purposes as it relates to excess tax deductions that have not reducedincome taxes payable. The benefit of these excess tax deductions will not berecognized for financial statement purposes until the related deductions reduceincome taxes payable.

 

The Company also hasapproximately $10,258,000 of California net operating losses and approximately$551,000 of Alaska net operating losses which begin to expire in 2010 and 2026,respectively. In accordance with ASC 718, a portion of the state NOLs hassimilarly not been benefited for financial statement purposes as it relates toexcess tax deductions which have not resulted in the reduction of income taxespayable. The benefit of such excess tax deductions will not be recognized forfinancial statement purposes until the related deductions reduce state incometaxes payable.

 

In addition, the Companyhas approximately $334,000 of carryforward credits in Texas, a portion of whichmay be utilized each year against Texas Margin Tax liability through 2027.

 

A significant change in our ownership may limit our ability to usethese NOL carryforwards. ASC 740, Accounting for Income Taxes (formerly Statement of FinancialAccounting Standards No. 109), requires that the taxbenefit of such net operating loss be recorded as an asset. At December 31,2009, we had net deferred tax assets of approximately $12,836,000 related tothe NOL and 

 

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othertemporary differences. We have recorded a full valuation allowance of $12,836,000at December 31, 2009 due to uncertainties surrounding the realizability ofthe deferred tax asset.

 

**Off Balance Sheet Arrangements**

 

From time to time, we mayenter into off-balance sheet arrangements and transactions that can give riseto off-balance sheet obligations. As of December 31, 2009, our off-balancesheet arrangements and transactions include operating lease agreements and gastransportation commitments. We do not believe that these arrangements arereasonably likely to materially affect our liquidity or availability of, orrequirements for, capital resources.

 

**Financia****l Instruments**

 

Wecurrently have no natural gas price financial instruments or hedges in place.Similarly, we have no financial derivatives. Our natural gas marketingcontracts use “spot” market prices. Given the uncertainty of the timing andvolumes of our natural gas production this year, we do not currently plan toenter into any long term fixed-price natural gas contracts, swap or hedgepositions, other gas financial instruments or financial derivatives in 2009.

 

**Impact of Inflation &Changing Prices**

 

Asthe following table illustrates, average sales prices of natural gas havechanged in the past three years. This has led to changes in revenues andearnings from operations:

 
| ** **                   | ** ** | **For the Year Ended December 31,** | ** **  |
|------------------------------|------------|--------------------------------------------------------------|-------------|
| ** **                   | ** ** | **2009 (1)**                                                 | ** **  | **2008 (2)** | ** ** |
| Average Sales Prices per Mcf |       | $                                                            | 3.19        |   | $ | 4.82 |   |
| Net Production Volume Mcf    |       | 1,278,434                                                    |        | 1,275,445 |   |
| Revenues                     |       | $                                                            | 4,077,355   |   | $ | 6,152,542 |   |
| Loss from Operation          |       | $                                                            | (26,567,746 | ) | $ | (252,061 | ) |

 

----

(1) Includes$20,843,305 impairment expense

 

(2) Includes $69,856impairment expense

 

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We are highly dependent upon natural gas pricing. Amaterial decrease in current and projected natural gas prices could impair ourability to raise additional capital on acceptable terms. Likewise, a materialdecrease in current and projected natural gas prices could also impact ourrevenues and cash flows. This could impact our ability to fund futureactivities.

 

Changing prices have had a significant impact oncosts of drilling and completing wells, particularly in the Madisonville Fieldarea where we are currently the most active. The estimated cost of drilling andcompleting a Rodessa formation well at approximately 12,300 feet of depth hasincreased from $3.0 million in 2001 to $4.2 million in 2009 due to higher costsassociated with tubular goods, well equipment, and day rates for drillingcontracts, among other factors. These higher costs have impacted and willcontinue to impact our income from operations in the form of higher depletionexpense.

 

**Critical Accounting Estimates**

 

Our consolidated financial statements have beenprepared by management in accordance with U.S. GAAP.

 

The preparation of consolidated financial statementsin conformity with U.S. GAAP requires management to make estimates andassumptions that affect the amounts reported in the consolidated financialstatements and accompanying notes. Actual results could differ from thoseestimates.

 

Management believes the most critical accountingpolicies that may have an impact on our financial results relate to theaccounting for oil and gas properties. Amortization, abandonment costs and fullcost ceiling limitation write-downs are all based on numerous estimates, manyof which are beyond management’s control. Reserves valuation is central to muchof the accounting for an oil and gas company as described below.

 

Significant accounting policies are contained inNote 2 to the consolidated financial statements. A summary ofunaudited supplementary oil and gas reserve information is contained inNote 12 to the consolidated financial statements.

 

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The following discusses the accounting estimatesthat are critical in determining the reported financial results:

 

*Oil and Gas Properties—*We**follow the full cost method of accountingfor oil and gas producing activities as prescribed by U.S. GAAP and,accordingly, capitalize all costs incurred in the acquisition, exploration, anddevelopment drilling of proved oil and gas properties, including the costs ofabandoned properties, dry holes, geophysical costs, and lease rentals. Allgeneral corporate costs are expensed as incurred. In general, sales or otherdispositions of oil and gas properties are accounted for as adjustments tocapitalized costs, with no gain or loss recorded. Amortization of proved oiland gas properties is computed on the units of production method based on allproved reserves on a country by country basis. Unproved oil and gas propertiesare assessed for impairment either individually or on an aggregate basis. Thenet capitalized costs of proved oil and gas properties (full cost ceilinglimitation) are not to exceed their related estimated future net revenuesdiscounted at 10%, and the lower of cost or estimated fair value of unprovedproperties, net of tax considerations.

 

*Reserves—*We**engage independent petroleum engineering consultants toevaluate our reserves. Reserves, future production profiles, and net revenuesare estimated by independent professional reservoir engineering firms. While weengage qualified reservoir engineering firms, their estimates are inherentlyuncertain, involve numerous assumptions that may not be realized, and predictasset values that may not be indicative of the true market value of the assetsevaluated. As a result of the inherent uncertainties and changing technical andeconomic assumptions, reserve estimates are subject to revisions that canmaterially impact our results.

 

*Stock Based Compensation—*The**Company has a stock- based compensationplan that allows employees to purchase common shares of the Company. Optionexercise prices approximate the market price for the common shares on the datethe options were issued. Options granted under the plan are generally fullyexercisable within five years and expire five to ten years after the grantdate. We measure and record stock-based awards to directors, employees andconsultants based on the grant-date fair value, determined using theBlack-Scholes option pricing model with assumptions for: risk free interestrates, expected dividend yield, expected life of the option, and the expectedvolatility.  We record the compensationexpense ratably over the requisite service period defined in the award.  The Company recorded $403,963 and $268,723 ofstock-based employee compensation for the twelve months ended December 31,2009 and 2008, respectively.

 

**Recently Issued Accounting Pronouncements**

 

Effective January 1,2009, we adopted ASC 260-10 (formerly Staff Position No. EITF 03-6-1),“Determining whether Instruments Granted in Share-Based Payment Transactionsare Participating Securities,” which provides that unvested share-based paymentawards that contain non-forfeitable rights to dividend or dividend equivalents(whether paid or unpaid) are participating securities, and, therefore need tobe included in the earnings allocation in computing earnings per share underthe two-class method. We adopted the provisions of this standard on January 1,2009, with no significant impact on our financial statements.

 

Effective January 1,2009, we adopted ASC 815-10 (formerly Statement of Financial AccountingStandards (“SFAS”) 161, *Disclosures aboutDerivative Instruments and Hedging Activities, an amendment of FASB Statement133*), which amends and expands the disclosure requirements with theintent to provide users of financial statements with an enhanced understandingof (i) how and why an entity uses derivative instruments; (ii) howderivative instruments and the related hedged items are accounted for; and (iii) howderivative instruments and related hedged items affect an entity’s financialposition, financial performance and cash flows. We adopted the provisions ofthis standard on January 1, 2009, with no significant impact on ourfinancial statements.

 

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In June 2009,the FASB issued ASC 105-10 (formerly SFAS No. 168), *Accounting Standards Codification**TM* *andthe Hierarchy of Generally Accepted Accounting Principles*. The FASBAccounting Standards CodificationTM (the “Codification”) has become the source ofauthoritative accounting principles recognized by the FASB to be applied bynongovernmental entities in the preparation of financial statements inaccordance with Generally Accepted Accounting Principles (“GAAP”). All existingaccounting standard documents are superseded by the Codification and anyaccounting literature not included in the Codification will not beauthoritative. Rules and interpretive releases of the SEC issued under theauthority of federal securities laws, however, will continue to be the sourceof authoritative generally accepted accounting principles for SEC registrants.Effective September 30, 2009, all references made to GAAP in ourconsolidated financial statements will include the new Codification numberingsystem along with original references. The Codification does not change oralter existing GAAP and, therefore, will not have an impact on our financialposition, results of operations or cash flows.

 

In December 2008,the SEC issued the final rule on the Modernization of Oil and GasReporting.  This SEC ruling revises its oil and gas reserves reportingrequirements effective for fiscal years ending on or after December 31,2009, with early adoption prohibited.  These revisions by the SEC areintended to provide investors with a more meaningful and comprehensiveunderstanding of oil and gas reserves.  These changes include:

 

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

·      Requiring certain additional disclosures around provedundeveloped reserves, internal controls used to ensure objectivity of theestimation process, and qualifications of those preparing and/or auditing thereserves.

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

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

·      We are now required to file the report of any thirdparty used to prepare or audit reserves our estimates.

 

In addition, in January 2010,FASB issued Account Standards Update (the “Update”) 2010-03, “Oil and GasReserve Estimation and Disclosures,” to provide consistency with the newreserve rules. The Update amends existing standards to align the reservescalculation and disclosure requirements under GAAP with the requirements in theSEC’s reserve rules. We adopted the new standards effective December 31,2009. The new standards are applied prospectively as a change in estimate.

 

Application of thenew reserve rules resulted in the use of a lower natural gas price at December 31,2009 than would have resulted under the previous rules. As a result, the newpricing methodology rules resulted in a lower net present value (PV-10) ofeconomically producible reserves. The new SEC rules require that reservecalculations be based on the un-weighted average first-day-of-the-month pricesfor the prior twelve months, as contrasted with the previous method whichutilized period end prices.  The prices under the new rules were$3.11 per Mcf for natural gas adjusted for energy content, quality and basisdifferentials. Under the new rules, this resulted in a ceiling test write-downof $19.8 million associated with the US full cost pool.  Had we used theprice prevailing on December 31, 2009 of $5.45 per Mcf for natural gas, noceiling test write-down would have been recorded.

 

Use of new 12-monthaverage pricing rules at December 31, 2009 also resulted in adecrease in economically producible proved reserves of approximately 1.03 Bcf.Use of the old year-end prices rules would have resulted in a decrease inproved reserves of approximately 0.53 Bcf at December 31,2009. Therefore, the total impact of the new price methodology rules resultedin negative reserves revisions of 0.5 Bcf.

 

Because we usequarter-end reserves and add back current production to calculate quarterlydepletion, depreciation and amortization expense, or DD&A, adoption ofthese new standards had an impact on DD&A for the fourth quarter of 2009.We estimate the impact of using the unweighted, arithmetic average on theclosing price on the first day of each month for the 12-month period prior to December 31,2009, as required by the new reserve rules, instead of year-end commodityprices, to be an increase in DD&A for the fourth quarter of 2009 ofapproximately $84,423.

 

On June 30, 2009, weadopted ASC 855-10 (formerly SFAS No. 165) *Subsequent Events*. ASC 855-10 establishes general standardsof accounting for and disclosure of events that occur after the balance sheetdate but before financial statements are issued or are available to be issued.Specifically, ASC 855-10 sets forth the period after the balance sheet dateduring which management of a reporting entity should evaluate events ortransactions that may occur for potential recognition or disclosure in thefinancial statements, the circumstances under which an entity should recognizeevents or transactions occurring after the balance sheet date in its financialstatements, and the disclosures that an entity should make about events ortransactions that occurred after the balance sheet date. The adoption of ASC855-10 had no impact on our results, cash flow or financial positionas management already followed a similar approach prior to the adoption ofthis standard.

 

In January 2010, theFinancial Accounting Standards Board issued amendments to Fair ValueMeasurements and Disclosures under ASC Topic 820. Effective for our 2010financial statements, this guidance provides for disclosures of significanttransfers in an out of Levels 1 and 2. In addition, the guidance clarifiesexisting disclosure requirements regarding inputs and valuation techniques aswell as the appropriate level of disaggregation for fair value measurements anddisclosures. Effective for our 2011 financial statements, this guidanceprovides for disclosures of activity on a gross basis within Level 3reconciliation.

 

**Risks and Uncertainties**

 

There are a number of risks that face participantsin the U.S., Canadian and international oil and natural gas industry, includinga number of risks that face us in particular. Accordingly, there are risksinvolved in an ownership of our securities. See “Risk Factors” for adescription of the principal risks faced by us.

 

**Item 7A.*Quantitative and Qualitative DisclosuresAbout Market Risk***

 

We are exposed tomarket risks arising from fluctuating prices of crude oil, natural gas andinterest rates as discussed below.

 

*        **CommodityRisk.*  Our major commodity price risk exposure is to the pricesreceived for our natural gas production. Realized commodity prices received forour production are the spot prices applicable to natural gas in the East Texasregion. Prices received for natural gas are volatile and unpredictable and arebeyond our control. 

 

*Currency Translation Risk.  *Because ourrevenues and expenses are primarily in U.S. dollars, we have littleexposure to currency translation risk, and, therefore, we have no plans in theforeseeable future to implement hedges or financial instruments to manageinternational currency changes.

 

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*Hedging.*We did not enter into any hedging transactions during the year ended December 312009.

 

**Item 8.*Financial Statements and Supplementary Data***

 

The reports of ourindependent registered public accounting firms and our consolidated financialstatements and supplemental information required to be filed under Item 8of Form 10-K are presented beginning on Page F-1 of this Form 10-K.

 

**Item 9. *Changes inand Disagreements With Accountants on Accounting and Financial Disclosure***

 

None.

 

**Item 9A. *Controls and Procedures***

 

**Evaluationof Disclosure Controls and Procedures**

 

Our management, with the participation of ourPresident, Chief Executive Officer and Chairman and our Chief FinancialOfficer, has evaluated the effectiveness of our disclosure controls andprocedures (as defined in Rules 13a-15(e) and 15d-15(e) underthe Exchange Act) as of December 31, 2009. Based on this evaluation, we have concluded that, as of December 31,2009, our disclosure controls and procedures were effective, in that theyensure that information required to be disclosed by us in the reports that wefile or submit under the Exchange Act is (1) recorded, processed,summarized and reported within the time periods specified in the SEC’s rules andforms, and (2) accumulated and communicated to our management, includingour President and Chief Executive Officer and Chief Financial Officer, asappropriate to allow timely decisions regarding required disclosure.

 

**Internal control over financial reporting**

 

Pursuantto Section 404 of the Sarbanes-Oxley Act of 2002, we have included areport of management’s assessment of the design and effectiveness of ourinternal controls as part of this annual report on Form 10-K for thefiscal year ended December 31, 2009. This annual report does not include an attestation report of the company’sregistered public accounting firm regarding internal control over financialreporting. Management’s report was not subject to attestation by the Company’sregistered public accounting firm pursuant to temporary rules of theSecurities and Exchange Commission that permit the company to provide onlymanagement’s report in this annual report. Management’s report shall not bedeemed to be filed for purposes of Section 18 of the Exchange Act orotherwise subject to the liabilities of that section.

 

No changes to our internal control over financialreporting occurred during the last fiscal quarter that have materiallyaffected, or are reasonably likely to materially affect, our internal controlover financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) underthe Exchange Act).

 

**Item 9B. *Other Information***

 

None.

 

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**PART III**

 

**Item 10. *Directors, Executive Officers and CorporateGovernance***

 

The information required by this item isincorporated by reference from our definitive proxy statement relating to our2009 Annual Meeting of Shareholders, to be filed on or before April 30,2010, the 2010 proxy statement.

 

**Item 11. *Executive Compensation***

 

The information required by this item isincorporated by reference from our 2010 proxy statement.

 

**Item 12. *Security Ownership of Certain Beneficial Owners andManagement and Related Shareholder Matters***

 

The information required by this item is incorporatedby reference from our 2010 proxy statement.

 

**Item 13.*Certain Relationships and RelatedTransactions and Director Independence***

 

The information requiredby this item is incorporated by reference from our 2010 proxy statement.

 

**Item 14.*Principal Accountant Fees and Services***

 

The information requiredby this item is incorporated by reference from 2010 proxy statement.

 

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**PART IV**

 

**Item 15.*Exhibits and Financial Statement Schedules***

 
| ***(a)    ******The following documents are filed  as part of this report*** |                                                                                                                                                                                                                                                                  |   |
|--------------------------------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
| 1.                                                                                               | Management’s  Report on Internal Control Over Financial Reporting                                                                                                                                                                                                |   | F-2 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Report  of Independent Registered Public Accounting Firm—Financial Statements                                                                                                                                                                                    |   | F-3 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Consolidated  Balance Sheets as of December 31, 2009 and 2008                                                                                                                                                                                                    |   | F-4 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Consolidated  Statements of Operations for the years ended December 31, 2009 and 2008                                                                                                                                                                            |   | F-5 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Consolidated  Statements of Shareholders’ Equity for the years ended December 31, 2009  and 2008                                                                                                                                                            |   | F-6 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Consolidated  Statements of Cash Flows for the years ended December 31, 2009 and 2008                                                                                                                                                                            |   | F-7 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
|                                                                                             | Notes  to Consolidated Financial Statements                                                                                                                                                                                                                           |   | F-8 |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
| 2.                                                                                               | All other schedules are omitted because they are not applicable, not  required or the required information is included in the consolidated  financial statements or related notes.                                                                                    |   |   |
|                                                                                             |                                                                                                                                                                                                                                                                  |   |   |
| 3.                                                                                               | A list of exhibits filed or furnished with this report on  Form 10-K (or-incorporated by reference to exhibits previously filed or  furnished by GeoPetro) is provided in the Exhibit Index immediately  following the financial statements in this report. |   |   |

 

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**SIGNATURES**

 

Pursuant to therequirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized, on March 31, 2010.

 
| ** ** | **GEOPETRO RESOURCES COMPANY** |
|------------|--------------------------------|
| ** ** | ** **                     | ** ** |
|       | By:                            | /s/ Stuart J. Doshi |
|       |                           | Stuart J. Doshi |
|       |                           | Chairman of the Board of Directors, President and  Chief Executive Officer |

 

Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the registrant and in thecapacities indicated on March 31, 2010.

 

| **Signature**            | ** ** | **Title**                          | ** ** | **Date**            |
|--------------------------|------------|------------------------------------|------------|---------------------|
|                     |       |                               |       |                |
| /s/ Stuart J. Doshi      |       | Chairman of the Board,  President  |       | March 31, 2010 |
| Stuart J. Doshi          |       | and Chief Executive  Officer       |       |                |
|                     |       |                               |       |                |
| /s/ David V. Creel       |       | Vice President of  Exploration and |       | March 31, 2010 |
| David V. Creel           |       | Director                           |       |                |
|                     |       |                               |       |                |
| /s/ J. Chris Steinhauser |       | Chief Financial Officer            |       | March 31, 2010 |
| J. Chris Steinhauser     |       | and Principal Accounting  Officer  |       |                |
|                     |       |                               |       |                |
| /s/ J. Chris Steinhauser |       | Director                           |       | March 31, 2010 |
| J. Chris Steinhauser     |       |                               |       |                |
|                     |       |                               |       |                |
| /s/ Jeffrey Friedman     |       | Director                           |       | March 31, 2010 |
| Jeffrey Friedman         |       |                               |       |                |
|                     |       |                               |       |                |
| /s/ Thomas D. Cunningham |       | Director                           |       | March 31, 2010 |
| Thomas D. Cunningham     |       |                               |       |                |
|                     |       |                               |       |                |
| /s/ David G. Anderson    |       | Director                           |       | March 31, 2010 |
| David G. Anderson        |       |                               |       |                |
|                     |       |                               |       |                |
| /s/ Nick DeMare          |       | Director                           |       | March 31, 2010 |
| Nick DeMare              |       |                               |       |                |

 

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**GLOSSARY OFOIL AND NATURAL GAS TERMS**

 

In this report, unless the context otherwiserequires, the following terms shall have the indicated meanings. A reference toan agreement means the agreement as it may be amended, supplemented or restatedfrom time to time.

 

“**1933 Act**” means the United States *Securities Act* of 1933, as amended.

 

“**BOK**” means the Bank of Oklahoma N.A.

 

“**Bengara II PSC**” means the PSC dated December 4,1997 between C-G Bengara and Pertamina.

 

“**Bengara Block**” means the contract area inthe Indonesian province of East Kalimantan designated as the Bengara (II) PSCBlock.

 

“**BP Migas**” means Badan Pelaksana Minyak DanGas Muni, a new executive board established by the government of Indonesiain 2002 for oil and gas upstream operations and an implementing body created toassume the role of Pertamina’s regulatory functions and responsibilities inmanaging oil and gas contractors.

 

“**CBM**” means coal bed methane, which ismethane found in coal seams. It is produced by non-traditional means, andtherefore, while it is sold and used the same as traditional natural gas, itsproduction is different. CBM is generated either from a biological process as aresult of microbial action or from a thermal process as a result of increasingheat with depth of the coal. Often a coal seam is saturated with water, withmethane held in the coal by water pressure.

 

“**C-G Bengara**” means Continental-GeoPetro(Bengara II) Ltd., a British Virgin Islands corporation owned 12% byGeoPetro.

 

“**CG Xploration**” means CG Xploration Inc., aDelaware corporation owned 50% by GeoPetro.

 

“**CNPC**” means CNPCHK (Indonesia) Limited.CNPC is a wholly owned subsidiary of CNPC (Hong Kong) Limited, apublicly held company based in Hong Kong where its shares trade on the HongKong Stock Exchange under the listing number 0135.HK.

 

“**Company**” or “**GeoPetro**” means GeoPetro Resources Company, a corporationincorporated under the laws of the State of California and its wholly-ownedsubsidiaries.

 

“**Condensate**” means a low-density, high-APIgravity liquid hydrocarbon product that is generally produced in associationwith natural gas. Condensate is mainly composed of propane, butane, pentane andheavier hydrocarbon fractions.

 

“**Continental**” means Continental EnergyCorporation.

 

“**CRA**” means the Canada Revenue Agency.

 

“**Earning Obligation**” means $18.7 millionpaid by CNPC into a special joint venture account at a Hong Kong internationalbank, which funds are under joint signature control of CNPC ourselves andContinental, and has been expended to pay for 2007 exploration drilling in the BengaraII PSC area.

 

“**EIA**” means the United States EnergyInformation Administration.

 

“**EP 408**” means the approximately 201,000gross (52,675 net) acre permit area including the Whicher Range gasfield in the South Perth basin of Western Australia designated as ExplorationPermit 408 which we transferred to an unrelated party in June 2007.

 

“**Proved Properties**”****means those properties that are producingoil or gas or on which, based on known geological and engineering data, oil andgas reserves are reasonably certain to exist.

 

“**Fannin Well**” means the Angela Farris FanninNo. 1 well located at the Madisonville Field.

 

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“**Farmout**” means an agreement whereby a thirdparty agrees to pay for the drilling of a well on one or more of GeoPetro’sproperties in order to earn an interest therein with GeoPetro retaining aresidual interest in such properties.

 

“**Flow-Through Share**” means a share of commonstock issued as a “flow-through share” within the meaning of Canadian tax law.

 

“**Gateway**” means Gateway Processing Company,a Texas corporation that has constructed pipeline facilities at theMadisonville Field.

 

“**GeoPetro Alaska**” means GeoPetroAlaska LLC, an Alaska limited liability company, which is a wholly-ownedsubsidiary of GeoPetro.

 

“**GeoPetro Canada**” means GeoPetroCanada Ltd., an Alberta corporation, which is a wholly-owned subsidiary ofGeoPetro.

 

“**Hanover**” means Hanover Compression LimitedPartnership, a Delaware limited partnership that has constructed and previouslyoperated treatment facilities at the Madisonville Field.

 

“**Hanover Agreement**” means, collectively, theFirst Amended and Restated Master Agreement, dated as of September 12,2002 among Redwood, Hanover and Gateway, as amended, providing for theprocessing of natural gas from the Madisonville Field, and the agreementsrelated thereto, which agreements were in effect prior to August 2005.

 

“**LPG**” means liquefied petroleum gas.

 

“**Madisonville Field**” means the Madisonville(Rodessa) field in Madison County, Texas.

 

“**Madisonville Midstream LLC**” meansMadisonville Midstream LLC, a Texas limited liability company, which is awholly-owned subsidiary of Redwood Energy Production, and which is 100% owned,directly or indirectly, by GeoPetro.

 

“**Madisonville Project**” means the oil andnatural gas exploration, development and production project at the MadisonvilleField.

 

“**Magness Well**” means the UMC Ruby Magness No. 1well located at the Madisonville Field.

 

“**Makapan Gas Field**” means the Makapan gasfield in East Kalimantan, Indonesia.

 

“**MGP**” means Madisonville GasProcessing, LP, a Colorado Limited Partnership that has purchased fromHanover and currently operates the treatment facilities at the MadisonvilleField, and is jointly owned by JPMorgan Partners and Bear CubInvestments LLC.

 

“**MGP Agreement**” means, collectively, theTermination and Release Agreement, Madisonville Field Development Agreement,Gas Purchase Contract between Redwood LP as Seller, and MGP as Buyer,Escrow Agreement and Dedication Agreement, all effective as of August 1,2005 among Redwood LP, MGP, Gateway and Gateway Pipeline Company,providing for the termination of the Hanover Agreement, the expansion of thetreatment facilities and the provision of the gathering, processing,transportation and sale of natural gas from the Madisonville Field.

 

“**Mitchell Well**” means the Mitchell No. 1well located at the Madisonville Field.

 

“**Pertamina**” means Perusahaan PertambanganMinyak Dan Gas Bumi Negara, the previous Indonesian state-owned oil and naturalgas company established in 1971 which had exclusive authority to explore, drillfor, and produce oil and natural gas minerals in Indonesia. In accordance withthe new Indonesian Oil and Gas Law, its corporate form has been changed tobecome a state-owned limited liability company established under IndonesianCompany Law, and all rights and obligations of Pertamina under existing PSCsshall pass to BP Migas.

 

**“Proveddeveloped oil and gas reserves”** means reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.Additional oil and gas expected to be obtained through the application of fluidinjection or other improved recovery techniques for supplementing the naturalforces and mechanisms of primary recovery should be included as “proveddeveloped reserves” only after testing by a pilot project or after theoperation of an installed program has confirmed through production responsethat increased recovery will be achieved.

 

**“Proveddeveloped nonproducing reserves”**means reserves expected to be recovered from zonesbehind casing in existing wells.

 

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**“Provedoil and gas reserves”** means estimated quantities of crude oil, natural gas, and natural gasliquids which geological and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs under existing economicand operating conditions, i.e., prices and costs as of the date the estimate ismade. Prices include consideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations based upon futureconditions.

 

(i)               Reservoirs are considered proved ifeconomic producibility is supported by either actual production or a conclusiveformation test. The area of a reservoir considered proved includes (A) thatportion delineated by drilling and defined by gas-oil and/or oil-watercontacts, if any; and (B) the immediately adjoining portions not yetdrilled, but which can be reasonably judged as economically productive on thebasis of available geological and engineering data. In the absence ofinformation on fluid contacts, the lowest known structural occurrence ofhydrocarbons controls the lower proved limit of the reservoir.

 

(ii)            Reserves which can be producedeconomically through application of improved recovery techniques (such as fluidinjection) are included in the “proved” classification when successful testingby a pilot project, or the operation of an installed program in the reservoir,provides support for the engineering analysis on which the project or programwas based.

 

(iii)         Estimates of proved reserves do notinclude the following:

 

(A)         oil that may become available from knownreservoirs but is classified separately as “indicated additional reserves”;

 

(B)           crude oil, natural gas, and natural gasliquids, the recovery of which is subject to reasonable doubt because ofuncertainty as to geology, reservoir characteristics, or economic factors;

 

(C)           crude oil, natural gas, and natural gasliquids, that may occur in undrilled prospects; and

 

(D)          crude oil, natural gas, and natural gasliquids that may be recovered from oil shales, coal, gilsonite and other suchsources.

 

**“Provedundeveloped reserves”** means reserves that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditureis required for recompletion. Reserves on undrilled acreage shall be limited tothose drilling units offsetting productive units that are reasonably certain ofproduction when drilled. Proved reserves for other undrilled units can beclaimed only where it can be demonstrated with certainty that there iscontinuity of production from the existing productive formation. Under nocircumstances should estimates, for proved undeveloped reserves be attributableto any acreage for which an application of fluid injection or other improvedrecovery technique is contemplated, unless such techniques have been provedeffective by actual tests in the area and in the same reservoir.

 

“**PSC**” means a production sharing contract,being a contract with Pertamina whereby Pertamina contracts with a petroleumcompany to explore for, develop and extract petroleum substances from aparticular license area, on Pertamina’s behalf, at the risk and expense of thepetroleum company, in exchange for a share of the production.

 

“**Redwood**” means Redwood Energy Company, aTexas corporation, which is a wholly-owned subsidiary of GeoPetro and which isthe general partner of, and holds a 5% interest in, Redwood LP.

 

“**Redwood LP**” means Redwood EnergyProduction, L.P., a Texas limited partnership, the sole limited partner ofwhich is GeoPetro and which is 100% owned, directly or indirectly, by GeoPetro.

 

“**Rodessa Formation**” means the geologicalformation at the Madisonville Field existing at a depth of approximately12,000 feet.

 

“**Seismic**” means data collected that usesreflected seismic waves to produce images of the Earth’s subsurface. The methodrequires a controlled seismic source of energy, such as dynamite or aspecialized air gun. By noting the time it takes for a reflection to arrive ata receiver, it is possible to estimate the depth of the feature that generatedthe reflection.

 

“**Series A Stock**” means the preferredstock of GeoPetro designated as Series A preferred stock, all of whichconverted to GeoPetro’s common stock on March 30, 2006.

 

“**Series AA Stock**” means the preferredstock of GeoPetro designated as Series AA preferred stock, as describedunder “Description of Share Capital”.

 

“**Series B Stock**”means the preferred stock of GeoPetro designed as Series B preferredstock, as described under “Description of Share Capital”.

 

54

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“**South TexasGeoPetro**” means South Texas GeoPetro, LLC., a Texas limitedliability company, the sole limited partner of which is GeoPetro and which is100% owned, directly or indirectly, by GeoPetro.

 

“**Tertiary Sandstones**” means sandstones whichwere deposited during a geologic time period ranging from 2 to 63 millionyears ago.

 

“**TSX**” means the Toronto Stock Exchange.

 

“**Unproved Properties**” means properties notyet evaluated through exploration and drilling as to whether or not they haveproved reserves.

 

“**U.S. GAAP**” means the accounting principlesgenerally accepted in the United States.

 

“**Wilson Well**” means the Wilson No. 1well located at the Madisonville Field.

 

“**Working interest**” means thepercentage of undivided interest held by a party in the oil and/or natural gasor mineral lease granted by the mineral owner, which interest gives the holderthe right to “work” the property (lease) to explore for, develop, produce andmarket the leased substances.

 

**ABBREVIATIONS ANDCONVERSIONS**

** **

In this report,the following abbreviations have the meanings set forth below:

 
| API           | American  Petroleum Institute                                                                                                                                                                                                                                                                                                                                                                                                                                              |
|---------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| bbl  and bbls | barrel  and barrels, each barrel representing 34.972 Imperial gallons or 42  U.S. gallons                                                                                                                                                                                                                                                                                                                                                                             |
| bbls/d        | barrels  per day                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| bcf           | billion  cubic feet                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| boe           | barrels  of oil equivalent converting 6 mcf of natural gas to one barrel of oil  equivalent and one barrel of natural gas liquids to one barrel of oil  equivalent. Measures of boes may be misleading, particularly if used in  isolation. This conversion ratio is based on an energy equivalency conversion  method primarily applicable at the burner tip and does not represent a value  equivalency at the wellhead, but is a commonly used industry benchmark. |
| boe/d         | barrels  of oil equivalent per day                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| degree  API   | an  indication of the specific gravity of crude oil measured on the API gravity  scale. Liquid petroleum with a specified gravity of 28 degree API or higher  is generally referred to as light crude oil.                                                                                                                                                                                                                                                                 |
| LPG           | liquefied  petroleum gas                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| mbbls         | one  thousand barrels                                                                                                                                                                                                                                                                                                                                                                                                                                                      |
| mboe          | one  thousand barrels of oil equivalent                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| mcf           | one  thousand cubic feet                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
| mcf/d         | one  thousand cubic feet per day                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| mmbbls        | one  million barrels                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| MMBTU         | one  million British Thermal Units                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| MMcf          | one  million cubic feet                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
| MMcf/d        | one  million cubic feet per day                                                                                                                                                                                                                                                                                                                                                                                                                                            |
| NGLs          | natural  gas liquids                                                                                                                                                                                                                                                                                                                                                                                                                                                       |
| Psig          | Pounds  per square inch gauge                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| TCF           | trillion  cubic feet                                                                                                                                                                                                                                                                                                                                                                                                                                                  |

 

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**GEOPETRO RESOURCES COMPANY**

 

**INDEX TO FINANCIAL STATEMENTS**

 
| ** **                                                                                                 | **Page** |
|------------------------------------------------------------------------------------------------------------|----------|
| CONSOLIDATED FINANCIAL STATEMENTS FOR THE FISCAL  YEARS ENDED DECEMBER 31, 2009 AND 2008              |     |
|                                                                                                       |     |
| Management’s Report on  Internal Control Over Financial Reporting                                     | F-2      |
|                                                                                                       |     |
| Report of Independent  Registered Public Accounting Firm—Financial Statements                         | F-3      |
|                                                                                                       |     |
| Consolidated Balance Sheets as of December 31,  2009 and 2008                                         | F-4      |
|                                                                                                       |     |
| Consolidated  Statements of Operations for the years ended December 31, 2009 and 2008                 | F-5      |
|                                                                                                       |     |
| Consolidated  Statements of Shareholders’ Equity for the years ended December 31, 2009  and 2008 | F-6      |
|                                                                                                       |     |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2009 and 2008                 | F-7      |
|                                                                                                       |     |
| Notes to  Consolidated Financial Statements                                                                | F-8      |

 

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**MANAGEMENT’SREPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

 

Managementis responsible for establishing and maintaining adequate internal control overfinancial reporting (as defined in Rule 13a-15(f) under theSecurities Exchange Act of 1934). Our internal control over financial reportingis designed to provide reasonable assurance to management and our board ofdirectors regarding the preparation and fair presentation of publishedfinancial statements. Because of its inherent limitations, internal controlover financial reporting may not prevent or detect misstatements. Therefore,even those systems determined to be effective can provide only reasonableassurance with respect to financial statement preparation and presentation.Management assessed the effectiveness of our internal control over financialreporting as of December 31, 2009.  In making this assessment,management used the criteria set forth by the Committee of SponsoringOrganizations of the Treadway Commission (COSO) in *Internal Control - Integrated Framework.*Based on our assessment, we believe that as of December 31, 2009, ourinternal control over financial reporting was effective based on thosecriteria. This annual report does not include an attestation report of theCompany’s registered public accounting firm regarding internal control overfinancial reporting.  Management’s reportwas not subject to attestation by the Company’s registered public accountingfirm pursuant to temporary rules of the Securities and exchange Commissionthat permit the Company to provide only management’s report in this annualreport.

 
|   |                                            |   |   |                     |
|--------|-------------------------------------------------|--------|--------|--------------------------|
| By:    | /s/ Stuart J. Doshi                             |   | By:    | /s/ J. Chris Steinhauser |
|   | Stuart J. Doshi                                 |   |   | J. Chris Steinhauser     |
|   | President, Chief Executive Officer and Chairman |   |   | Chief Financial Officer  |

 

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**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

To the Board of Directorsand Stockholders

GeoPetro Resources Company

 

We have audited theconsolidated balance sheets of GeoPetro Resources Company and subsidiaries(collectively, the “Company”) as of December 31, 2009 and 2008, and therelated consolidated statements of operations, changes in shareholders’ equityand cash flows for each of the years then ended.  These financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audits.

 

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whetherthe financial statements are free of material misstatement.  An audit includes examining, on a test basis,evidence supporting the amounts and disclosures in the financialstatements.  An audit also includesassessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statementpresentation.  We believe that our auditsprovide a reasonable basis for our opinion.

 

In our opinion, theconsolidated financial statements referred to above present fairly, in allmaterial respects, the financial position of GeoPetro Resources Company andsubsidiaries as of December 31, 2009 and 2008, and the results of theiroperations and their cash flows for each of the years then ended in conformitywith accounting principles generally accepted in the United States of America.

 

As discussed in Note 2 tothe financial statements, the Company has changed its method of estimating itsproved natural gas reserves and related disclosures as a result of adopting newoil and gas reserve estimation and disclosure requirements as of December 31,2009.

 

We were not engaged toexamine management’s assessment of the effectiveness of GeoPetro ResourcesCompany and subsidiaries’ internal control over financial reporting as of December 31,2009, included in the accompanying Management’s Report on Internal Controls andFinancial Reporting and, accordingly, we do not express an opinion thereon.

 

 

***/****s**/******HEIN**** & ASSOCIATES LLP*

Dallas, Texas

March 31, 2010

 

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**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                                                                                                                                                | ** ** | **December 31,** | ** **       |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------------|
| ** **                                                                                                                                                                                                | ** ** | **2009**              | ** **       | **2008** | ** ** |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **ASSETS**                                                                                                                                                                                                |       |                  |             |   |   |
| **Current assets:**                                                                                                                                                                                       |       |                  |             |   |   |
| Cash and cash equivalents                                                                                                                                                                                 |       | $                     |  2,429,891  |   | $ |  770,779 |   |
| Trade accounts receivable—oil and gas sales                                                                                                                                                          |       | 473,944               |             | 4,266 |   |
| Accounts receivable—other                                                                                                                                                                            |       | 8,658                 |             | 35,107 |   |
| Prepaid expenses                                                                                                                                                                                          |       | 132,238               |             | 212,938 |   |
| Total current assets                                                                                                                                                                                      |       | 3,044,731             |             | 1,023,090 |   |
|                                                                                                                                                                                                      |       |                  |             |   |   |
| **Oil and gas properties, at cost  (full cost method):**                                                                                                                                                  |       |                  |             |   |   |
| Unproved properties                                                                                                                                                                                       |       | 8,411,773             |             | 10,500,498 |   |
| Proved properties                                                                                                                                                                                         |       | 51,194,852            |             | 48,346,939 |   |
| Gas processing plant                                                                                                                                                                                      |       | 10,285,573            |             | 10,707,982 |   |
| Less—accumulated depletion, depreciation and  impairment                                                                                                                                             |       | (38,950,914           | )                | (16,522,304 | ) |
| Net oil and gas properties                                                                                                                                                                                |       | 30,941,284            |             | 53,033,115 |   |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **Furniture, fixtures and  equipment, at cost, net of depreciation**                                                                                                                                      |       | 2,071                 |             | 12,364 |   |
| **Other assets—deposits and other  noncurrent assets**                                                                                                                                               |       | 16,127                |             | 7,436 |   |
| **Total Assets**                                                                                                                                                                                          |       | $                     |  34,004,213 |   | $ |  54,076,005 |   |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **LIABILITIES AND  SHAREHOLDERS’ EQUITY**                                                                                                                                                            |       |                  |             |   |   |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **Current Liabilities:**                                                                                                                                                                                  |       |                  |             |   |   |
| Trade payables                                                                                                                                                                                            |       | $                     |  950,097    |   | $ |  1,137,432 |   |
| Current portion of long term notes payable                                                                                                                                                                |       | 1,549,829             |             | 600,000 |   |
| Interest payable                                                                                                                                                                                          |       | 136,233               |             | 1,479 |   |
| Dividends payable                                                                                                                                                                                         |       | 110,462               |             | — |   |
| Production taxes payable                                                                                                                                                                                  |       | 309,904               |             | 311,168 |   |
| Other taxes payable                                                                                                                                                                                       |       | 11,147                |             | 20,833 |   |
| Royalty owners payable                                                                                                                                                                                    |       | 1,151,284             |             | 1,103,830 |   |
| Total current liabilities                                                                                                                                                                                 |       | 4,218,956             |             | 3,174,742 |   |
|                                                                                                                                                                                                      |       |                  |             |   |   |
| **Long Term Notes Payable**                                                                                                                                                                               |       | 5,986,645             |             | 7,019,449 |   |
| **Asset Retirement Obligations**                                                                                                                                                                          |       | 65,009                |             | 59,099 |   |
| **Total Liabilities**                                                                                                                                                                                     |       | 10,270,610            |             | 10,253,290 |   |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **Commitments and Contingencies  (Notes 1, 4, and 10)**                                                                                                                                                   |       | —                |             | — |   |
| ** **                                                                                                                                                                                                | ** ** | ** **            | ** **       | ** ** | ** ** |
| **Shareholders’ Equity:**                                                                                                                                                                            |       |                  |             |   |   |
| Series B preferred stock, no par value;  7,523,000 shares authorized; 7,523,000 shares issued and outstanding at  December 31, 2009. Liquidation preference of $5,642,250 and $0,  respectively |       | 5,448,602             |             | — |   |
| Common stock, no par value; 100,000,000 shares  authorized; 34,284,646 shares issued and outstanding, respectively                                                                                   |       | 53,397,733            |             | 53,397,733 |   |
| Additional paid-in-capital                                                                                                                                                                                |       | 3,060,187             |             | 2,610,596 |   |
| Accumulated deficit                                                                                                                                                                                       |       | (38,172,919           | )                | (12,185,614 | ) |
| Total shareholders’ equity                                                                                                                                                                           |       | 23,733,603            |             | 43,822,715 |   |
|                                                                                                                                                                                                      |       |                  |             |   |   |
| **Total Liabilities and  Shareholders’ Equity**                                                                                                                                                      |       | $                     |  34,004,213 |   | $ |  54,076,005 |   |

 

***See accompanying notes to theseconsolidated financial statements.***

 

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**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OF OPERATIONS**

 
| ** **                                                 | ** ** | **For the Years Ended December 31,** | ** **  |
|------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                 | ** ** | **2009**                                                      | ** **  | **2008** | ** ** |
|                                                       |       |                                                          |        |   |   |
| **Revenues:**                                              |       |                                                          |        |   |   |
| Oil and gas sales                                          |       | $                                                             | 4,077,355   |   | $ | 6,152,542 |   |
|                                                       |       |                                                          |        |   |   |
| **Costs and expenses:**                                    |       |                                                          |        |   |   |
| Plant operating                                            |       | 4,832,548                                                     |        | — |   |
| Lease operating                                            |       | 606,266                                                       |        | 1,484,267 |   |
| General and administrative                                 |       | 2,767,385                                                     |        | 2,717,121 |   |
| Net profits interest                                       |       | —                                                        |        | 579,941 |   |
| Impairment of oil and gas properties                       |       | 20,843,305                                                    |        | 69,856 |   |
| Depreciation and depletion                                 |       | 1,595,597                                                     |        | 1,553,418 |   |
| Total costs and expenses                                   |       | 30,645,101                                                    |        | 6,404,603 |   |
|                                                       |       |                                                          |        |   |   |
| **Loss from operations**                                   |       | (26,567,746                                                   | )           | (252,061 | ) |
|                                                       |       |                                                          |        |   |   |
| **Other Income (Expense):**                                |       |                                                          |        |   |   |
|                                                       |       |                                                          |        |   |   |
| Interest expense                                           |       | (736,596                                                      | )           | (1,846 | ) |
| Interest income                                            |       | 6,404                                                         |        | 91,867 |   |
| Gain on sale of equipment                                  |       | 1,488,687                                                     |        | — |   |
| Total other income                                         |       | 758,495                                                       |        | 90,021 |   |
|                                                       |       |                                                          |        |   |   |
| **Loss Before Taxes**                                      |       | (25,809,251                                                   | )           | (162,040 | ) |
|                                                       |       |                                                          |        |   |   |
| Income tax (expense) benefit                               |       | 991                                                           |        | (12,785 | ) |
|                                                       |       |                                                          |        |   |   |
| **Net Loss After Taxes**                                   |       | (25,808,260                                                   | )           | (174,825 | ) |
|                                                       |       |                                                          |        |   |   |
| Preferred stock dividend                                   |       | (179,045                                                      | )           | — |   |
|                                                       |       |                                                          |        |   |   |
| **Net Loss Available to Common  Shareholders**             |       | $                                                             | (25,987,305 | ) | $ | (174,825 | ) |
|                                                       |       |                                                          |        |   |   |
| **Loss per Share:**                                        |       |                                                          |        |   |   |
| Basic                                                      |       | $                                                             | (0.76       | ) | $ | (0.01 | ) |
| Diluted                                                    |       | $                                                             | (0.76       | ) | $ | (0.01 | ) |
|                                                       |       |                                                          |        |   |   |
| **Weighted Average Number of  Common Shares Outstanding:** | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| Basic                                                      |       | 34,284,646                                                    |        | 32,511,251 |   |
| Diluted                                                    |       | 34,284,646                                                    |        | 32,511,251 |   |

 

***See accompanying notes to theseconsolidated financial statements.***

 

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** **

**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OFSHAREHOLDERS’ EQUITY**

 

**FOR THE YEARS ENDED DECEMBER 31, 2009AND 2008**

 
| ** **                                          | ** ** | **Preferred Stock  Series B** | ** ** | **Common stock** | ** ** | **Additional  Paid-in** | ** ** | **Accumulated** | ** ** | **Total  Shareholders’** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------|------------|-----------------------|------------|-------------------------|------------|-----------------|------------|-------------------------------|------------|
| ** **                                          | ** ** | **Shares**                              | ** ** | **Amount**            | ** ** | **Shares**              | ** ** | **Amount**      | ** ** | **Capital**                   | ** ** | **Deficit** | ** ** | **Equity** | ** ** |
| Balances, January 1, 2008                      |       | —                                  |       | $                     | —     |                    | 31,950,970 |            | $          | 51,492,733                    |       | 2,219,109 |   | $ | (12,010,789 | ) | $ | 41,701,053 |   |
| Issuance of common stock from options/warrants      |       | —                                  |       | —                |       | 750,000                 |       | 375,000         |       | —                        |       | — |   | 375,000 |   |
| Issuance of common stock from gas plant acquisition |       | —                                  |       | —                |       | 1,500,000               |       | 1,530,000       |       | —                        |       | — |   | 1,530,000 |   |
| Net warrant exercise                                |       | —                                  |       | —                |       | 83,676                  |       | —          |       |                          |       |   |   | — |   |
| Fair value of warrants issued with notes payable    |       | —                                  |       | —                |       | —                  |       | —          |       | 122,764                       |       | — |   | 122,764 |   |
| Share-based compensation                            |       | —                                  |       | —                |       | —                  |       | —          |       | 268,723                       |       | — |   | 268,723 |   |
| Net loss                                            |       | —                                  |       | —                |       | —                  |       | —          |       | —                        |       | (174,825 | ) | (174,825 | ) |
| Balances, December 31, 2008                    |       | —                                  |       | —                |       | 34,284,646              |       | 53,397,733      |       | 2,610,596                     |       | (12,185,614 | ) | 43,822,715 |   |
| Issuance of Series B preferred stock for cash net   |       | 7,523,000                               |       | 5,448,602             |       | —                  |       | —          |       | —                        |       | — |   | 5,448,602 |   |
| Share-based compensation                            |       | —                                  |       | —                |       | —                  |       | —          |       | 403,963                       |       | — |   | 403,963 |   |
| Fair value of warrants issued with notes payable    |       | —                                  |       | —                |       | —                  |       | —          |       | 45,628                        |       | — |   | 45,628 |   |
| Net loss                                            |       | —                                  |       | —                |       | —                  |       | —          |       | —                        |       | (25,808,260 | ) | (25,808,260 | ) |
| Dividends on Series B preferred stock          |       | —                                  |       | —                |       | —                  |       | —          |       | —                        |       | (179,045 | ) | (179,045 | ) |
|                                                |       |                                    |       |                  |       |                    |       |            |       |                          |       |   |   |   |   |
| Balances, December 31, 2009                    |       | 7,523,000                               |       | $                     | 5,448,602  |                    | 34,284,646 |            | $          | 53,397,733                    |       | $ | 3,060,187 |   | $ | (38,172,919 | ) | $ | 23,733,603 |   |
|                                                     |            |                                         |            |                       |            |                         |            |                 |            |                               |            |  |  |  |  |  |  |  |  |  |

 

***See accompanyingnotes to these consolidated financial statements.***

 

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**GEOPETRORESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 
| ** **                                                                                 | ** ** | **For the Years Ended December 31,** | ** **  |
|--------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                                                                 | ** ** | **2009**                                                      | ** **  | **2008** | ** ** |
| ** **                                                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| **Cash Flows From Operating  Activities:**                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| ** **                                                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| Net loss                                                                                   |       | $                                                             | (25,808,260 | ) | $ | (174,825 | ) |
| Adjustments to reconcile net loss to net cash  provided by (used in) operating activities: |       |                                                          |        |   |   |
| Depreciation and depletion                                                                 |       | 1,595,598                                                     |        | 1,553,418 |   |
| Share-based compensation expense                                                           |       | 403,963                                                       |        | 268,723 |   |
| Non-cash interest expense                                                                  |       | 62,649                                                        |        | 366 |   |
| Impairment of oil and gas properties                                                       |       | 20,843,305                                                    |        | 69,856 |   |
| Gain on sale of equipment                                                                  |       | (1,488,687                                                    | )           | — |   |
| Accretion of discount on asset retirement  obligations                                     |       | 4,728                                                         |        | 4,298 |   |
| Changes in operating assets and liabilities:                                               |       |                                                          |        |   |   |
| Accounts receivable                                                                        |       | (443,229                                                      | )           | 960,922 |   |
| Other assets                                                                               |       | 72,013                                                        |        | 215,400 |   |
| Other liabilities                                                                          |       | (16,077                                                       | )           | 212,915 |   |
| Net cash provided by (used in) operating  activities                                       |       | (4,773,997                                                    | )           | 3,111,073 |   |
|                                                                                       |       |                                                          |        |   |   |
| **Cash Flows from Investing  Activities:**                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| ** **                                                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| Additions to oil and gas properties                                                        |       | (758,006                                                      | )           | (5,569,417 | ) |
| Additions to gas processing plant                                                          |       | (588,904                                                      | )           | (2,480,135 | ) |
| Acquisition of furniture, fixtures and equipment                                      |       | —                                                        |        | (4,307 | ) |
| Proceeds from sale of equipment                                                            |       | 2,500,000                                                     |        | — |   |
| Net cash provided by (used in) investing  activities                                       |       | 1,153,090                                                     |        | (8,053,859 | ) |
|                                                                                       |       |                                                          |        |   |   |
| **Cash Flows from Financing  Activities:**                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
|                                                                                       |       |                                                          |        |   |   |
| Proceeds from issuance of common shares, option  and warrant exercises, net                |       | —                                                        |        | 375,000 |   |
| Proceeds from issuance of Series B preferred stock,  net                              |       | 5,448,602                                                     |        | — |   |
| Payments of preferred dividends                                                            |       | (68,583                                                       | )           | — |   |
| Proceeds from promissory notes, net                                                        |       | 1,897,000                                                     |        | 1,050,000 |   |
| Payments of loan fee                                                                       |       | (40,000                                                       | )           | (6,000 | ) |
| Repayments of promissory notes                                                             |       | (1,825,000                                                    | )           | — |   |
| Repayments of related party notes                                                          |       | (132,000                                                      | )           | — |   |
| Net cash provided by financing activities                                                  |       | 5,280,019                                                     |        | 1,419,000 |   |
|                                                                                       |       |                                                          |        |   |   |
| **Net Increase (Decrease) in Cash  and Cash Equivalents:**                                 |       | 1,659,112                                                     |        | (3,523,786 | ) |
| ** **                                                                                 |       |                                                          |        |   |   |
| **Cash and Cash Equivalents:**                                                             | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| Beginning of period                                                                        |       | 770,779                                                       |        | 4,294,565 |   |
| End of period                                                                              |       | $                                                             | 2,429,891   |   | $ | 770,779 |   |
| ** **                                                                                 | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| **Supplemental Disclosure of Cash  Flow Information:**                                     | ** ** | ** **                                                    | ** **  | ** ** | ** ** |
| Cash paid for interest                                                                     |       | $                                                             | 462,786     |   | $ | 1,528 |   |
|                                                                                       |       |                                                          |        |   |   |
| Cash (refund) paid for income taxes                                                        |       | $                                                             | (991        | ) | $ | 12,785 |   |
|                                                                                       |       |                                                          |        |   |   |
| **Non-Cash Transactions :**                                                                |       |                                                          |        |   |   |
| Assumption of long-term debt for acquisition of  gas treatment plant                       |       | $                                                             | —      |   | $ | 6,697,847 |   |
|                                                                                       |       |                                                          |        |   |   |
| Issuance of common stock for acquisition of gas  treatment plant                           |       | $                                                             | —      |   | $ | 1,530,000 |   |
|                                                                                       |       |                                                          |        |   |   |
| Issuance of warrants in connection with promissory  notes and private placements           |       | $                                                             | 45,628      |   | $ | 122,764 |   |

 

***The accompanying notes are an integral part of theseconsolidated financial statements.***

 

F-7

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Tableof Contents

 

**GEOPETRORESOURCES COMPANY**

 

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**(Informationsubsequent to December 31, 2009 is unaudited)**

 

**1**.                 **ORGANIZATION AND NATUREOF OPERATIONS*:***

 

*GeoPetro*—GeoPetro Resources Company (“we,” “us,” “our,”“GeoPetro” or the “Company”) was originally incorporated as GeoPetro Companyunder the laws of the State of Wyoming in 1994 to participate in the oil andgas acquisition, exploration, development and production business in theUnited States and internationally. GeoPetro Company was subsequentlymerged into GeoPetro Resources Subsidiary Company, a California corporation, onJune 28, 1996. GeoPetro’s name was then changed to GeoPetro ResourcesCompany. GeoPetro’s corporate offices are in San Francisco, California. Theaccompanying consolidated financial statements include the accounts of GeoPetroand its wholly-owned subsidiaries. All significant intercompany accounts andtransactions have been eliminated in consolidation.

 

*Operationsand Liquidity*—AlthoughGeoPetro is not a development stage enterprise, the Company has a limitedoperating history upon which an evaluation of its business prospects can bebased. The risks, expense, and difficulties encountered by early stagecompanies must be considered when evaluating GeoPetro’s business prospects.GeoPetro recorded a net loss of 25,987,305 and $174,825 in 2009 and 2008 respectively, and had a working capitaldeficit of $1,174,225 and an accumulated deficit at December 31, 2009 of$38,172,919. GeoPetro expects to make significant capital expenditures in theforeseeable future. Management believes that GeoPetro will be successful inobtaining adequate sources of cash to fund its anticipated capital expendituresand operating expense through the end of 2010 and to follow through with plansfor continued investments in oil and gas properties. GeoPetro’s success, inpart, depends on its ability to generate additional financing, farmout certainof its projects and manage its relations with the companies that provideexploration and development services. GeoPetro’s success also depends on itsability to effectively manage growth and develop proved reserves. Additionally,GeoPetro’s operations are subject to all of the environmental and operationalrisks normally associated with the oil and gas industry.

 

Since its inception,GeoPetro has participated as a working interest owner in the acquisition ofundeveloped leases, seismic options, lease options and foreign concessions andhas participated in seismic surveys and the drilling of test wells on itsundeveloped properties. More recently, we acquired a natural gas treatmentplant in East Texas.  Further leaseholdacquisitions and seismic operations are planned for 2010 and future periods. Inaddition, exploratory and development drilling is scheduled during 2010 andfuture periods on GeoPetro’s undeveloped properties and capital improvementsare planned on the natural gas treatment plant. It is anticipated that theplanned capital improvements at the natural gas treatment plant and theexploration activities together with others that may be entered into may imposefinancial requirements which may exceed the existing working capital ofGeoPetro. Management will need to raise additional equity and/or debt capital,to finance its continued activities. However, if additional financing is notavailable, GeoPetro may be compelled to reduce the scope of its businessactivities. If GeoPetro is unable to fund planned expenditures, it may benecessary to:

 

1.                  farm-out its interest in proposed wells;

 

2.                  sell a portion of its interest inprospects and use the sale proceeds to fund its participation for a lesserinterest;

 

3.                  forfeit its interest in wells that are proposed to bedrilled and;

 

4.                  reduce general and administrativeexpenses.

 

As an example of this, inMarch 2010 we sold our entire working interest in our Alaskan Leases forcertain cash payments and overriding royalties.

 

**2.****                ****SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:**

 

*U.S.GAAP**—*TheCompany’s financial statements have been prepared in accordance with accountingprinciples generally accepted within the United States of America (“U.S. GAAP”).

 

*Use ofEstimates and Significant Estimates**—*Certain amounts in GeoPetro’s financial statements arebased upon significant estimates, including oil and gas reserve quantitieswhich form the basis for the calculation of depreciation, depletion,amortization and impairment of oil and gas properties, the carrying values ofunproved properties, asset retirement obligations, accounting for businesscombinations and share-based payments. Actual results could materially differfrom those estimates.

 

F-8

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Tableof Contents

 

*Oil andGas Properties*—GeoPetrofollows the full cost method of accounting for oil and gas producing activitiesand, accordingly, capitalizes all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including thecosts of abandoned properties, dry holes, geophysical costs, and annual leaserentals. All general corporate costs are expensed as incurred. In general,sales or other dispositions of oil and gas properties are accounted for asadjustments to capitalized costs, with no gain or loss recorded. Costs incurredfor repairs and maintenance are expensed as incurred. Amortization of provedoil and gas properties is computed on the units of production method based onall proved reserves on a country by country basis. Unproved oil and gasproperties are assessed for impairment either individually or on an aggregatebasis. The net capitalized costs of proved oil and gas properties (full costceiling limitation) are not to exceed their related estimated future netrevenues discounted at 10%, and the lower of cost or estimated fair value ofunproved properties, net of tax considerations.

 

*Asset Impairment*—Under full cost accounting, a ceiling test is performed to ensure thatunamortized capitalized costs in each cost center (country) do not exceed theirfair value.  Impairment is recognizedwhen the carrying value is greater than the discounted future cash flows.  In the event of impairment, the amount by whichthe carrying value exceeds the estimated fair value of the long-lived asset ischarged to earnings. The present value of estimated future net revenues iscomputed by applying average oil and gas prices to estimated future productionof proved oil and gas reserves as of period-end, less estimated futureexpenditures to be incurred in developing and producing the proved reservesassuming the continuation of existing economic conditions.  In December 2008, the SEC announced that it hadapproved revisions designed to modernize the oil and gas company reservesreporting requirements.  We adopted the rules effective December 31,2009.  Application of the new reserve rules resultedin the use of a lower natural gas price at December 31, 2009 than wouldhave resulted under the previous rules. As a result, the new pricingmethodology rules resulted in a lower net present value (PV-10) ofeconomically producible reserves. The new SEC rules requirethat reserve calculations be based on the un-weighted average first-day-of-the-monthprices for the prior twelve months, as contrasted with the previous methodwhich utilized period end prices.  The prices under the new rules were$3.11 per Mcf for natural gas adjusted for energycontent, quality and basis differentials. Under the new rules, this resulted ina ceiling test write-down of $19,798,390 associated with the US full costpool.  There was no impairment of provedoil and gas properties indicated at December 31, 2008.

 

For the unprovedproperties, the Company evaluates the possibility of potential impairment on aquarterly basis. During the twelve months ended December 31, 2009,approximately $1,020,270 of unproved property costs related to Canadianexploration projects and $24,644 of unproved property costs related toIndonesia exploration were reclassified to proved property and ceiling testimpairment was recorded in the Canadian and Indonesia full cost pool due to dryholes drilled.

 

*JointVentures*—Someexploration and production activities are conducted jointly with others and,accordingly, the accounts reflect only GeoPetro’s proportionate interest insuch activities.

 

*RevenueRecognition*—Priorto December 31, 2008, revenue was recognized upon delivery of oil and gasproduction and was shown net of applicable royalty payments, processing andtransportation fees. The Company recognized revenue from the Madisonville Fieldnet of applicable fees to gather, treat and transport the Company’s natural gasproduction. The applicable fees were paid to unrelated third parties.  On December 31, 2008, the Companycompleted the acquisition of a natural gas treatment plant (the “Plant”) fromMadisonville Gas Processing, LP (“MGP”). Effective January 1, 2009, the Companybegan recognizing revenue without the netting of applicable processing and thetransportation fees since the Company acquired the Plant. See Note 3.

 

*AssetRetirement Obligation*—In accordance with *Accounting forAsset Retirement Obligation,* ASC 410-20 (formerly Statement ofFinancial Accounting Standards No. 143,”SFAS 143”), the fair value ofan asset retirement cost, and corresponding liability, should be recorded aspart of the cost of the related long-lived asset and subsequently allocated toexpense using a systematic and rational method. GeoPetro recorded an assetretirement obligation to reflect GeoPetro’s legal obligations related to futureplugging and abandonment of its oil and gas wells. GeoPetro estimated theexpected cash flow associated with the obligation and discounted the amountusing a credit-adjusted, risk-free interest rate. At least annually, GeoPetroreassesses the obligation to determine whether a change in the estimatedobligation is necessary. GeoPetro evaluates whether there are indicators thatsuggest the estimated cash flows underlying the obligation have materiallychanged. Should those indicators suggest the estimated obligation hasmaterially changed, GeoPetro will accordingly update its assessment.

 

Thereare asset retirement obligations associated with the Plant. However, componentsof the Plant can be used for extended and indeterminate periods of time as longas they are properly maintained and/or upgraded. GeoPetro’s intent is tomaintain the Plant assets and continue making improvements to those assetsbased on technological advances. As a result, GeoPetro’s management believesthat the Plant has an indeterminate life for purposes of estimating assetretirement obligations because dates or ranges of dates upon which GeoPetrowould retire the Plant cannot reasonably be estimated.

 
| ** **                                        | ** ** | **December 31,** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **2009**              | ** ** | **2008** | ** ** |
| ** **                                        | ** ** | ** **            | ** ** | ** ** | ** ** |
| Asset retirement obligations, beginning of period |       | $                     | 59,099     |   | $ | 53,726 |   |
| Liabilities incurred                              |       | 1,182                 |       | 1,075 |   |
| Accretion expense                                 |       | 4,728                 |       | 4,298 |   |
| Asset retirement obligations, end of period       |       | $                     | 65,009     |   | $ | 59,099 |   |

 

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Tableof Contents

 

*Furniture,Fixtures and Equipment**—*Furniture, fixtures and equipment are stated at cost.Depreciation is provided on furniture, fixtures and equipment using thestraight-line method over an estimated service life of three to seven years.

 

*IncomeTaxes*—GeoPetroaccounts for income taxes using the asset and liability method wherein deferredtax assets and liabilities are recognized for the future tax consequencesattributable to differences between financial statement carrying amounts ofexisting assets and liabilities and their respective tax bases. Deferred taxassets and liabilities are measured using enacted tax rates expected to applyto taxable income in the years in which the temporary differences are expectedto be recovered or settled. Because management has determined that realizationof deferred tax assets is not more likely than not, the net deferred tax assetsare fully reserved.

 

*Concentrationsof Credit Risk*—Creditrisk represents the accounting loss that would be recognized at the reportingdate if counterparties failed completely to perform as contracted.Concentrations of credit risk (whether on or off balance sheet) that arise fromfinancial instruments exist for groups of customers or counterparties when theyhave similar economic characteristics that would cause their ability to meetcontractual obligations to be similarly affected by changes in economic or otherconditions described below. The credit risk amounts for cash and accountsreceivable do not take into account the value of any collateral or security.

 

GeoPetro maintainsseveral cash accounts with three financial institutions. Accounts at eachinstitution are insured by the Federal Deposit Insurance Corporation up to$250,000. As of December 31, 2009, the uninsured bank balance was$1,561,754. GeoPetro has not experienced any losses in such accounts andbelieves it is not exposed to any significant credit risk.

 

During the years ended December 31,2009 and 2008, the Company had sales to customers exceeding 10% of total salesas follows:

 
| ** **                   | ** ** | **2009** | ** ** | **2008** | ** ** |
|------------------------------|------------|----------|------------|----------|------------|
| Luminant Energy Company, LLC |       | 100      | %          | 98       | %          |
| ETC Katy Pipeline, Ltd.      |       | —   |       | 2        | %          |

 

At December 31,2009, and 2008, the Company had accounts receivable balances from LuminantEnergy Company, LLC of $473,944 or 98% and $ 4,266 or 11% of total accountsreceivable respectively.

 

*Trade Accounts Receivable and Allowance for DoubtfulAccounts*—Accounts receivable, oil and gas sales, consist ofuncollateralized accrued revenues due under normal trade terms, generallyrequiring payment within 30 days.  Nointerest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliestunpaid items.  Trade accounts receivableare recorded at net realizable value. If the financial condition of GeoPetro’scustomers were to deteriorate, resulting in an impairment of their ability tomake payments, additional allowances may be required. Delinquent trade accountsreceivable are charged against the allowance for doubtful accounts onceuncollectibility has been determined. The allowance is determined through ananalysis of the past-due status of accounts receivable and assessments of riskthat are based on historical trends and an evaluation of the impact of currentand projected economic conditions. There was no allowance for doubtful accountsneeded as of the years ended December 31, 2009 or 2008.

 

*FairValue of Financial Instruments*—The estimated fair values for financial instrumentsare determined at discrete points in time based on relevant market information.These estimates involve uncertainties and cannot be determined with precision.For certain of GeoPetro’s financial instruments, including cash, accountsreceivable, accounts payable and current portion of notes payable, the carryingamounts approximate fair value due to their maturities.

 

*Share-Based Payments*—The**Company has a stock- based compensationplan that allows employees to purchase common shares of the Company. Optionexercise prices approximate the market price for the common shares on the datethe options were issued. Options granted under the plan are generally fullyexercisable after five years and expire five to ten years after the grantdate. The Company measures and records stock-based awards to directors,employees and consultants based on the grant-date fair value, determined usingthe Black-Scholes option pricing model with assumptions for: risk free interestrates, expected dividend yield, expected life of the option, and the expectedvolatility. The compensation expense was recorded ratably over the requisiteservice period defined in the award.  TheCompany recorded $403,963 and $268,723 of stock-based employee compensation forthe twelve months ended December 31, 2009 and 2008, respectively. See Note8.

 

*Net Loss per Common Share****—***Basic net loss per common share is computed bydividing the net loss attributable to common shareholders by the weightedaverage number of shares of common stock outstanding during the period.

 

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

 
| ** **                                 | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------|------------|-----------------------------------|------------|
| ** **                                 | ** ** | **2009**                          | ** ** | **2008** | ** ** |
| Stock options (Note 8)                     |       | 2,720,000                         |       | 2,740,000 |   |
| Warrants (Note 9)                          |       | 1,561,547                         |       | 1,249,857 |   |
| Convertible preferred stock, Series B |       | 7,523,000                         |       | — |   |

 

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All of the common sharesunderlying the stock options and warrants above were excluded from dilutedweighted average shares outstanding for each of the two years in the periodended December 31, 2009 because their effects were antidilutive.

 

*SegmentReporting*—GeoPetrohas oil and gas exploration, development and production operations in theUnited States, Canada, Australia and Indonesia. All revenues and relatedcosts are associated with operations in the United States. A summary ofassets and capital expenditures by geographical segment is included inNote 3.

 

*Cashand Cash Equivalents**—*Cash and cash equivalents include cash on hand,amounts held in banks and highly liquid investments purchased with an originalmaturity of three months or less.

 

*Recently Issued Accounting Pronouncements**—* Effective January 1, 2009, weadopted ASC 260-10 (formerly Staff Position No. EITF 03-6-1), “Determiningwhether Instruments Granted in Share-Based Payment Transactions areParticipating Securities,” which provides that unvested share-based paymentawards that contain non-forfeitable rights to dividend or dividend equivalents(whether paid or unpaid) are participating securities, and, therefore need tobe included in the earnings allocation in computing earnings per share underthe two-class method. We adopted the provisions of this standard on January 1,2009, with no significant impact on our financial statements.

 

Effective January 1,2009, we adopted ASC 815-10 (formerly Statement of Financial Accounting Standards(“SFAS”) 161, *Disclosures about DerivativeInstruments and Hedging Activities, an amendment of FASB Statement 133*),which amends and expands the disclosure requirements with the intent to provideusers of financial statements with an enhanced understanding of (i) howand why an entity uses derivative instruments; (ii) how derivativeinstruments and the related hedged items are accounted for; and (iii) howderivative instruments and related hedged items affect an entity’s financialposition, financial performance and cash flows. We adopted the provisions ofthis standard on January 1, 2009, with no significant impact on ourfinancial statements.

 

In June 2009,the FASB issued ASC 105-10 (formerly SFAS No. 168), *Accounting Standards Codification**TM* *and the Hierarchy of Generally Accepted AccountingPrinciples*. The FASB Accounting Standards CodificationTM (the “Codification”)has become the source of authoritative accounting principles recognized by theFASB to be applied by nongovernmental entities in the preparation of financialstatements in accordance with Generally Accepted Accounting Principles (“GAAP”).All existing accounting standard documents are superseded by the Codificationand any accounting literature not included in the Codification will not beauthoritative. Rules and interpretive releases of the SEC issued under theauthority of federal securities laws, however, will continue to be the sourceof authoritative generally accepted accounting principles for SEC registrants.Effective September 30, 2009, all references made to GAAP in ourconsolidated financial statements will include the new Codification numberingsystem along with original references. The Codification does not change oralter existing GAAP and, therefore, will not have an impact on our financialposition, results of operations or cash flows.

 

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

 

·                  Modifying prices used to estimate reserves for SECdisclosure purposes to the simple average of the prices posted on the first dayof each month in the Company’s fiscal year instead of a single-day, period-endprice.

·                  Requiring certain additional disclosures around provedundeveloped reserves, internal controls used to ensure objectivity of theestimation process, and qualifications of those preparing and/or auditing thereserves.

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

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

 

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·                  We are now required to file the report of any thirdparty used to prepare or audit reserves our estimates.

 

In addition, in January 2010, FASB issued AccountStandards Update (the “Update”) 2010-03, “Oil and Gas Reserve Estimation andDisclosures,” to provide consistency with the new reserve rules. The Updateamends existing standards to align the reserves calculation and disclosurerequirements under GAAP with the requirements in the SEC’s reserve rules. Weadopted the new standards effective December 31, 2009. The new standardsare applied prospectively as a change in estimate.

 

Application of the newreserve rules resulted in the use of a lower natural gas price at December 31,2009 than would have resulted under the previous rules. As a result, the newpricing methodology rules resulted in a lower net present value (PV-10) ofeconomically producible reserves. The new SEC rules require that reservecalculations be based on the un-weighted average first-day-of-the-month pricesfor the prior twelve months, as contrasted with the previous method whichutilized period end prices.  The pricesunder the new rules were $3.11 per Mcf for natural gas adjusted for energycontent, quality and basis differentials. Under the new rules, this resulted ina ceiling test write-down of $19.8 million associated with the US full costpool.  Had we used the price prevailingon December 31, 2009 of $5.45 per Mcf for natural gas, no ceiling testwrite-down would have been recorded. 

 

Use of new 12-month averagepricing rules at December 31, 2009 also resulted in a decrease in economicallyproducible proved reserves of approximately 1.03 Bcf. Use of the old year-endprices rules would have resulted in a decrease in proved reserves ofapproximately 0.53 Bcf at December 31, 2009. Therefore, the total impact of thenew price methodology rules resulted in negative reserves revisions of 0.5 Bcf.

 

The effect of adopting the new reserve rules on our depletion wasinsignificant.

 

On June 30, 2009, weadopted ASC 855-10 (formerly SFAS No. 165) *Subsequent Events*. ASC 855-10 establishes general standardsof accounting for and disclosure of events that occur after the balance sheetdate but before financial statements are issued or are available to be issued.Specifically, ASC 855-10 sets forth the period after the balance sheet dateduring which management of a reporting entity should evaluate events ortransactions that may occur for potential recognition or disclosure in thefinancial statements, the circumstances under which an entity should recognizeevents or transactions occurring after the balance sheet date in its financialstatements, and the disclosures that an entity should make about events or transactionsthat occurred after the balance sheet date. The adoption of ASC 855-10 had noimpact on our results, cash flow or financial position as managementalready followed a similar approach prior to the adoption of this standard.

 

In January 2010,the Financial Accounting Standards Board issued amendments to Fair ValueMeasurements and Disclosures under ASC Topic 820. Effective for our 2010financial statements, this guidance provides for disclosures of significanttransfers in an out of Levels 1 and 2. In addition, the guidance clarifiesexisting disclosure requirements regarding inputs and valuation techniques aswell as the appropriate level of disaggregation for fair value measurements anddisclosures. Effective for our 2011 financial statements, this guidanceprovides for disclosures of activity on a gross basis within Level 3reconciliation.  The adoption of thestandard is not expected to have a material impact on our financial statements.

 

**3.****                ****SUMMARY OF OIL AND GAS OPERATIONS*:***

 

Capitalized costs at yearend and costs incurred relating to GeoPetro’s oil and gas properties aresummarized as follows:

 

Capitalized costs as of December 31,2009 are as follows:

 
| ** **                                     | ** ** | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals**  | ** ** |
|------------------------------------------------|------------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|-------------|------------|
| Proved properties                              |       | $                      | 46,102,853 |          | $          | 2,388,051     |       | $          | 24,644     |        | $          | 2,679,304 |   | $ | 51,194,852 |   |
| Unproved properties                            |       | 5,225,530              |       | 1,522,718     |       | 1,333,797     |       | 329,728    |       | 8,411,773   |       |
| Gas processing plant                           |       | 10,285,573             |       | —        |       | —        |       | —     |       | 10,285,573  |       |
| Less—accumulated depletion and impairment |       | (33,858,915            | )          | (2,388,051    | )          | (24,644       | )          | (2,679,304 | )          | (38,950,914 | )          |
| Net capitalized costs                          |       | $                      | 27,755,041 |          | $          | 1,522,718     |       | $          | 1,333,797  |        | $          | 329,728 |   | $ | 30,941,284 |   |

 

Costs incurred for theyear ended December 31, 2009 are as follows:

 
| Gas processing plant acquisition |   | $       | (570,971 | )      | $      | —  |   | $       | —  |    | $      | —  |   | $ | (570,971 | )      |
|----------------------------------|--------|---------|----------|--------|--------|---------|--------|---------|---------|---------|--------|---------|--------|---|----------|--------|
| Exploration                      |   | 528,532 |     | — |   | (41,896 | )      | (15,683 | )       | 470,953 |   |
| Development                      |   | 288,236 |     | — |   | —  |   | —  |    | 288,236 |   |
| Total costs incurred             |   | $       | 245,797  |   | $      | —  |   | $       | (41,896 | )       | $      | (15,683 | )      | $ | 188,218  |   |

 

Capitalized costs as of December 31,2008 are as follows:

 
| ** **                                     | ** ** | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals**  | ** ** |
|------------------------------------------------|------------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|-------------|------------|
| Proved properties                              |       | $                      | 44,299,854 |          | $          | 2,388,051     |       | $          | —     |        | $          | 1 ,659,034 |   | $ | 48,346,939 |   |
| Unproved properties                            |       | 6,211,761              |       | 1,522,718     |       | 1,400,338     |       | 1,365,681  |       | 10,500,498  |       |
| Gas processing plant                           |       | 10,707,982             |       | —        |       | —        |       | —     |       | 10,707,982  |       |
| Less—accumulated depletion and impairment |       | (12,475,219            | )          | (2,388,051    | )          | —        |       | (1,659,034 | )          | (16,522,304 | )          |
| Net capitalized costs                          |       | $                      | 48,744,378 |          | $          | 1,522,718     |       | $          | 1,400,338  |        | $          | 1,365,681 |   | $ | 53,033,115 |   |

 

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Costsincurred for the year ended December 31, 2008 are as follows:

 
| Gas processing plant acquisition |   | $         | 10,707,982 |   | $      | —  |   | $       | —  |      | $      | —  |   | $ | 10,707,982 |   |
|----------------------------------|--------|-----------|------------|--------|--------|---------|--------|---------|---------|-----------|--------|---------|--------|---|------------|--------|
| Exploration                      |   | 3,854,688 |       | — |   | 376,498 |   | 490,973 |    | 4,722,159 |   |
| Development                      |   | 848,332   |       | — |   | —  |   | —  |    | 848,332   |   |
| Total costs incurred             |   | $         | 15,411,002 |   | $      | —  |   | $       | 376,498 |      | $      | 490,973 |   | $ | 16,278,473 |   |

 

During 2009 and 2008, theCompany recorded impairment write-downs associated with the Canadian provedcost pool due to dry holes of $1,020,270, and $69,856, respectively. TheCompany also record impairment write-downs associated with Indonesia project of$24,644.

 

*Un**proved**Oil and GasProperties—United States**—*As GeoPetro’s properties are evaluated throughexploration, they will be included in the amortization base. Costs of unprovedproperties in the United States at December 31, 2009 and 2008 representexploration costs in connection with GeoPetro’s Alaska and Californiaprospects. The prospects and their related costs in unproved properties havebeen assessed individually and no impairment charges were considered necessaryfor the United States properties for any of the periods presented. The currentstatus of these prospects is that seismic data is being interpreted on anon-going basis on the subject lands within the prospects. Drilling in the Alaskaand California prospects is expected to commence in 2010 and 2011, and willcontinue in future periods. See Note 11

 

*Un**proved**Oil and GasProperties—Australia**—*Unproved costs incurred in Australia represent costsin connection with the exploration of two exploration permit areas inAustralia. The prospects and their related costs in unproved properties havebeen assessed individually and no impairment charges were considered necessaryfor the Australian properties for any of the periods presented. On June 20,2007, the Company entered into a contract to sell its Australian Properties toan unaffiliated third party. These costs remaining in unproved propertiesrepresent our retained interest.

 

*Un**proved**Oil and GasProperties—Indonesia**—*Unproved costs incurred in Indonesia represent costsin connection with one production sharing contract area and the explorationefforts in Indonesia. The prospect and its related costs in the unprovedproperties have been assessed individually and no impairment charges wereconsidered necessary for the Indonesian property for any of the periodspresented. The current status of this prospect is that seismic data is beinginterpreted on an on-going basis to identify drilling locations on the subjectlands within the prospect. Drilling was commenced on the prospect in early 2007and is expected to continue in future periods.

 

The Company retains acarried 12% stake in the Bengara (II) Block PSC through its subsidiary,Continental-GeoPetro (Bengara-II) Ltd. (“CGB2”), the operator company of theproject with offices in Jakarta, Indonesia. GeoPetro’s partner, ContinentalEnergy Corporation likewise retains an 18% interest in the Bengara (II) Block.CNPCHK (Indonesia) Limited owns the remaining 70% in the Bengara (II) Blockand has paid 100% of the cost of drilling certain exploratory and appraisalwells.

 

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In the event that theCompany does not establish commerciality and provided that no extensions aregranted for establishing commerciality, the Company would be required toforfeit its interest in the production sharing contract. If the Companyforfeits its interest, it will be necessary to record an impairment write-downequal to the capitalized costs recorded for the area forfeited.

 

In 2009, C-G Bengarareceived an extension to the Bengara-II PSC contract until December 4,2011 and may be extended for subsequent years subject to further approval basedon an annual review of progress and results of appraisal work.

 

*Breakdownof Un**proved**Oil and Gas Properties**—*The following table sets forth a summaryof oil and gas property costs not being amortized at December 31, 2009, bythe period in which the costs were incurred:

 
| ** **                    | ** ** | **Totals** | ** ** | **Year Ended  December 31,  2009** | ** ** | **Year Ended  December 31,  2008** | ** ** | **Year Ended  December 31,  2007** | ** ** | **2006 and Prior  Years** | ** ** |
|-------------------------------|------------|------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|-------------------------------------|------------|
| Unproved property acquisition |       | $          | 2,150,134  |                                         | $          | —                                       |       | $                                            | —     |                                | $          | 296,189 |   | $ | 1,853,945 |   |
| Exploration                   |       | 6,261,639  |       | (2,088,725                                   | )          | 4,652,303                                    |       | 1,048,525                                    |       | 2,649,536                           |       |
| Total                         |       | $          | 8,411,773  |                                         | $          | (2,088,725                                   | )          | $                                            | 4,652,303  |                                | $          | 1,344,714 |   | $ | 4,503,481 |   |

 

Management expects thatplanned activities for the year 2010 will enable the evaluation ofapproximately 25% of the costs as of December 31, 2009. Evaluation of 30%of the remaining costs is expected to occur in 2011 with the remaining 45% in2012 and beyond.

 

*GAS PROCESSING PLANT*

 

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

 

GeoPetro paid totalconsideration of $10,707,982 for the plant, summarized as follows:

 
| Cash                                                                                                                                                                                                                                    |   | $         | 2,094,000  |   |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|-----------|------------|--------|
| Assumption of note payable to Bank of Oklahoma,  N.A.                                                                                                                                                                                   |   | 6,697,847 |       |
| 1,500,000 common shares of GeoPetro valued at  $1.02 per share, based on the weighted average trading value of GeoPetro’s  common shares during the five days before and after the terms of the sale  were announced to the public |   | 1,530,000 |       |
| Direct costs incurred                                                                                                                                                                                                                   |   | 386,135   |       |
| Total consideration                                                                                                                                                                                                                     |   | $         | 10,707,982 |   |

 

Allof the purchase price was allocated to the processing plant, included in oiland gas properties on our consolidated balance sheet as of December 31,2009.

 

Thereare asset retirement obligations associated with the Plant. However, componentsof the Plant can be used for extended and indeterminate periods of time as longas they are properly maintained and/or upgraded. GeoPetro’s intent is tomaintain the Plant assets and continue making improvements to those assetsbased on technological advances. As a result, GeoPetro’s management believesthat the Plant has an indeterminate life for purposes of estimating assetretirement obligations because dates or ranges of dates upon which GeoPetrowould retire the Plant cannot reasonably be estimated.

 

Ourresults of operations for the years ended December 31, 2008 do not includethe operating results of the natural gas treatment plant because suchacquisition closed on December 31, 2008.  The following condensed proforma information gives effect to the acquisition as if it had occurred on January 1,2008.  The pro forma information has been included in the notes asrequired by generally accepted accounting principles and is provided forcomparison purposes only.  The pro forma financial information is notnecessarily indicative of the financial results that would have occurred hadthe acquisition been effective on the dates indicated and should not be viewedas indicative of operations in the future.

 
| ** **                        | ** ** | **Years Ended  December 31,** | ** ** |
|-----------------------------------|------------|------------------------------------|------------|
| ** **                        | ** ** | **2008**                           | ** ** |
| Operating revenues                |       | $                                  | 15,066,915 |   |
| Total operating expenses          |       | $                                  | 15,954,201 |   |
| Loss applicable to common stock   |       | $                                  | (1,239,749 | ) |
| Net loss per share — basic   |       | $                                  | (0.04      | ) |
| Net loss per share — diluted |       | $                                  | (0.04      | ) |

 

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The Plant consists of theoriginal facilities (currently in service) installed and made operational byHanover Compression Limited Partnership (“Hanover”) in 2003 and the expandedfacilities which were installed by MGP in 2007, but which have not yet beenplaced into operation.  The Plant’sprimary components consist of amine treaters, nitrogen rejection units,compressors and related equipment.  Otherassets acquired in the transaction include land, buildings, gathering lines,fuel lines, acid injection lines and rights of way.  The Plant facilities were installed in orderto treat and remove impurities associated with natural gas produced from theRodessa Formation at the Madisonville Field. The expanded facilities have a designed capacity to treat 50 million cubicfeet of natural gas per day (“MMcf/d”), which combined with the design capacityof the current in-service facilities of 18 MMcf/d will represent a totaltreating capacity of 68 MMcf/d for the Plant.

 

Prior to acquisition ofthe Plant, GeoPetro and MGP had certain agreements whereby MGP was responsiblefor the gathering, treating and marketing of GeoPetro’s gas production from theMadisonville Project.  The agreementsprovided, among other things, that MGP install and make operational theexpanded facilities.  The agreements andrelated obligations were terminated concurrent with GeoPetro’s acquisition ofthe Plant effective December 31, 2008.

 

**4.****                ****DEBT*:***

 

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

 
| ** **                                                       | ** ** | **December 31,  2009** | ** ** | **December 31,  2008** | ** ** |
|------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                       | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| Promissory notes dated December 23, 2008 (a)                |       | $                           | 1,050,000  |                        | $          | 1,050,000 |   |
| Promissory notes dated May 2009 (b)                         |       | 365,000                     |       | —                      |       |
| Promissory notes dated June 2009 (c)                        |       | 300,000                     |       | —                      |       |
| Bridge notes dated August, September, and  October 2009 (d) |       | 1,000,000                   |       | —                      |       |
| Bank of Oklahoma loan (e)                                        |       | 4,972,847                   |       | 6,697,847                   |       |
|                                                             |       | 7,687,847                   |       | 7,747,847                   |       |
| Less current portion of long term debt                           |       | (1,600,000                  | )          | (600,000                    | )          |
| Less discount on promissory notes relating to loan  fees         |       | (101,202                    | )          | (128,398                    | )          |
|                                                             |       | $                           | 5,986,645  |                        | $          | 7,019,449 |   |

 

----

(a)          The Company issued four promissory notestotaling $1,050,000 during December 2008 with maturity dates in December 2011.The notes may be repaid at any time without penalty. The notes bear an annualrate of eight percent (8%), with such interest payable quarterly in arrears.The principal amount and accrued and unpaid interest are due and payable on December 23,2011. In connection with the notes, the Company paid loan origination feestotaling $6,000 and granted three-year exercisable warrants to purchase 105,000Common Shares and reissued 15,000 warrants at $1.00 per share. We also issued150,000 warrants as a finder’s fee. The fair value of the warrants on the datesof issuance, $122,764 and the $6,000 of loan origination fees, was recorded asa debt discount and is being amortized over the life of the promissory note. Asof December 31, 2009, the unamortized debt discount was $85,476.

 

(b)         During May 2009 the Company borrowed $365,000pursuant to two separate three-year loans. The notes have maturity dates in May 2012. The notes may be repaid at any time without penalty.  The notes bearan annual rate of eight percent (8%), with such interest payable quarterly inarrears.  The principal amount and accrued and unpaid interest are due andpayable on May 2012.  In connection with the notes, the Companygranted three-year exercisable warrants to purchase 36,500 Common Shareswarrants at $1.00 per share. The fair value of the warrants on the dates ofissuance, $12,724, was recorded as a debt discount and is being amortized overthe life of the promissory note. As of December 31, 2009, the unamortizeddebt discount was $10,073.

 

(c)          In June 2009 the Company borrowed $300,000pursuant to two separate one-year loans. The two notes have maturity dates in June 2010. The notes may be repaid at any time without penalty.  The notes bearan annual rate of eight percent (8%), with such interest payable quarterly inarrears.  The principal amount and accrued and unpaid interest are due andpayable on June 2010.  In connection with the notes, the Companygranted three-year exercisable warrants to purchase 30,000 Common Shareswarrants at $1.00 per share. The fair value of the warrants on the dates ofissuance, $7,537, was recorded as a debt discount and is being amortized overthe life of the promissory note. On March 16, 2010, these two notes were 

 

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extended for  an additional one year and the new maturitydates are June 30, 2011. As of December 31, 2009, the unamortizeddebt discount was $5,652.

 

(d)         During August thru October 2009, the Companyborrowed $1,000,000 pursuant to five separate one-year bridge loans.  The notes have maturity dates in August 31, 2010and October 23, 2010.  The notes may be repaid at any time withoutpenalty.  The note bears an annual rateof ten percent (10%), with such interest payable at maturity.  Theprincipal amount and accrued and unpaid interest are due and payable on August 31, 2010and October 23, 2010.  In connection with the notes, the Companygranted three-year warrants exercisable to purchase 50,000 Common Shares at$1.00 per share. The fair value of the warrants on the dates of issuance,$25,367, was recorded as a debt discount and is being amortized over the lifeof the bridge note. As of December 31, 2009, the unamortized debt discountwas $19,507.

 

(e)          Effective December 31, 2008, the Company assumed$7,697,847 of Madisonville Gas Processing LP’s (“MGP”) bank debt related to theCompany’s acquisition of the Madisonville Gas Treatment Plant (the “Plant”) viaa (i) $1 million cash payment applied directly towards debt principalreduction, and (ii) a refinancing by GeoPetro of the $6,697,847 remainingbalance in the form of a 3 year Amended and Restated Term Loan Agreement withthe lender, Bank Oklahoma (“BOK”).  Theterms of the three year loan provide for minimum quarterly principal paymentsof $150,000 and interest payable quarterly in arrears at prime plus 4% or Liborplus 5.5% at the option of the Company. At December 31, 2009, the interestrate was 5.78% (LIBOR + 5.5%). Additional principal will be payable upon GeoPetro meeting certain netoperating cash flow thresholds during the three year term of the loan.  The loan is secured by a first lien on theMadisonville Midstream Plant and all of the Company’s proved natural gasreserves located at the Madisonville Project. In addition, GeoPetro has agreed to pay, at the time the loan is repaidin full, a loan origination fee of $60,000 for any annual period during whichthe loan principal remains outstanding. There is no prepayment penalty. The Amended and Restated Term Loan Agreement contains customaryaffirmative and negative covenants including restrictions on incurringadditional debt and requiring that the Company maintain a minimum tangible networth of at least $35,000,000. The Company’s tangible net worth was less than$35 million at December 31, 2009 due to the impairment write-down of $19.8million in the US cost pool. On March 25, 2010, BOK waived compliance ofthe covenant as of December 31, 2009 and lowered the minimum tangible networth requirement from the current $35 million to $18 million.

 

**5.**                 **INCOME TAXES:**

 

The Company files incometax returns in the U.S. federal jurisdiction and various states.  There are currently no federal or stateincome tax examinations underway. Furthermore, the Company is no longer subject to U.S. federal income taxexaminations by the Internal Revenue Service for tax years before 2006 and forstate and local tax authorities for tax years before 2005.  The Company does, however, have net operatinglosses generated in tax years 1997 and after, which remain open forexamination.

 

The Company adopted theprovisions of ASC 740, Accounting for Uncertainty in Income Taxes (formerly SFAS109 and FIN 48), on January 1, 2007. As of December 31, 2009 theCompany had no unrecognized tax benefits. There have been no changes during theyear with respect to unrecognized tax benefits. The Company does not foresee the total amounts of unrecognized taxbenefits significantly increasing within the next 12 months.  Furthermore, no corresponding interest andpenalties have been accrued as the Company is in a net operating loss position.

 

ASC 740 requires therecognition of deferred tax assets and liabilities for the expected future taxconsequences of temporary differences between the financial statement carryingamounts and the tax basis of the assets and liabilities. Where it is morelikely than not that a tax benefit will not be realized, a valuation allowanceis recorded to reduce the deferred tax asset to its realizable value.

 

A valuation allowance hasbeen provided against the Company’s net deferred tax assets as the Companybelieves that it is more likely than not that the net deferred tax assets willnot be realized.

 

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The effective tax ratefor the year ended December 31, 2009 is negligible.

 
| ** **                 | ** ** | **2009** | ** ** | **2008** | ** ** |
|----------------------------|------------|----------|------------|----------|------------|
| Current                    |       |     |       |     |       |
| Federal                    |       | $        | —     |     | $          | — |   |
| State                      |       | 2,100    |       | 13,000   |       |
| Total                      |       | 2,100    |       | 13,000   |       |
|                       |       |     |       |     |       |
| Deferred                   |       |     |       |     |       |
| Federal                    |       | —   |       | —   |       |
| State                      |       | —   |       | —   |       |
| Total                      |       | —   |       | —   |       |
| Total Income Tax Provision |       | $        | 2,100      |     | $          | 13,000 |   |

 

The actual income tax(benefit) expense differs from the expected tax (benefit) expense as computedby applying the U.S. Federal corporate income tax rate of 35% for each periodas follows:

 
| ** **                               | ** ** | **2009**  | ** ** | **2008** | ** ** |
|------------------------------------------|------------|-----------|------------|----------|------------|
| Amount of expected tax (benefit) expense |       | $         | (9,096,000 | )        | $          | (57,000 | ) |
| Non-deductible expenses                  |       | 69,000    |       | 16,000   |       |
| Alternative minimum tax                  |       | —    |       | —   |       |
| State Taxes                              |       | 2,100     |       | 1,600    |       |
| Other                                    |       | —    |       | 2,400    |       |
| Valuation allowance adjustments          |       | 9,027,000 |       | 50,000   |       |
|                                     |       | $         | 2,100      |     | $          | 13,000 |   |

 

Deferred income taxesreflect the net tax effects of temporary differences between carrying amountsof assets and liabilities for financial reporting purposes and the amounts usedfor income tax purposes. Significant components of the Company’s deferred taxassets (liabilities) are as follows:

 
| ** **                             | ** ** | **2009**    | ** ** | **2008**   | ** ** |
|----------------------------------------|------------|-------------|------------|------------|------------|
| Deferred tax assets (liabilities):     |       |        |       |       |       |
| Net operating loss carry forwards      |       | $           | 10,460,000 |       | $          | 8,294,000 |   |
| Oil and gas property basis differences |       | 2,795,000   |       | (5,071,000 | )          |
| Stock compensation                     |       | 330,000     |       | 189,000    |       |
| Other                                  |       | (749,000    | )          | (96,000    | )          |
| Total deferred tax assets              |       | 12,836,000  |       | 3,316,000  |       |
| Valuation allowance                    |       | (12,836,000 | )          | (3,316,000 | )          |
| Total net deferred taxes               |       | $           | —     |       | $          | — |   |

 

As of December 31,2009, GeoPetro had net operating loss (NOL) carryforwards of approximately $31,991,000for federal income tax purposes which begin to expire in 2017.  If the Company were to experience a change inownership under Section 382, the Company may be limited in its ability tofully utilize its net operating losses.

 

However, in accordancewith ASC 718 (formerly SFAS 123(R)), a deferred tax asset has not beenrecognized for the portion of the net operating loss carryforwards that isattributable to excess tax deductions associated with the exercise of stockoptions which do not reduce income taxes payable. Accordingly, approximately$3,536,000 of GeoPetro’s federal NOL has not been benefited for financialstatement purposes as it relates to excess tax deductions that have not reducedincome taxes payable. The benefit of these excess tax deductions will not berecognized for financial statement purposes until the related deductions reduceincome taxes payable.

 

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The Company also hasapproximately $10,258,000 of California net operating losses and approximately$551,000 of Alaska net operating losses which begin to expire in 2010 and 2026,respectively. In accordance with ASC 718, a portion of the state NOLs hassimilarly not been benefited for financial statement purposes as it relates toexcess tax deductions which have not resulted in the reduction of income taxespayable. The benefit of such excess tax deductions will not be recognized forfinancial statement purposes until the related deductions reduce state incometaxes payable.

 

In addition, the Companyhas approximately $334,000 of carryforward credits in Texas, a portion of whichmay be utilized each year against Texas Margin Tax liability through 2027.

 

**6.**                 **RELATED PARTY TRANSACTIONS*:***

 

On June 18, 2009 andAugust 12, 2009, Stuart J. Doshi, President and CEO, made loans to theCompany totaling $132,000. The notes accrued interest at 8% annually and waspayable on demand. The notes and accrued interest were repaid on August 20,2009 and September 14, 2009, respectively.

 

**7.**                 **SHAREHOLDERS’ EQUITY*:***

 

GeoPetro’s articles ofincorporation allow for the issuance of 100,000,000 shares of common stock,1,000,000 shares of Series A preferred stock (“Series A Stock”),5,000,000 shares of Series AA preferred stock (“Series AA Stock”),and an additional 44,000,000 shares of preferred stock which may be issued fromtime to time in one or more series.

 

*CommonStock**—*Theholders of common stock are entitled to one vote per share. Subject topreferences on outstanding preferred stock, the holders of common stock areentitled to receive ratably such dividends as may be declared by the board ofdirectors. In 

 

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the event of aliquidation, the holders of common stock and Series A preferred stock areentitled to share ratably in all assets remaining after payment of liabilities,subject to prior distribution rights of preferred stock.

 

*Series BPreferred Stock**—* Thereare presently 7,523,000 shares of Series B Stock issued andoutstanding.  The holders of Series BStock are entitled to receive an annual dividend at the rate of $0.06 per shareand are entitled to such number of votes per share as equals the number ofcommon shares into which each share of Series B Stock is convertible. Eachshare of Series B Stock is convertible, at the option of the holder, intofully paid and non-assessable common shares on a one-for-one basis, subject tocertain adjustments. The Series B Stock will automatically convert intocommon shares on a one-for-one share basis effective the first trading dayafter the reported high selling price for the Company’s common shares on anyinternational, national or regional securities exchange or inter-dealerquotation system including but not limited to, NASDAQ, the Pink Sheets or theOver-the-Counter Bulletin Board, is at least $1.50 per share for any tenconsecutive trading days. If an automatic conversion occurs within one yearafter the Series B Stock was purchased from the Company, a holder willreceive, on the one-year anniversary date of his, her or its purchase, a cashdividend equivalent to a full year of dividends less any dividends paid beforesuch conversion. In 2009, we incurred $179,045 in dividends on the Series BStock, of which $68,583 had been paid as of December 31, 2009.

 

**8.**                 **COMMON STOCK OPTIONS*:***

 

Effective as of September 10,2001, the board of directors approved an incentive stock plan, providing forawards under the terms and provisions of such plan of incentive stock options,stock appreciation rights and restricted stock awards to officers, directorsand employees of GeoPetro and its consultants (the “Stock Incentive Plan”). Theplan provides, among other provisions, the following:

 

The maximum number ofCommon Shares which may be awarded, optioned and sold under the plan is5,000,000 (subject to adjustment for stock splits, stock dividends and certainother adjustments to GeoPetro’s common stock); and the per share exercise pricefor Common Shares to be issued pursuant to the exercise of an option shall beno less than the fair market value of GeoPetro’s Common Shares as of the dateof grant.

 

The Stock Incentive Planprovides for the granting to employees incentive stock options within themeaning of Section 422 of the United States Internal Revenue Code of 1986,as amended, and for the granting of non-statutory stock options to directorswho are not employees and consultants. In the case of employees who receiveincentive stock options which are first exercisable in a particular calendaryear and the aggregate fair market value of which exceeds $100,000, the excessof the $100,000 limitation shall be treated as a nonstatutory stock optionunder the Stock Incentive Plan.

 

The Stock Incentive Planis being administered by the Board of Directors. The Board of Directorsdetermines the terms of the options granted, including the number of CommonShares subject to each option, the exercisability and vesting requirements ofeach option, and the form of consideration payable upon the exercise of suchoption (i.e., whether cash or exchange of existing Common Shares in a cashlesstransaction or a combination thereof).

 

The Stock Incentive Planwill continue in effect for 10 years from September 10, 2001 (i.e., thedate first adopted by the Board), unless sooner terminated by the board ofdirectors. In 2004, we implemented a new 2004 Stock Option and AppreciationRights Plan (the “Stock Option Plan”) providing for awards of incentive stockoptions, non-qualified stock options and stock appreciation rights. The StockOption Plan replaced the Stock Incentive Plan as to new award grants effectivein 2004 or thereafter to our directors, officers, employees and consultants.Outstanding awards issued under the Stock Incentive Plan will continue to beoutstanding in accordance with their terms and the terms of the Stock IncentivePlan, but will count toward the limits in the number of shares of common stockavailable to be issued under the Stock Option Plan, which is 5,000,000. Theexercise price of stock options granted under the Stock Option Plan may not beless than 110% of the fair market value of our common stock on the date ofgrant.

 

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During 2008, the Companyissued 820,000 of stock options to officers, directors and employees, whichwere exercisable at $4.28 per share.

 

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

 

The Company recordedstock compensation expense of $403,963 and $268,723 for the twelve monthsperiod ended December 31, 2009 and 2008, respectively.

 

A summary of the statusof GeoPetro’s stock option plan is as follows:

 
| ** **                            | ** ** | **Options** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|---------------------------------------|------------|-------------|------------|----------------------|------------|------------------------------------------------|------------|
| Outstanding at January 1, 2008        |       | 2,670,000   |       | $0.50 to $6.25       |       | $                                              | 1.77       |   |
| Granted                               |       | 820,000     |       | $4.28                |       | 4.28                                           |       |
| Exercised                             |       | (750,000    | )          | $0.50                |       | 0.50                                           |       |
| Expired                               |       | —      |       | —               |       | —                                         |       |
| Outstanding at December 31, 2008 |       | 2,740,000   |       | $2.10 to $6.25       |       | 2.87                                           |       |
| Granted                               |       | 60,000      |       | $1.00                |       | 1.00                                           |       |
| Exercised                             |       | —      |       | —               |       | —                                         |       |
| Canceled                              |       | (80,000     | )          | $4.28                |       | 4.28                                           |       |
| Outstanding at December 31, 2009 |       | 2,720,000   |       | $1.00 to $6.25       |       | $                                              | 2.73       |   |

 

We estimated the fairvalues of each option granted using the Black-Scholes model with the followingassumptions for options granted during the years ended December 31:

 
| ** **                              | ** ** | **2009** | ** ** | **2008**     | ** ** |
|-----------------------------------------|------------|----------|------------|--------------|------------|
| Expected dividend yield                 |       | —   |       | —       |       |
| Expected volatility                     |       | 113.0%   |       | 66.0%        |       |
| Risk-free interest rates                |       | 2.53%    |       | 3.5% to 4.9% |       |
| Expected lives                          |       | 5 years  |       | 5 years      |       |
| Weighted  average fair values per share |       | $0.33    |       | $2.17        |       |

 

We estimated the dividendyield at 0% considering that we have not historically paid dividends on ourcommon stock, nor do we expect to pay dividends in the future.  Volatility estimates represent the historictrading volatility underlying our common stock at the date of grant.  We estimated risk-free interest rates basedon the U.S. Treasury yield curve at the date of grant.  Expected lives are based on our historicexperience with employee option exercise behavior and consider the vestingperiod and the contractual lives of the related options.

 

The options outstandingas of December 31, 2009 have the following contractual lives:

 
| **Number of  Options  Outstanding** | ** ** | **Number of  Options  Exercisable** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Remaining  Contractual Life** | ** ** |
|------------------------------------------|------------|------------------------------------------|------------|----------------------|------------|-------------------------------------------------------------|------------|
| 210,000                                  |       | 150,000                                  |       | 1.00                 |       | 4.26                                                        |       |
| 1,600,000                                |       | 1,600,000                                |       | 2.10                 |       | 3.43                                                        |       |
| 150,000                                  |       | 90,000                                   |       | 3.85                 |       | 1.29                                                        |       |
| 10,000                                   |       | 8,000                                    |       | 4.25                 |       | 0.01                                                        |       |
| 740,000                                  |       | 148,000                                  |       | 4.28                 |       | 3.49                                                        |       |
| 10,000                                   |       | 8,000                                    |       | 6.25                 |       | 0.44                                                        |       |
| 2,720,000                                |       | 2,004,000                                |       |                 |       |                                                        |       |

 

The total intrinsic valueof options outstanding was $0.00 at December 31, 2009 and 2008,respectively. The intrinsic value for exercisable options was $0.00 at December 31,2009 and 2008, respectively. The total intrinsic value for stock optionsexercised was $0 and approximately $172,500 for the years ended December 31,2009 and 2008, respectively.

 

As of December 31,2009, there are 2,004,000 options which are exercisable. The remaining 716,000options will become exercisable over the next four years. The stockcompensation expense related to the unvested awards is $1,209,781.

 

As of December 31,2009, the available issuable options are 2,280,000 shares.

 

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**9.**                 **COMMON STOCK WARRANTS:**

 

During October 2009,the Company issued warrants to purchase 157,690 shares of common stock to anon-related parties expiring September 30, 2011 and October 19, 2014,with a strike price of $1.00 per share. The grant-date fair value of the warrants amounted to $97,144, using theBlack-Scholes valuation method, was recorded as finder’s fee and offsetadditional paid in capital.

 

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

 

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

 

On February 23, 2009and October 8, 2009, the Company issued warrants to purchase 98,500 sharesof common stock to a non-related party expiring February 22, 2012 and October 18,2012 with a strike price of $1.00 to $1.25 per share. Warrants granted shallvest according the following schedule: 25% immediately; 25% at the three monthanniversary of the signing of the agreement; 25% at the six month anniversaryof the signing of the agreement; and 25% at the nine month anniversary of thesigning of the agreement. The grant-date fair value of the warrants amounted to$55,893, using the Black-Scholes valuation method, which is recognized ingeneral and administrative expense on our consolidated statement of operationsratably over the requisite service period as defined by the vesting scheduleabove.

 

During 2008, the Companyissued three-year exercisable common stock warrants to purchase 105,000 CommonShares and reissued 15,000 warrants at $1.00 per share in conjunction with theissuance of certain promissory notes payable. The purchase right under thewarrants has expiration dates of December 22, 2011, December 23,2011, and December 25, 2011 unless terminated earlier in accordance withthe stock warrant purchase agreement. On January 9, 2009, the Companyissued 150,000 warrants as a finder’s fee related to certain promissory notes.The fair value of the warrants issued on the dates of grant of $122,764 and theorigination fees of $6,000 were recorded as discount to notes payable and arebeing amortized as interest expense over the term of the notes.

 

On December 15,2008, the Company extended the date of expiration on 114,000 warrants to December 15,2010. The warrants were issued as a finder fee for a 2003 private placement ofthe Company’s common shares. The fair value of the warrants extension of$17,507 was recorded as finder’s fee and offset additional paid in capital.

 

On July 2, 2008, theCompany issued 83,676 shares of common stock pursuant to a cashless exercise of175,125 common stock warrants.

 

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The following tablesummarizes the number of shares reserved for the exercise of common stockpurchase warrants as of December 31, 2009:

 
| ** **    | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **Outstanding at** | ** ** | **Warrants**  | ** ** | **Warrants** | ** ** | **Warrants**           | ** ** | **Outstanding at** | ** ** |
|---------------|------------|----------------|------------|--------------|------------|-------------------------|------------|---------------|------------|--------------|------------|------------------------|------------|-------------------------|------------|
| ** **    | ** ** | **Date**       | ** ** | **Price**    | ** ** | **12/31/2008**          | ** ** | **Exercised** | ** ** | **Granted**  | ** ** | **(Expired/Canceled)** | ** ** | **12/31/2009**          | ** ** |
|          |       |           |       |         |       |                    |       |          |       |         |       |                   |       |                    |       |
| Common  Stock |       | 01/31/09       |       | $            | 3.50       |                    | 150,000    |          | —     |         | —     |                   | (150,000   | )                       | —     |   |
| Common  Stock |       | 02/12/09       |       | $            | 3.50       |                    | 20,000     |          | —     |         | —     |                   | (20,000    | )                       | —     |   |
| Common  Stock |       | 02/28/09       |       | $            | 4.51       |                    | 5,000      |          | —     |         | —     |                   | (5,000     | )                       | —     |   |
| Common  Stock |       | 01/31/10       |       | $            | 3.50       |                    | 80,000     |          | —     |         | —     |                   | —     |                    | 80,000     |   |
| Common  Stock |       | 08/13/10       |       | $            | 3.85       |                    | 60,078     |          | —     |         | —     |                   | —     |                    | 60,078     |   |
| Common  Stock |       | 09/30/11       |       | $            | 1.00       |                    | —     |          | —     |         | 27,150     |                   | —     |                    | 27,150     |   |
| Common  Stock |       | 12/15/11       |       | $            | 3.50       |                    | 114,000    |          | —     |         | —     |                   | —     |                    | 114,000    |   |
| Common  Stock |       | 12/22/11       |       | $            | 1.00       |                    | 35,000     |          | —     |         | —     |                   | —     |                    | 35,000     |   |
| Common  Stock |       | 12/23/11       |       | $            | 1.00       |                    | 45,000     |          | —     |         | —     |                   | —     |                    | 45,000     |   |
| Common  Stock |       | 12/25/11       |       | $            | 1.00       |                    | 40,000     |          | —     |         | —     |                   | —     |                    | 40,000     |   |
| Common  Stock |       | 02/22/12       |       | $            | 1.00       |                    | —     |          |       |         | 50,000     |                   | —     |                    | 50,000     |   |
| Common  Stock |       | 01/12/12       |       | $            | 1.00       |                    | —     |          |       |         | 150,000    |                   | —     |                    | 150,000    |   |
| Common  Stock |       | 05/17/12       |       | $            | 1.00       |                    | —     |          |       |         | 36,500     |                   | —     |                    | 36,500     |   |
| Common  Stock |       | 06/29/12       |       | $            | 1.00       |                    | —     |          |       |         | 30,000     |                   | —     |                    | 30,000     |   |
| Common  Stock |       | 08/13/12       |       | $            | 4.50       |                    | 600,779    |          | —     |         | —     |                   | —     |                    | 600,779    |   |
| Common  Stock |       | 09/30/12       |       | $            | 1.00       |                    | —     |          |       |         | 14,000     |                   | —     |                    | 14,000     |   |
| Common  Stock |       | 10/22/12       |       | $            | 1.00       |                    | —     |          |       |         | 36,000     |                   | —     |                    | 36,000     |   |
| Common  Stock |       | 11/22/12       |       | $            | 1.25       |                    | —     |          |       |         | 12,500     |                   | —     |                    | 12,500     |   |
| Common  Stock |       | 03/31/14       |       | $            | 5.25       |                    | 100,000    |          | —     |         | —     |                   | —     |                    | 100,000    |   |
| Common  Stock |       | 10/19/14       |       | $            | 1.00       |                    | —     |          |       |         | 130,540    |                   | —     |                    | 130,540    |   |
|          |       |           |       |         |       |                    |       |          |       |         |       |                   |       |                    |       |
|          |       |           |       |         |       |                    |       |          |       |         |       | —                 |       |                    |       |
|          |       |           |       |         |       | 1,249,857               |       | —        |       | 486,690      |       | (175,000               | )          | 1,561,547               |       |

 

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The following tablesummarizes the number of shares reserved for the exercise of common stockpurchase warrants as of December 31, 2008:

 
| ** **         | ** ** | ** **     | ** ** | ** **   | ** ** | ** **                    | ** ** | ** **    | ** ** | **Warrants** | ** ** | **Warrants**  | ** ** | ** **              | ** ** |
|--------------------|------------|----------------|------------|--------------|------------|-------------------------------|------------|---------------|------------|--------------|------------|---------------|------------|-------------------------|------------|
| ** **         | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **Outstanding at**       | ** ** | **Warrants**  | ** ** | **Granted/** | ** ** | **(Expired/** | ** ** | **Outstanding at** | ** ** |
| ** **         | ** ** | **Date**       | ** ** | **Price**    | ** ** | **January 1, 2008** | ** ** | **Exercised** | ** ** | **Extended** | ** ** | **Canceled)** | ** ** | **12/31/2008**          | ** ** |
|               |       |           |       |         |       |                          |       |          |       |         |       |          |       |                    |       |
| Common Stock       |       | 02/28/08       |       | $            | 5.00       |                          | 27,000     |          | —     |         | —     |          | (27,000    | )                       | —     |   |
| Common Stock       |       | 07/19/08       |       | $            | 5.00       |                          | 50,000     |          | —     |         | —     |          | (50,000    | )                       | —     |   |
| Common Stock       |       | 09/30/08       |       | $            | 5.00       |                          | 14,375     |          | —     |         | —     |          | (14,375    | )                       | —     |   |
| Common Stock       |       | 12/15/08       |       | $            | 3.50       |                          | 1,100,998  |          | —     |         | —     |          | (1,100,998 | )                       | —     |   |
| Common Stock       |       | 01/31/09       |       | $            | 3.50       |                          | 150,000    |          | —     |         | —     |          | —     |                    | 150,000    |   |
| Common Stock       |       | 02/12/09       |       | $            | 3.50       |                          | 20,000     |          | —     |         | —     |          | —     |                    | 20,000     |   |
| Common Stock       |       | 02/28/09       |       | $            | 4.51       |                          | 5,000      |          | —     |         | —     |          | —     |                    | 5,000      |   |
| Common Stock       |       | 03/31/09       |       | $            | 5.25       |                          | 100,000    |          | —     |         | —     |          | —     |                    | 100,000    |   |
| Common Stock       |       | 12/15/10       |       | $            | 3.50       |                          | —     |          | —     |         | 114,000    |          | —     |                    | 114,000    |   |
| Common Stock       |       | 01/31/10       |       | $            | 3.50       |                          | 95,000     |          | —     |         | —     |          | (15,000    | )                       | 80,000     |   |
| Common Stock       |       | 08/13/10       |       | $            | 3.85       |                          | 60,078     |          | —     |         | —     |          | —     |                    | 60,078     |   |
| Common Stock       |       | 12/22/11       |       | $            | 1.00       |                          | —     |          | —     |         | 35,000     |          | —     |                    | 35,000     |   |
| Common Stock       |       | 12/23/11       |       | $            | 1.00       |                          | —     |          | —     |         | 45,000     |          | —     |                    | 45,000     |   |
| Common Stock       |       | 12/25/11       |       | $            | 1.00       |                          | —     |          | —     |         | 40,000     |          | —     |                    | 40,000     |   |
| Common Stock       |       | 08/13/12       |       | $            | 4.50       |                          | 600,779    |          | —     |         | —     |          | —     |                    | 600,779    |   |
|               |       |           |       |         |       |                          |       |          |       |         |       |          |       |                    |       |
| **Related party:** | ** ** | ** **     | ** ** | ** **   | ** ** | ** **                    | ** ** | ** **    | ** ** | ** **   | ** ** | ** **    | ** ** | ** **              | ** ** |
| Common Stock       |       | 04/30/08       |       | $            | 3.00       |                          | 33,333     |          | —     |         | —     |          | (33,333    | )                       | —     |   |
| Common Stock       |       | 12/31/08       |       | $            | 2.00       |                          | 185,125    |          | (175,125   | )            | —     |          | (10,000    | )                       | —     |   |
|               |       |           |       |         |       |                          |       |          |       |         |       |          |       |                    |       |
|               |       |           |       |         |       | 2,441,688                     |       | (175,125      | )          | 234,000      |       | (1,250,706    | )          | 1,249,857               |       |

 

**10.****         ****COMMITMENTS AND CONTINGENCIES*:***

 

*EmploymentAgreements*—TheCompany entered into a contract of employment with Stuart J. Doshi, Founder,President, Chief Executive Officer and Chairman of the Board of Directors, asamended through December 31, 2008. The contract, as amended, provides fora five-year term commencing May 1, 2005 which term is automaticallyextended for successive two-year renewal terms unless: (a) the board ofdirectors elects not to renew the contract and the Company provides notice to Mr. Doshiof such non-renewal at least six months prior to the expiry of his employmentterm or any renewal term, or (b) Mr. Doshi attains age 75, inwhich case the term ends upon the completion of the calendar year in which hebecomes 75 years old unless the Company and Mr. Doshi mutually agreeto one-year extensions. The contract of employment currently provides for anannual base salary of $300,000 and further provides that in the event of achange of control of the Company or if Mr. Doshi is terminated withoutcause, he is entitled to receive (a) in exchange for all of his vestedstock options and vested restricted shares, such number of Common Shares havinga market value equal to the difference between (x) the aggregatetotal market value of all vested restricted shares and Common Shares he wouldreceive upon exercise of all vested stock options less (y) theaggregate total exercise price for all of his vested stock options; provided,however, that if the Common Shares to be delivered to Mr. Doshi upon suchchange of control or termination have not been registered so as to permitimmediate public resale, Mr. Doshi shall instead receive a cash paymentequal to the market value on the date of termination of all vested stockoptions and restricted shares without any discount for liquidity or minorityposition against cancellation of such options and restricted shares, (b) acash payment equal to the greater of (i) his compensation for theremainder of his term, including salary and the aggregate amount of his bonusesin respect of the last four fiscal years and (ii) four times hiscompensation in the current year, including his then-current salary and theaverage amount of his bonuses for the last four fiscal years, and (c) anadditional cash payment representing his employment benefits equal to 20% ofthe amount of salary he is entitled to receive under (b)(i) or (b)(ii) above,as applicable. In addition, in the event of a change of control or terminationwithout cause, all unvested options issued by the Company to Mr. Doshiwill vest.

 

GeoPetro has executed anemployment contract as amended through December 31, 2008 with its VicePresident of Exploration, David V. Creel. The contract provides an annualsalary of $163,200 and may be terminated by GeoPetro without cause upon thepayment to Mr. Creel of cash payments 

 

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equal to the lesser ofthree months’ base salary or base salary during the remainder of the employmentterm, and, in the event of termination without cause, all unvested optionsissued by GeoPetro to Mr. Creel will vest.

 

GeoPetro has executed anemployment contract dated April 27, 2009 with its Chief Financial Officer,J. Chris Steinhauser. The contract provides an annual salary of $225,000 andmay be terminated by GeoPetro without cause upon the payment to Mr. Steinhauserof cash payments equal to the lesser of nine months’ base salary or base salaryduring the remainder of the employment term.

 

*OfficeLease**—*The Company leases its San Francisco, CA office spaceunder a non-cancelable operating loss arrangement expiring in April 2010. Minimum annual rentals due under thisagreement as of December 31, 2009 amounted to $31,038. See Note 11.

 

Rent expense for theyears ended December 31, 2009 and 2008, was approximately $90,651 and$78,334, respectively, and is included in general and administrative expensesin the accompanying statements of operations.

 

*MadisonvilleNet Profits Interest**—*Redwood LP’s 100% working interest is subject to a netprofits interest in favor of unrelated third parties. The net profits interestis 12.5% (proportionately reduced) of the net operating profits until payout isachieved. After payout, the net profits interest increases to 30%(proportionately reduced). Payout, for purposes of the net profits interest, isdefined and achieved at such time as Redwood LP has recouped from net operatingcash flows its total net investment in the project plus a 33% cash on cashreturn.

 

*DevonLawsuit**—-*On September 11,2009, the Company’s subsidiary, Redwood Energy Production, L.P. (“Redwood”) filedan Original Petition for Declaratory Judgment against Devon Energy ProductionCompany (“Devon”) regarding certain overriding royalty interests and relatedrevenue amounts claimed by Devon.  In the context of this lawsuit, Devonhas asserted a claim for the past due royalties held by Redwood in a suspenseaccount.  The Company previously accruedall amounts owed pursuant to these overriding royalty interests as royaltyowners payable.  In the opinion of management based on consultation withlegal counsel, these proceedings are not expected to have a material adverseeffect on our financial condition or results of operations.

 

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**11.****         ****SUBSEQUENT EVENTS:**

 

We have evaluatedsubsequent events through the date on which these financial statements werefiled.

 

*NewOffice Lease**:*On February 15,2010, we entered into a new lease for our principal executive office to belocated at 150 California Street, Suite 600, San Francisco, CA 94111.  The terms of the lease provide for an eighty-four(84) month term. Minimum annual rentals due under this agreement are asfollows:

 

 

| 2010   |   | 95,223  | *         |
|--------|--------|---------|-----------|
| 2011   |   | 145,635 |      |
| 2012   |   | 149,836 |      |
| 2013   |   | 154,037 |      |
| 2014   |   | 158,238 |      |
| 2015   |   | 162,439 |      |
| 2016   |   | 166,640 |      |
| 2017   |   | 56,013  |      |
|   |   |    |      |
| Total  |   | $       | 1,088,061 |   |
|        |        |         |           |  |

 

----

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

 

*Sale ofAlaskan Leases**:*On February 26,2010, we sold our entire working interest in our Alaskan leases to Linc Energy(Alaska) Inc. (“Linc”).  Linc is awholly-owned subsidiary of Linc Energy Ltd., an Australian-based companypublicly traded on the Australian Stock Exchange.

 

Linc will acquire all ofthe Alaskan Leases for the following consideration:

 

f.                                         A cash payment of $1.0 million will bedeposited by Linc in an escrow account, to be released to us upon approval ofthe assignments of the Alaskan leases to Linc.

 

g.                                      In addition, we will receive a $4.0million payment from the first 75% of 8/8ths of the proceeds from any oil andgas production from the Alaskan leases.

 

h.                                      After we have received the $4.0 millionpayment specified in paragraph (b) above, we will thereafter receive anoverriding royalty interest of 10% of 8/8ths in and to the Alaskan leasesissued by the State of Alaska and the Alaska Mental Health Trust (whichcomprise over 99% of the Alaskan Leases), and an overriding royalty interest of7% of 8/8ths in and to the Alaskan Leases issued by Cook Inlet Region, Inc.on conventional oil and gas production and coal bed methane production.

 

i.                                          Linc has agreed to pay all of the costsof maintaining the Alaskan leases at least through the end of the primary termsthereof.

 

j.                                          Following the lessors’ approval of theassignments of the Alaskan leases into Linc, Linc will diligently commence andprosecute the drilling of the Frontier Spirit #1 exploration well to evaluate aconventional oil and gas prospect identified and developed by us.

 

*Bank ofOklahoma Loan Agreement Amendment*:  Our Amended andRestated Term Loan Agreement with our lender, Bank Oklahoma (“BOK”) was amendedon March 25, 2010.  Our originalAmended and Restated Term Loan Agreement contained customary affirmative andnegative covenants including restrictions on incurring additional debt andrequiring that the Company maintain a minimum tangible net worth of at least$35,000,000. The Company’s tangible net worth was less than $35 million at December 31,2009 due to the impairment write-down of $19.8 million in the US cost pool. BOKwaived compliance of the covenant as of December 31, 2009 and lowered theminimum tangible net worth requirement from the current $35 million to $18million as of the March 25, 2010 amendment.

 

**12.****         ****SUPPLEMENTARY OIL AND GAS RESERVEINFORMATION: (UNAUDITED)**

 

The reserve quantitiesand valuations are based upon estimates by MHA Petroleum Consultants. Theproved reserves presented herein are located entirely within theUnited States. Proved reserves are the estimated quantities of crude oil,natural gas and natural gas liquids which geological and engineering datademonstrate with reasonable certainty to be recoverable in future years fromknown reservoirs under existing economic and operating conditions, i.e. pricesand costs as of the date the estimate is made. For year-end 2009, new SEC rules wereimplemented requiring that reserve calculations be based on the un-weightedaverage 

 

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first-day-of-the-monthprices for the prior twelve months, as contrasted with the previous methodwhich utilized period end prices.  The prices under the new rules were$3.11 per Mcf for natural gas adjusted for energycontent, quality and basis differentials. By contrast, the price prevailing on December 31, 2009 of $5.45 perMcf.  Prices include consideration ofchanges in existing prices provided only by contractual arrangements, but noton escalations based upon future conditions. Reservoirs are considered provedif economic productivity is supported by either actual production or aconclusive formation test. The area of a reservoir considered proved includes (A) thatportion delineated by drilling and defined by gas-oil and/or oil-watercontacts, if any, and (B) the immediately adjoining portions not yetdrilled, but which can reasonably be judged as economically productive on thebasis of available geological and engineering data. In the absence ofinformation on fluid contacts the lowest known structural occurrence ofhydrocarbons controls the lower proved limit of the reservoir.

 

Proved developed reservesare reserves that can be expected to be recovered through existing wells withexisting equipment and operating methods. Additional oil and gas reservesexpected to be obtained through the application of fluid injection or otherimproved recovery techniques for supplementing the natural forces andmechanisms of primary recovery should be included as “proved developed reserves”only after testing by a pilot project or after the operation of an installedprogram has confirmed through production response that increased recovery willbe achieved.

 

The estimates included inthe following tables are by their nature inexact and are subject to changingeconomic, operating and contractual conditions. At December 31, 2009, allof GeoPetro’s reserves are attributable to three producing wells, one shut-inwell and an undeveloped location. Other than the producing wells and oneshut-in well, there is no other production history as of or subsequent to thatdate. Reserve estimates for these wells are subject to substantial upward ordownward revisions after production commences and a production history isobtained.   Accordingly, reserveestimates of future net revenues from production may be subject to substantialrevision from year to year. Reserve information presented herein is based onreports prepared by independent petroleum engineers.

 

The assumptions used tocompute the standardized measure are those prescribed by the FinancialAccounting Standards Board and, as such, do not necessarily reflect GeoPetro’sexpectations for actual revenues to be derived from those reserves nor theirpresent worth. The limitations inherent in the reserve quantity estimationprocess, as discussed previously, are equally applicable to the standardizedmeasure computations since these are the basis for the valuation process.

 
| ** **                                    | ** ** | **Natural Gas  (Mcf)** | ** ** |
|-----------------------------------------------|------------|------------------------|------------|
| PROVED-DEVELOPED  AND UNDEVELOPED RESERVES:   |       |                   |       |
| January 1,  2008                         |       | 23,139                 |       |
| Revisions  of previous estimates              |       | (1,553                 | )          |
| Extensions,  discoveries, and other additions |       | —                 |       |
| Sale  of reserves                             |       | —                 |       |
| Production                                    |       | (1,116                 | )          |
| December 31,  2008                       |       | 20,470                 |       |
| Revisions  of previous estimates              |       | (6,280                 | )          |
| Extensions,  discoveries, and other additions |       | 5,249                  |       |
| Sale  of reserves                             |       | —                 |       |
| Production                                    |       | (807                   | )          |
| December 31,  2009                       |       | 18,632                 |       |

 

**PROVEDRESERVES PRESENTED HEREIN ARE LOCATED ENTIRELY WITHIN THE UNITED STATES**

 
| ** **                     | ** ** | ** ** | **2009**   | ** ** | **2008**   | ** ** |
|--------------------------------|------------|------------|------------|------------|------------|------------|
| ** **                     | ** ** | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
| Proved developed               |       |       | 3,651      |       | 17,300     |       |
| Proved developed non-producing |       |       | 6,611      |       | 3,170      |       |
| Proved undeveloped             |       |       | 8,371      |       | —     |       |
|                           |       |       |       |       |       |       |
| Total                          |       |       | 18,632     |       | 20,470     |       |

 

The downward revision of previous estimates of naturalgas reserves during 2009 of 6,280 MMcf is primarily associated with performancerevisions attributable to the Fannin #1 well. The remainder of the downwardrevision of previous estimates is attributable to lower natural gas prices ascalculated under the new SEC pricing methodology. Natural gas prices utilizingthe new SEC price methodology decreased approximately 41% from December 31,2008 to December 31, 2009, resulting in a decrease in proved reserves ofapproximately 505 MMcf.

 

The reserve increasesresulting from extensions, discoveries and other additions resulted for tworeasons.  The first reason is that one probable location from the year end2008 report was reclassified to a proved undeveloped location in the year end2009 report.  This change was based on the overall proved volumetrics forthe field (which did not change year over year), and a decline in the volumesassigned for existing proved developed locations because of reservoirgeometry.  The second reason is that the planned hydraulic fracturetreatment for the existing Wilson #1 well, in conjunction with the necessaryplant upgrade to handle the increased volume of gas,  resulted in the Wilson#1 well reserves beingreclassified into the proved undeveloped category because of the relativelylarge expense required to achieve the predicted production rates from thiswell.

 

For purposes of thefollowing disclosures, estimates were made of quantities of proved reserves andthe periods during which they are expected to be produced. Future cash flowsfor the 2008 estimates were computed by applying year-end prices, adjusted forhistoric differentials, to estimated annual future production from proved gasreserves. Future cash flows for the 2009 estimates were computed by applyingthe simple arithmetic average of the natural gas price in effect on the firstday of each month in 2009 to estimated annual future production from proved gasreserves. The average and year-end prices for gas are indicated below. Futuredevelopment and production costs were computed by applying year-end costs to beincurred in producing and further developing the proved reserves. Future incometax expenses were computed by applying, generally, year-end statutory tax rates(adjusted for permanent differences, tax credits and allowances) to theestimated net future pre-tax cash flows. The discount was computed byapplication of a 10% discount factor. The calculations assume the continuationof existing economic, operating and contractual conditions. However, sucharbitrary assumptions have not proven to be the case in the past. Otherassumptions of equal validity could give rise to substantially differentresults.

 

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**STANDARDIZEDMEASURE OF DISCOUNTED FUTURE NET CASH FLOWSRELATING TO PROVED PETROLEUM AND NATURAL GAS RESERVES**

 
| ** **                                                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2009**                                   | ** ** | **2008** | ** ** |
| ** **                                                | ** ** | **(in thousands)**                    | ** ** |
| Future cash inflows                                       |       | $                                          | 50,652     |   | $ | 107,063 |   |
| Future production costs                                   |       | (17,157                                    | )          | (34,414 | ) |
| Future development costs                                  |       | (7,849                                     | )          | (5,075 | ) |
| Future income taxes                                       |       | —                                     |       | (7,977 | ) |
| Future net cash flows                                     |       | 25,646                                     |       | 59,597 |   |
| 10% annual discount                                       |       | (6,005                                     | )          | (12,282 | ) |
| Standardized measure of discounted future net cash  flows |       | $                                          | 19,641     |   | $ | 47,315 |   |

 

The PV-10 values shown inthe aforementioned table are not intended to represent the current market valueof the estimated proved oil and gas reserves owned by us.

 

For comparative purposes,in addition to the new SEC pricing methodology, we also prepared estimates ofour year-end proved reserves using the old pricing methodology which would haveutilized the December 31, 2009 price of $5.45 per Mcf. Under the old pricing methodology, our reserves at the end of 2009 wouldhave been 19.14 Bcf, with a PV-10 value of $44.5 million.  Accordingly, the impact of using the new SECpricing methodology resulted in a net reduction of our PV-10 value ofapproximately $24.9 million.

 
| **AVERAGE  PRICE**     | ** ** | **YEAR END  PRICE**    | ** ** |
|------------------------|------------|------------------------|------------|
| **2009  REPORT**       | ** ** | **2008 REPORT**   | ** ** |
| **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** |
| $                      | 3.11       |                   | $          | 5.25 |   |
|                        |            |                        |            |  |  |

 

The following are theprincipal sources of changes in the standardized measure of discounted futurenet cash flows:

 

**CHANGESIN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASHFLOWS FROM PROVED PETROLEUM AND NATURAL GAS RESERVEQUANTITIESPROVED RESERVES ARE LOCATED ENTIRELY WITHIN THE UNITED STATES**

 
| ** **                                 | ** ** | **Years Ended December 31,** | ** ** |
|--------------------------------------------|------------|-----------------------------------|------------|
| ** **                                 | ** ** | **2009**                          | ** ** | **2008** | ** ** |
|                                       |       |                              |       |   |   |
| Balance,  beginning of period              |       | 47,315                            |       | 60,208 |   |
| Sales  of oil and gas, net                 |       | 1,373                             |       | (4,088 | ) |
| Net  change in prices and production costs |       | (32,319                           | )          | (5,664 | ) |
| Net  change in future development costs    |       | (2,497                            | )          | (3,547 | ) |
| Extensions  and discoveries                |       | 7,229                             |       | — |   |
| Revisions  of previous quantity estimates  |       | (8,648                            | )          | (4,376 | ) |
| Net  change in income taxes                |       | 6,109                             |       | 4,748 |   |
| Accretion  of discount                     |       | 3,548                             |       | 4,823 |   |
| Other                                      |       | (2,469                            | )          | (4,789 | ) |
| Balance,  end of period                    |       | $                                 | 19,641     |   | $ | 47,315 |   |
|                                            |            |                                   |            |  |  |  |  |

 

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**EXHIBIT INDEX**

 
| **Exhibit   Number** | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                                          |
|---------------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.1  (2)                  |       | Amended  and Restated Articles of Incorporation of GeoPetro Resources Company                                                                                                                                                                                                                                                                                                                                            |
| 3.2  (4)                  |       | Second  Amended and Restated Bylaws of the GeoPetro Resources Company                                                                                                                                                                                                                                                                                                                                                    |
| 4.1  (2)                  |       | Form of  Warrant issued by GeoPetro Resources Company to various investors on various  dates.                                                                                                                                                                                                                                                                                                                       |
| 4.2  (3)                  |       | Specimen  Common Stock Certificate                                                                                                                                                                                                                                                                                                                                                                                       |
| 4.3                       |       | Form of  common stock purchase warrant issued to various investors dated August 13,  2007 (filed as exhibit 4.1 to the Company’s Report on Form 8-K as filed  with the Securities and Exchange Commission on August 16, 2007, and  incorporated herein by reference)                                                                                                                            |
| 4.4                       |       | Registration  Rights Agreement between GeoPetro Resources Company and various investors  dated August 13, 2007 (filed as Exhibit B to the Form of Unit  Subscription Agreement dated August 13, 2007 filed as Exhibit 10.20  to the Company’s Report on Form 8-K as filed with the Securities and  Exchange Commission on August 16, 2007 and incorporated herein by  reference) |
| 4.5  (6)                  |       | Placement  Agent Warrant dated August 13, 2007                                                                                                                                                                                                                                                                                                                                                                      |
| 4.6  (7)                  |       | Form of Common  Stock Purchase Warrant dated as of various dates, issued to purchasers of  promissory notes                                                                                                                                                                                                                                                                                                         |
| 10.1 (2)                  |       | Joint  Venture Agreement Bengara II, Dated January 1, 2000                                                                                                                                                                                                                                                                                                                                                          |
| 10.2 (2)                  |       | Production  Sharing Contract Bengara II, Dated December 4, 1997                                                                                                                                                                                                                                                                                                                                                     |
| 10.4 (2)                  |       | Exploration  Permit#408, Dated July 2, 1997                                                                                                                                                                                                                                                                                                                                                                         |
| 10.5 (2)                  |       | Madisonville  Field Development Agreement dated August 1, 2005                                                                                                                                                                                                                                                                                                                                                      |
| 10.6 (2)                  |       | Alaska  Cook Inlet Option dated April 20, 2005                                                                                                                                                                                                                                                                                                                                                                      |
| 10.7 (2)†            |       | The  2001 Stock Incentive Plan                                                                                                                                                                                                                                                                                                                                                                                           |
| 10.8 (2)†            |       | The  2004 Stock Option and Appreciation Rights Plan                                                                                                                                                                                                                                                                                                                                                                      |
| 10.9 (2)†            |       | Stuart  Doshi Employment Agreement, Dated July 28, 1997 (effective July 1,  1997) and amendments dated January 11, 2001, July 1, 2003, April 20,  2004, May 9, 2005, July 28, 2005 and January 30, 2006                                                                                                                                                                          |
| 10.10 (2)†           |       | David  Creel Employment Agreement, Dated April 28, 1998 and amendments dated June 15,  2000, May 12, 2003 and January 1, 2005                                                                                                                                                                                                                                                                        |
| 10.12 (2)                 |       | Office  Lease Agreement, Dated effective March 1, 2004                                                                                                                                                                                                                                                                                                                                                              |
| 10.13 (4)                 |       | Form of  Subscription Agreement for GeoPetro Resources Company stock executed by  various investors on various dates.                                                                                                                                                                                                                                                                                               |
| 10.19 (5)                 |       | Shares  Sale & Purchase Agreement Dated September 29, 2006                                                                                                                                                                                                                                                                                                                                                 |
| 10.20 (6)                 |       | Form of  Unit Subscription Agreement Dated August 13, 2007                                                                                                                                                                                                                                                                                                                                                     |
| 10.22 (6)                 |       | Promissory  Note to Stuart Doshi dated February 12, 2007                                                                                                                                                                                                                                                                                                                                                            |
| 10.23 (11)†          |       | Seventh  Amendment to Employment Agreement of Stuart Doshi, dated December 29,  2008                                                                                                                                                                                                                                                                                                                                |
| 10.24 (11)†          |       | Eighth  Amendment to Employee Agreement of Stuart Doshi, dated December 31, 2008                                                                                                                                                                                                                                                                                                                                    |
| 10.25 (11)†          |       | Fourth  Amendment to Employment Agreement of David Creel, dated December 29,  2008                                                                                                                                                                                                                                                                                                                                  |
| 10.26 (11)†          |       | Fifth  Amendment to Employee Agreement of David Creel, dated December 31, 2008                                                                                                                                                                                                                                                                                                                                      |
| 10.29 (8)                 |       | Purchase  and Sale Agreement dated December 31, 2008                                                                                                                                                                                                                                                                                                                                                                |
| 10.30 (9)                 |       | Amended  and Restated Term Loan Agreement dated December 31, 2008 with Bank of  Oklahoma                                                                                                                                                                                                                                                                                                                            |
| 10.31 (11)                |       | Security  Agreement dated December 31, 2008                                                                                                                                                                                                                                                                                                                                                                         |
| 10.32 (11)                |       | Form of  Promissory Note issued by GeoPetro Resources Company to various investors  dated various dates from December 23, 2008 to December 26, 2008                                                                                                                                                                                                                                                       |
|  10.24 (12)†    |       | Employment Agreement with J. Chris Steinhauser dated  April 27, 2009                                                                                                                                                                                                                                                                                                                                                |
|  10.25 (13)†    |       | Sixth Amendment to David Creel Employment Agreement  dated April 28, 2009                                                                                                                                                                                                                                                                                                                                           |
|  10.26 (14)          |       | Related Party Promissory Note Dated June 18,  2009                                                                                                                                                                                                                                                                                                                                                                  |
| 21.1  (11)                |       | List  of subsidiaries of GeoPetro Resources                                                                                                                                                                                                                                                                                                                                                                              |
| 23.1  (1)                 |       | Consent  of MHA Petroleum Consultants                                                                                                                                                                                                                                                                                                                                                                                    |
| 23.2  (1)                 |       | Consent  of Hein & Associates LLP                                                                                                                                                                                                                                                                                                                                                                               |
| 31.1  (1)                 |       | Rule 13a-14(a)/15d-14(a) Certification  of Chief Executive Officer.                                                                                                                                                                                                                                                                                                                                            |
| 31.2  (1)                 |       | Rule 13a-14(a)/15d-14(a) Certification  of Chief Financial Officer.                                                                                                                                                                                                                                                                                                                                            |
| 32.1  (1)                 |       | Certification  of Chief Executive Officer and Chief Financial Officer of GeoPetro Resources  Company pursuant to 18 U.S.C. § 1350.                                                                                                                                                                                                                                                                                  |
| 99.1  (1)                 |       | Report  of MHA Petroleum Consultants                                                                                                                                                                                                                                                                                                                                                                                     |

 

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| (1)    | Filed  herewith.                                                                                                                     |
|--------|--------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                 |
| (2)    | Filed  as the identically numbered exhibit to the Registration Statement on Form S-1,  (No. 333-135485), as filed with the |

 

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Table of Contents

 
|   | Securities  and Exchange Commission on June 30, 2006, and incorporated herein by  reference.                                                                                                                                        |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                     |
| (3)    | Filed  as the identically numbered exhibit to the Registration Statement on Form S-1,  (No. 333-135485), as filed with the Securities and Exchange Commission  on January 31, 2007, and incorporated herein by reference. |
|   |                                                                                                                                                                                                                                     |
| (4)    | Filed  as the Exhibit 3(ii) to the Company’s Report on Form 8-K as  filed with the Securities and Exchange Commission on April 25, 2008, and  incorporated herein by reference.                                 |
|   |                                                                                                                                                                                                                                     |
| (5)    | Filed  as the identically numbered exhibit to the Registration Statement on Form S-1  (No. 333-135485), as filed with the Securities and Exchange Commission  on January 9, 2007, and incorporated herein by reference.   |
|   |                                                                                                                                                                                                                                     |
| (6)    | Filed  as the identically numbered exhibit to the Registration Statement on Form S-1  (No. 333-146557), as filed with the Securities and Exchange Commission  on October 9, 2007, and incorporated herein by reference.   |
|   |                                                                                                                                                                                                                                     |
| (7)    | Filed  as Exhibit 4.1 to the Company’s Report on Form 8-K, as filed with  the Securities and Exchange Commission on January 7, 2009, and  incorporated herein by reference.                                          |
|   |                                                                                                                                                                                                                                     |
| (8)    | Filed as Exhibit 10.24  to the Company’s Report on Form 8-K, as filed with the Securities and  Exchange Commission on January 14, 2009, and incorporated herein by  reference.                                       |
|   |                                                                                                                                                                                                                                     |
| (9)    | Filed as Exhibit 10.25  to the Company’s Report on Form 8-K, as filed with the Securities and  Exchange Commission on January 14, 2009, and incorporated herein by  reference.                                       |
|   |                                                                                                                                                                                                                                     |
| (10)   | Filed  as Exhibit 10.1 to the Company’s Report on Form 8-K, as filed with  the Securities and Exchange Commission on December 21, 2007, and  incorporated herein by reference.                                       |
|   |                                                                                                                                                                                                                                     |
| (11)   | Filed  as Exhibit 23.1 to the Company’s Report on Form 10-K, as filed with  the Securities and Exchange Commission on March 23, 2009, and  incorporated herein by reference.                                         |
|   |                                                                                                                                                                                                                                     |
| (12)   | Filed as Exhibit 10.24  to the Form 10-Q, as filed with the Securities and Exchange Commission  on May 11, 2009, and incorporated herein by reference.                                                                    |
|   |                                                                                                                                                                                                                                     |
| (13)   | Filed as Exhibit 10.25  to the Form 10-Q, as filed with the Securities and Exchange Commission  on May 11, 2009, and incorporated herein by reference.                                                                    |
|   |                                                                                                                                                                                                                                     |
| (14)   | Filed as Exhibit 10.26  to the Form 10-Q, as filed with the Securities and Exchange Commission  on August 10, 2009, and incorporated herein by reference.                                                                 |
|   |                                                                                                                                                                                                                                     |
| † | Indicates  a management or compensatory plan or arrangement.                                                                                                                                                                             |

 

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