** **

**UNITED STATES**

**SECURITIES AND EXCHANGECOMMISSION**

**WASHINGTON, D.C. 20549**

** **

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** **

**Form 10-K**

** **

**ANNUAL REPORT**

**PURSUANT TO SECTION 13 OR15(d)**

**OF THE SECURITIES EXCHANGE ACT OF1934**

 
| **x** | **ANNUAL  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE  ACT OF 1934** |
|-------|------------------------------------------------------------------------------------------------------|

 

**For the fiscal year ended December 31,2007**

** **

**OR**

** **
| **o** | **TRANSITION  REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE  ACT OF 1934** |
|-------|----------------------------------------------------------------------------------------------------------|

 

**For the transition period from                    to**

** **

**Commission File Number  001-16749**

 

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**GeoPetro Resources Company**

(Exactname 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’stelephone number, including area code)

 

**Securitiesregistered pursuant to Section 12(b) of the Act:**

 

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

 

**Securitiesregistered pursuant to Section 12(g) of the Act: None**

 

Indicateby check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405of the Securities Act. Yes o  Nox

 

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 xNo 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 x |   | Smaller Reporting  Company o |
|---------------------------|--------|---------------------|--------|-------------------------|--------|------------------------------|

 

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 $71,888,148 based on the closing sale price of $2.65 pershare as reported by the American Stock Exchange on March 28, 2008.

 

Thenumber of shares of the registrant’s common stock outstanding on March 31,2008 was 31,950,970.

 

**DOCUMENTS INCORPORATED BY REFERENCE**

 

Portionsof the registrant’s Proxy Statement relating to the 2007 Annual Meeting ofShareholders to be filed on or before April 29, 2008 are incorporated byreference into Part III of this Form 10-K.

 

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**GEOPETRO RESOURCES COMPANY**

 

**TABLE OF CONTENTS**

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

 

**Forward-LookingStatements**

 

*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 such forward-looking statements besubject to the safe harbors created thereby. These statements are related to future events or our future financialperformance.  We have attempted toidentify forward-looking statements with terminology, including “anticipate,” “believe,”“can,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “will,”or similar expressions as they relate to us and our business, industry andmarkets.  All statements other thanstatements of historical fact are statements that could be deemed forward-lookingstatements, such as those statements that address activities, events ordevelopments that we expect, believe or anticipate will or may occur in thefuture. These statements are based on certain assumptions and analyses made byus in light of our experience and perception of historical trends, currentconditions, expected future developments and other factors we believe areappropriate in the circumstances. Such forward looking statements are subjectto change based on factors beyond our control. Certain factors that may affectour financial condition and results of operations are discussed in Item 1A “RiskFactors” and Item 7A “Quantitative and Qualitative Disclosures About MarketRisk” of this Annual Report on Form 10-K, and may be discussed from timeto time in our reports filed with the Securities and Exchange Commissionsubsequent to this report.  We assume noobligation, nor do we intend to update these forward-looking statements, unlessrequired by law. Unless the context requires otherwise, references in thisAnnual Report on Form 10-K to “GeoPetro,” “we,” “us” and “our” refer toGeoPetro Resources Company and its consolidated subsidiaries.*

 

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**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.

 

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.

 

**GENERALDEVELOPMENT OF THE BUSINESS**

** **

During the past fiveyears, we have conducted leasehold acquisition, exploration and drillingactivities on our North American, Australian and Indonesian prospects. Theseprojects currently encompass approximately 372,317 gross (158,401net) 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.

 

In December 2000, weacquired working interests in oil and natural gas leases in the MadisonvilleField in Madison County, Texas, including interests in the Rodessa Formation.Also included in the acquisition was the Magness Well, an existing well thathad been drilled, cased and production tested in the Rodessa Formation. In October 2001,we re-completed and tested the Magness Well over a 12-day period. In October 2002,we drilled, completed and successfully tested an injection well to dispose ofwaste products resulting from the treating process for gas produced from theRodessa Formation. The Madisonville Field gas treatment plant and associatedpipelines, which were built specifically for this project, were placed intoservice in May 2003, and the Magness Well began production in late May 2003.Since 2003, substantially all of our revenue has been generated from naturalgas sales derived from the Madisonville Field. The Madisonville Project isexpected to be our primary source of revenue in 2008. The first developmentwell in the Madisonville Field, the Fannin Well, was drilled in 2004 and wastested at rates of up to 25.7 MMcf/d. In 2006, we drilled the Wilson andMitchell wells. Presently, the Fannin, Mitchell and Magness wells are producingwhile the 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 treating capacity limit of approximately 18,000 Mcf per day. Weentered into an agreement with the plant owner, Madisonville Gas Processing, LP(“MGP”), an unaffiliated third party, which required, among other things, thatMGP expand the design treating capacity of the plant from 18,000 to 68,000 Mcfper day to treat additional volumes from our producing wells. In early October 2007,MGP completed the additional treating facilities and the additional treatingcapacity at such facilities, however operations at the additional treatingfacilities were suspended in December 2007 in order to make modificationsto more effectively deal with the presence of diamondoids in the gas streamproduced from the Rodessa Formation.  See“Properties” — Description of the Properties — Texas — The Madisonville GasTreatment Plant and Gathering Facilities.”

 

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As of March 31, 2008 wehave 31,950,970 shares of common stock outstanding as a result of raisingapproximately $54.9 million of equity, net of offering costs, by way ofprivate placements and a public offering in Canada. These funds have been usedprimarily to acquire, explore and develop our oil and natural gas prospects.

 

Most recently, on August 13,2007, we sold, pursuant to a private placement, 2,002,599 units of oursecurities at a price of $3.85 per unit, for total gross proceeds of$7,710,006. Each unit consists of one share of our common stock and a warrantto purchase three-tenths of a common share. Each one whole warrant shallentitle the holder to acquire one share of common stock at a price of $4.50 pershare for a period of five years from the closing date. The units werepurchased by a small number of accredited investors. We filed a re-saleregistration statement covering the common shares and warrants exercisable forcommon shares sold in such placement, which registration statement was declaredeffective by the Securities and Exchange Commission in October 2007. Thegross proceeds  from the sale have been,and will be, used to fund the Company’s exploration and development program andfor general working capital purposes.

 

**GrowthStrategy**

** **

Our 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:

 

·       identifyand pursue potential projects which individually have the potential to be “companymakers” which we define as projects which could generate a minimum unrisked netpresent value of $50 million net to our interest using a 10% discountfactor;

 

·       performgeological, engineering and geophysical evaluations;

 

·       gain controlof key acreage;

 

·       generate highquality drillable exploration and development drilling prospects;

 

·       retaina large working interest in those projects which involve low risk appraisal ordevelopment drilling, exploitation or appraisal of proven, probable andpossible reserves; and

 

·       minimizeearly investment and exploration risk in higher risk exploratory prospectsthrough farmouts to other oil and natural gas companies and maintain meaningfulinterests with a “carry” through the exploration phase.

 

**RisksAssociated With Foreign Operations**

** **

Our business activitiesin Indonesia, Canada and the United States are subject to political andeconomic risks, including: loss of revenue, property and equipment as a resultof unforeseen events like expropriation, nationalization, war, terrorist attacksand insurrection; risks of increases in import, export and transportationregulations and tariffs, taxes and governmental royalties; renegotiation ofcontracts with governmental entities; changes in laws and policies governingoperations of foreign-based companies in Indonesia; exchange controls, andnumerous other factors. While we expect these risks are greater in Indonesia,especially political risk, any one or more of such political or economicconditions could change in the United States or Canada to our detriment.For a related discussion of the risks attendant with foreign operations, see “RiskFactors.”

 

**Financial Information AboutGeographic Areas**

 

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

** **

***3***

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** **

**Regulations**

** **

Domestic exploration for,and 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:

 

·       Federalenvironmental laws and regulations

 

·       Stateenvironmental laws and regulations

 

·       Localenvironmental laws and regulations

 

·       Conservationlaws and regulations

 

·       Taxand other laws and regulations pertaining to the energy 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.

 

As of December 2007,we have re-completed an existing production well and drilled three additionalproduction wells and an injection well in the Madisonville Project as operator.In addition, we may drill oil, gas and disposal wells in the future as theoperator and will be required to obtain local government and other permits todrill such wells. There can be no assurance that such permits will be availableon a timely basis or at all. Texas and other states have statutes orregulations pertaining to conservation matters which, among other matters,regulate the unitization or pooling of gas properties and the spacing, pluggingand abandonment of such wells and set limits on the maximum rates of naturalgas that can be produced from gas wells.

 

Our operations andactivities are subject to numerous federal, state and local environmental lawsand regulations. These laws and regulations:

 

·       Requirethe acquisition of permits

 

·       Restrictthe type, quantities and concentration of various substances that can bedischarged into the environment

 

·       Limitor prohibit drilling and other activities on wetlands and other designated,protected areas

 

·       Regulatethe generation, handling, storage, transportation, disposal and treatment ofwaste materials

 

·       Imposecriminal or civil liabilities for pollution resulting from oil and natural gasoperations

 

We expect that with theincrease in our exploratory and development drilling activities, the impact ofenvironmental laws and regulations on our business and operations will also increase.We may be required in the future to make substantial outlays of money to complywith environmental laws and regulations. Additional changes in operatingprocedures and expenditures to comply with future environmental laws cannot bepredicted.

 

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.

 

As the operator of theMadisonville Project, among other various environmental laws and regulations,we are  subject to the U.S. ComprehensiveEnvironmental Response, Compensation and Liability Act (“**CERCLA**”)and any 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. 

 

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Under CERCLA, one owner,lessee or other party, having responsibility for and an interest in a siterequiring cleanup may, under certain circumstances, be required to bear adisproportionate share of liability for the cost of such cleanup if payments cannotbe obtained from other responsible parties. The Resource Conservation andRecovery Act (“**RCRA**”) and comparable rules adoptedby Texas and other states regulate the generation, management and disposal ofhazardous oil and gas waste.

 

The Texas RailroadCommission has been delegated the responsibility and authority to regulate andprevent pollution from oil and gas operations, including the prevention ofpollution of surface or subsurface water resulting from the drilling of oil andgas wells and the production of oil and gas. In addition to regulating thegeneration, management and disposal of hazardous oil and gas waste, the TexasRailroad Commission has been delegated authority to regulate undergroundhydrocarbon 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.

 

In re-completing theexisting well on the Madisonville Project, we were required to drill a well forinjection or disposal of produced waste gas from wells. Injection wells aresubject to regulation under the Safe Drinking Water Act (“**SDWA**”)and the regulations and procedures which have been adopted by the EnvironmentalProtection Agency (“**EPA**”) underthat Act. Generally, enforcement procedures under the SDWA are administered bythe EPA unless such authority has been delegated by the EPA to a state whichhas primary enforcement responsibility based on the EPA’s determination thatthe state has adopted drinking water regulations no less stringent than thenational primary drinking water regulations and meets certain other criteria.Underground injection wells not used for the underground injection of naturalgas for storage are generally unlawful and subject to penalties under the SWDAunless authorized by:

 

·       permitissued by the EPA or a state having primary enforcement responsibility, or

 

·       rule pursuantto an underground injection control program established by a state or the EPA.

 

The regulatory burden onthe natural gas and oil industry increases our cost of doing business andaffects our financial condition. Future developments, such as stricterrequirements of environmental or health and safety laws and regulationsaffecting our business or more stringent interpretations of, or enforcementpolicies with respect to, such laws and regulations, could adversely affect us.To meet changing permitting and operational standards, we may be required, overtime, to make site or operational modifications at our facilities, some ofwhich might be significant and could involve substantial expenditures. Therecan be no assurance that material costs or liabilities will not arise fromthese or additional environmental matters that may be discovered or otherwisemay arise from future requirements of law.

 

**OverseasRegulations**

** **

We own a working interestin an oil and gas project located in Indonesia. We have farmed out our interestin this project to a third party who is the operator of this project. Inexploring for, drilling and developing this property, this operator will berequired to comply with the environmental, conservation, tax and other laws andregulations of Indonesia. We own non-operated working interests in oil and gasprojects located in Canada.  In exploringfor, drilling and developing these properties, these operators will be requiredto comply with the environmental, conservation, tax and other laws and regulations in Canada.

 

**Technology**

 

We participate inprojects utilizing economically feasible exploration technology in ourexploration and development drilling activities to reduce risks, lower costs,and more efficiently produce oil and gas. We believe that the availability of 

 

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cost effective 2-D and3-D seismic data makes its use in exploration and development drillingactivities attractive from a risk management perspective in certain areas.

 

Briefly, through the useof a seismograph, a seismic survey sends pulses of sound from the surface downinto the earth, and records the echoes reflected back to the surface. Bycalculating the speed at which sound travels through the various layers ofrock, it is possible to estimate the depth to the reflecting surface. It thenbecomes possible to infer the structure of rock deep below the earth’s surface.We evaluate substantially all of our exploratory prospects using 2-D seismicdata. In addition, we own approximately 12 square miles of 3-D seismicdata covering our leasehold and adjacent lands in the Madisonville Project.

 

The use of seismictechnology does not entirely remove the risk of exploration and developmentdrilling of oil and natural gas deposits. It is important to consider thefollowing:

 

·       we may not recognize significant geological featuresdue to errors in interpretation, processing limitations, the presence ofcertain geological environments that are out of our control or other factors;and

 

·       seismic generally becomes less reliable withincreasing depth of the geological horizon; and

 

·       the use of this technology may increase our findingcost over that if it is not used.

 

**PrincipalProducts**

** **

Our principal productsare the production of natural gas and crude oil from properties in which we ownan interest. Since our inception, we have realized only limited production ofnatural gas and crude oil 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.

 

During the last threefiscal years, 100% of our revenues have been derived from the sale of naturalgas. Substantially all of our natural gas sales, approximately 99%, have beengenerated by three producing wells, the Magness #1, Fannin #1and Mitchell#1 wells, located in the Madisonville Field in East Texas. Natural gas producedby the wells is sold at the wellhead where it is delivered to a gatheringpipeline and transported to a nearby gas treatment plant where it is treated toremove impurities. The gas is then transported nine miles to one of two commoncarrier pipelines from which point it is delivered to the greater Dallas, Texasarea. The price received for the natural gas is the Houston Ship Channel priceindex less certain adjustments for the quality of the gas delivered. Theadjustments for the quality of gas delivered at the wellsite as well as thegathering and transportation costs presently amount to approximately $1.75  per Mcf of untreated gas delivered at thewellsite.

 

For financial informationregarding our business activities by segment, please see our FinancialStatements beginning on page F-1 of this annual report. Substantially allof our revenue is produced from natural gas sales in the Madisonville Fieldlocated 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**

** **

Permits and licenses areimportant to our operations, since they allow the search for the extraction ofany oil, gas and minerals discovered on the areas covered. See****“Properties” for a general description ofthe permits and licenses under which we operate. Provided we establish acommercial discovery thereon, the Bengara PSC in Indonesia grants us the rightto 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 and deposits in trust received from thesale of natural gas from our Madisonville Project in Texas and from the sale ofcommon stock in private placements. We are required to use this cash to pay forthe cost of our operations and activities. See further, “Management’sDiscussion and Analysis of Financial Condition and Results of Operations.”

 

**Customers**

** **

Substantially all of ourrevenues to date have been derived from sales by MGP to two customers, LuminantEnergy Company, and ETC Katy Pipeline, Ltd., of natural gas produced from ourMadisonville Project in Texas. We have notcommitted any forward sales of our natural gas. We contract to sell thegas with spot-market based contracts that vary with market forces on a monthlybasis. No other customer accounts forin excess of 10% of our revenues.  Theloss of either of these customers could result in the loss of our revenues,which would have a material adverse effect on our results of operations.  See “Risk Factors”.

 

**Competition**

** **

The natural gas and oilindustry is intensely competitive and speculative in all of its phases. Weencounter competition from other natural gas and oil companies in all areas ofour operations. In seeking suitable natural gas and oil properties for acquisition,we compete with other companies operating in our areas of interest, includinglarge natural gas and oil companies and other independent operators, which havegreater financial resources and in many instances, have been engaged in theexploration and production business for a much longer time than we have. Manyof our competitors also have substantially larger operating staffs than we do.Many of these competitors not only explore for and produce natural gas and oilbut also market natural gas and oil and other products on a regional, nationalor worldwide basis. These competitors may be able to pay more for productivenatural gas and oil properties and exploratory prospects and define, evaluate,bid for and purchase a greater number of properties and prospects than us. Inaddition, these competitors may have a greater ability to continue explorationactivities during periods of low market prices. Our ability to acquireadditional properties and to discover reserves in the future will depend on ourability to evaluate and select suitable properties and to consummatetransactions in a highly competitive environment.

 

The prices of our naturalgas production are controlled by market forces. However, competition in thenatural gas and oil exploration industry also exists in the form of competitionto acquire leases and obtain favorable transportation prices. We are relativelysmall and may have difficulty acquiring additional acreage and/or projects andmay have difficulty arranging for the transportation of our production. We alsoface competition in obtaining natural gas and oil drilling rigs and in sourcingthe manpower to run them and provide related services.

 

**Employees**

** **

Currently, we have 10employees, all of whom are full time. We use the services of independentconsultants and contractors to perform various professional services, includingreservoir 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.

** **

**7**

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

 

Inaddition to risks and uncertainties in the ordinary course of business that arecommon to all businesses, important factors that are specific to our industryand our company could materially impact our future performance and results ofoperations. We have provided below a list of these risk factors that should bereviewed when considering our securities. These are not all the risks we faceand other factors currently considered immaterial or unknown to us may impactour future operations.

 

**RisksRelated to Our Business**

** **

***As of December 31, 2007 wehave capitalized costs totaling $53.28 million as evaluated and unevaluated oiland gas properties whereas we have generated revenues of only $29.9 millionsince January 1, 2003 and revenues of only $6.9 million during the fiscalyear ended December 31, 2007.***

** **

Since inception, ouractivities have been primarily related to acquiring and exploring leaseholdinterests in oil and natural gas properties in Texas, California, Alaska,Alberta, Indonesia and Australia. We incur substantial acquisition andexploration costs and overhead expenses in our operations, and until 2003,excluding minor interest and dividend income, our only significant cash inflowswere the recovery of capital invested in projects through sale or otherdivestitures of interests in oil and gas prospects to industry partners. As aresult, we have sustained an accumulated deficit through December 30, 2007of $12,010,789. Our production activities commenced in May 2003. Since May 2003,over 90% of our revenue has been generated from natural gas sales derived fromwells in the Madisonville Field in Texas. It is possible that in the future wewill be unable to continue to generate revenues from our sales of natural gasfrom our Madisonville Field wells because our proved reserves decline asreserves are produced from the wells. The drilling of exploratory oil andnatural gas wells is highly speculative and often unproductive. Ourparticipation in future drilling activities to explore, develop and exploit theproperties in which we have an interest, or in which we may acquire interests,may be unsuccessful, may fail to generate positive cash flow, and may notenable us to maintain profitability in the future.

 

***Approximately 99% of our currentrevenues are generated by our interest in the Madisonville Project. Delays orinterruptions of the Madisonville Project natural gas drilling and productionoperations including, but not limited to, events beyond our control or thefailure of third parties on which we rely to provide key services, couldnegatively impact our revenues.***

** **

Approximately 99% of ouroil and natural gas revenues for the years ended December 31, 2007 and2006 were derived from the Madisonville Project. In connection with thatproject, we have contracted with third parties to provide key services,including:

 

(a)            Madisonville Gas Processing, LP, or MGP,which owns and operates gathering pipelines and a dedicated natural gastreatment plant which we utilize to treat impurities in the MadisonvilleProject natural gas; and

 

(b)           Gateway Processing Company, or Gatewaywhich operates a sales pipeline for such natural gas.

 

The failure of MGP orGateway to perform their contractual obligations to us could impose delays orinterruptions in our production operations and prevent us from generatingrevenues. In addition, events which are beyond our control, or that of Gatewayor MGP, could affect our production operations. Such events include, but arenot limited to:

 

·       events referred to as force majeure, such as an act ofGod, act of a public enemy, war, blockade, public riot, lightning, fire, storm,flood, explosion and any other causes whether of the kind enumerated orotherwise not reasonably within the control of MGP, Gateway or our company.

 

·       subsurface conditions or formations encountered duringthe drilling of wells, whether natural or mechanical, including but not limitedto blowout, igneous rock, salt, saltwater flow, loss of circulation, loss ofhole, abnormal pressures, or any other impenetrable substance or adversecondition, which renders further drilling of a well impossible or impractical.

 

·       the inability to secure raw materials or equipment,

 

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·       transportation accidents, and

 

·       labor disputes and equipment failures.

 

**Inexcess of 90% of our revenues to date have been derived from sales by MGP totwo customers. The loss of one or both these customers could have a materialadverse impact on our oil and gas revenues.**

 

Approximately 99% of ouroil and natural gas revenues for the years ended December 31, 2007 and2006 were derived from the Madisonville Project. During 2007 and 2006,approximately 99% of our revenues have been derived from sales by MGP to twocustomers, Luminant Energy Company, LLC, and ETC Katy Pipeline, Ltd. The lossof one of these customers could impact the price we receive for our gas solddue to lessened competition. The loss of both customers could result in a totalloss of our revenue.

 

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

*** ***

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. The business ofexploring for, developing or acquiring reserves is capital intensive. Forexample, as of December 30, 2007 we have capitalized costs totaling$53,276,945 as evaluated and unevaluated oil and gas properties. To the extentcash flow from operations is reduced and external sources of capital becomelimited or unavailable, our ability to make the necessary capital investment tomaintain or expand our asset base of oil and natural gas reserves will beimpaired. Even if we are able to raise capital to develop or acquire additionalproperties, no assurance can be given that our future exploitation and developmentdrilling activities will result in the discovery of any reserves.

 

***Our exploration and development drilling activities may notbe commercially successful. The drilling of exploratory oil and natural gaswells is expensive, highly speculative and often unproductive.***

 

Exploration for oil andnatural gas on unproven prospects is expensive, highly speculative and involvesa high degree of risk, including the risk that no commercially productive oilor natural gas reservoirs will be encountered. Reserves are dependent on ourability to successfully complete drilling activity on proven prospects.

 

The cost of drilling,completing and operating wells is often uncertain, and drilling operations maybe curtailed, delayed or cancelled as a result of a variety of factors,including:

 

·       unexpected drilling conditions, pressure orirregularities in formations;

 

·       equipment failures or accidents, adverse weatherconditions;

 

·       compliance with governmental requirements; and

 

·       shortages or delays in the availability of drillingrigs and the delivery of equipment.

 

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

** **

With the exception of theMadisonville Project, the properties in which we have an interest are prospectsin which the presence of oil and natural gas reserves in commercial quantitieshas not been established. Any decision to engage in exploratory drilling orother activities on any of these properties will be dependent in part on theevaluation of data compiled by petroleum engineers and geologists and obtainedthrough geophysical testing and geological analysis.

 

Reservoir engineering,geophysics and geology are not exact sciences and the results of studies andtests used to make such evaluations are sometimes inconclusive or subject tovarying interpretations. As such, there is no certain way to know in advancewhether any of our prospects will yield oil and natural gas in commercialquantities. Further, it is possible that we will participate in the drilling ofmore dry holes than productive wells or that all or substantially all of thewells drilled will 

 

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be dry holes. Thedrilling of dry holes on prospects in which we have an interest could adverselyaffect their values and our decision to undertake further exploration anddevelopment drilling of such prospects. It is not certain or predictablewhether, and no assurance can be made that, the wells drilled on the propertiesin which we have an interest will be productive or, if productive, that we willrecover all or any part of our investment in the properties. In sum, ourparticipation in future drilling activities may not be successful and, ifunsuccessful, such failure will negatively impact our revenues and have amaterial adverse effect on our results of operations and financial condition.Our oil and natural gas revenues were $6,890,777 and $6,716,360 for the yearsended December 31, 2007 and 2006, respectively. Future revenues coulddecline from those levels if our future drilling efforts are not successful.Furthermore, as of December 30, 2007 we have capitalized costs totaling$53.28 million as evaluated and unevaluated oil and gas properties. Should ourfuture drilling activities be unsuccessful, we may then be required to recordan impairment charge equal to a portion of, or all, of the capitalized costsresulting in an immediate adverse impact on our results of operations andfinancial position.

 

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

*** ***

Our ability to manage andmitigate the various risks associated with certain of our exploration andoperations in Alberta, Canada, and Indonesia is limited since we rely on thirdparties to operate our projects. We are a non-operating interest owner in ourCanadian and Indonesian properties. With respect to our interests outside ofthe United States, we have entered into agreements with third partyoperators for the conduct and supervision of drilling, completion andproduction operations. In the event that commercial quantities of oil andnatural gas are discovered on one of our properties, the success of the oil andnatural gas operations on that property depends in large measure on whether theoperator of the property properly performs its obligations. The failure of suchoperators and their contractors to perform their services in a proper mannercould result in materially adverse consequences to the owners of interests inthat particular property, including us.

 

***Our percentage share of oil and gas revenues from our Indonesianproperty is diminished by the terms of our production sharing contract in theBengara Block.***

 

C-G Bengara owns 100% ofthe underlying rights to explore for and produce oil and natural gas within theBengara Block.  We have a 12% interest inC-G Bengara. C-G Bengara is subject to a production sharing contract, whichmeans generally that C-G Bengara is entitled to receive, from productionproceeds, 100% of expenditures in the block as “cost recovery.” Once thesecosts are recovered, C-G Bengara’s production share will be reduced toapproximately 26.7% of oil produced and 62.5% of all natural gas produced. Weare entitled to 12% of C-G Bengara’s reduced share of any such production. Seethe discussion under “Properties for more information concerning the productionsharing contract.

 

***Drilling andcompletion equipment, services, supplies and personnel are scarce and may notbe available when needed, which could significantly disrupt or delay ouroperations.***

*** ***

From time to time, therehas been a general shortage of drilling rigs, equipment, supplies and oilfieldservices in North America and Indonesia, which may intensify with currentincreased industry activity. In addition, the costs and delivery times of rigs,equipment and supplies have risen. There can be no assurance that sufficientdrilling and completion equipment, services and supplies will be available whenneeded. Shortages could delay our proposed exploration, development drilling, 

 

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and sales activities, which could have a materialadverse effect on our results of operations. Our oil and natural gas revenueswere $6.9 million for the year ended December 31, 2007. Future revenuescould decline from those levels if we experience delays in our proposedexploration, development drilling, and sales activities. The demand for, andwage rates of, qualified rig crews have risen in the drilling industry due tothe increasing number of active rigs in service. If the demand for qualifiedrig crews continues to rise in the drilling industry, then the oil and gasindustry may experience shortages of qualified personnel to operate drillingrigs. This could delay our drilling operations and adversely affect ourfinancial condition and results of operations.

 

***Our working interest in properties, and our ability torealize any profits from such properties, will be diminished to the extent thatwe enter into farmout arrangements with unaffiliated third parties.***

 

We have previouslyentered into, and may in the future enter into, farmout arrangements with thirdparties willing to drill natural gas and oil wells on leaseholds in which weoriginally acquired working interests, in exchange for our assignment of partor all of our leasehold interests. As a consequence of these arrangements, ourretained interests in properties which are subject to farmout arrangements havebeen or may be diminished. Our opportunity to realize revenues and profitsfrom properties which are successfully developed under farmout arrangementswill be diminished to the extent of our reduced interests.

 

***Competition withother oil and natural gas exploration and development drilling companies forviable oil 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)                                  thosecompetitors that are seeking oil and gas fields for expansion, further drilling,or increased production through improved engineering techniques;

 

(b)                                 income-seekingentities purchasing a predictable stream of earnings based upon historicproduction from fields being acquired; and

 

(c)                                  juniorcompanies seeking exploration opportunities in unknown, unproven territories.

 

Our competitors may be able to pay more for productiveoil and natural gas properties and may be able to define, evaluate, bid for andpurchase a greater number of properties and prospects than we can. Our abilityto acquire additional properties in the future will depend upon our ability toconduct efficient operations, evaluate and select suitable properties,implement advanced technologies and consummate transactions in a highlycompetitive environment.

 

***Estimates of oil and natural gas reserves are inherentlyimprecise. Any material inaccuracies in these reserve estimates or underlyingassumptions will affect materially the quantities and present value of ourreserves.***

 

Estimates of proved oiland natural gas reserves and the future net cash flows attributable to thosereserves are prepared by independent petroleum engineers and geologists. Thereare numerous uncertainties inherent in estimating quantities of proved oil andnatural gas reserves and cash flows attributable to such reserves, includingfactors beyond our control and that of our engineers. Reserve engineering is asubjective process of estimating underground accumulations of oil and naturalgas that cannot be measured in an exact manner. Different reserve engineers maymake different 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.

 

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*** ***

***Competitive pressures may force us to implement newtechnologies at substantial cost and our limited financial resources may limitour ability to implement such technologies at the same rate as our competitors.***

 

The oil and gas industryis characterized by rapid and significant technological advancements andintroductions of new products and services utilizing new technologies. Otheroil and gas companies may have greater financial, technical and personnelresources that allow them to enjoy technological advantages and may in the futureallow them to implement new technologies before we do. There can be noassurance that we will be able to respond to such competitive pressures andimplement such technologies on a timely basis or at all. One or more of thetechnologies currently utilized by us or implemented in the future may becomeobsolete.

 

***We will require additional capital to fund our futureactivities. Our ability to pursue our business plan may be restricted by ouraccess to additional financing.***

 

Until such time as theproperties in which we own interests are generating sufficient cash flow tofund planned capital expenditures, we will be required to raise additionalcapital through the issuance of additional securities or otherwise sell or farmout interests in our oil and natural gas properties to third parties. If andwhen the properties in which we own interests become productive and haveadequate reserves, we may borrow funds to finance our future oil and naturalgas operations and exploratory and development drilling activities. We may notbe able to raise additional funds in the future from any source or, if suchadditional funds are made available to us, we may not be able to obtain suchadditional financing on terms acceptable to us. To the extent such funds arenot available from any of those sources, our operations and activities will belimited to those operations and activities we can afford with the funds thenavailable to us. We have committed to a three well drilling program in ourMadisonville project to facilitate the expansion of the gas treatment plant.The commitment is not discretionary. While we have fulfilled the commitment todrill the first two wells of the three well commitment, we are further requiredto drill a third well sufficient to test the Smackover Formation (estimated tobe encountered at approximately 18,000 feet) on or before September 30,2008. This well is expected to cost approximately $12 million to drill andcomplete. We have granted MGP a security interest in the Madisonville Fieldproperties to secure the three well commitment. Subject to events of forcemajeure, and the availability of suitable drilling rigs, well services, andequipment, our failure to drill this well could result in the loss of ourinterest in the Madisonville Project. Our larger competitors, by reason oftheir size and relative financial strength, may be more easily able to accesscapital markets than us.

 

***The volatility in crude oil and natural gas prices couldadversely affect our financial results and ability to raise additional capital.***

 

Our revenues, cash flowsand profitability are substantially dependent on prevailing prices for both oiland natural gas. Decreases in natural gas prices will decrease revenues andcash flows from the Madisonville Project and our other producing properties, ifany, and decreases in oil and natural gas prices could deter potentialinvestors from investing in our company and generally impede our ability toraise additional financing to fund our exploration and development drillingactivities. Historically, oil and natural gas prices and markets have beenvolatile, and they are likely to continue to be volatile in the future. Pricesfor oil and natural gas are subject to wide fluctuations in response torelatively minor changes in the supply of, and demand for, oil and natural gas,market uncertainty and a variety of additional factors that are beyond ourcontrol. These factors include, but are not limited to, political conditions inthe Middle East and other regions, internal and political decisions of OPEC andother oil and natural gas producing nations to decrease or increase productionof crude oil, domestic and foreign supplies of oil and natural gas, consumerdemand, weather conditions, domestic and foreign government regulations, transportationcosts, the price and availability of alternative fuels and overall economicconditions.

 

Our current operationsare particularly exposed to volatility in natural gas prices because a portionof the fees we pay to process natural gas at the Madisonville gas treatmentplant is fixed. The sale price of natural gas must be above a minimum price ofapproximately $3.00 per Mcf at the present time before we earn any net revenuesfrom the sale of natural gas.

 

***We are subject to a number of operational risks beyond ourcontrol against which we may not have, or be able to obtain insurance.***

 

Our operations aresubject to the many risks and hazards incident to exploring and drilling for,and producing and transporting, oil and natural gas, including among otherrisks:

 

·       blowouts, fires, craterings, pollution and equipmentfailures that may result in damage to or destruction of wells, producingformations, production facilities and equipment;

 

·       personal injuries or death due to accidents, humanerror or acts of God;

 

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·       unavailability of materials and equipment to drill andcomplete or re-complete wells; unfavorable weather conditions; engineering andconstruction delays;

 

·       fluctuations in product markets and prices; proximityand capacity of pipeline, and trucking or termination facilities to our oil andnatural gas reserves; hazards resulting from unusual or unexpected geologicalor environmental conditions; environmental regulations and requirements;

 

·       accidental leakage of toxic or hazardous materials,such as petroleum liquids or drilling fluids into the environment, remediationand clean-up costs; and

 

·       political instability and civil unrest, insurrectionsor disruptions in foreign countries in which some of our interests are located.

 

If one or more of theseevents occurs, we could incur substantial liabilities to third parties orgovernmental entities, the payment of which could have a material adverseeffect on our financial condition and results of operations, or we could loseproperties in which we have invested significant sums (totaling $53.28 million)which are capitalized as evaluated and unevaluated oil and gas properties as ofDecember 30, 2007.

 

***A loss not covered by insurance couldresult in substantial expenses to us.***

 

We do not insure fullyagainst 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. However, a loss not fully covered by insurance could result inexpenses 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.

 

***We are subject to extensive government regulations that canchange from time to time, compliance with which are costly and could negativelyimpact our production, operations and financial results.***

 

The oil and gas industryis subject to extensive government regulations in the countries in which we operate.Matters subject to regulation include discharge permits for drillingoperations, drilling bonds, reports concerning operations, unitization andpooling of properties and taxation. Historically, our costs of complying withthese regulations have not exceeded $100,000 per year. From time to time,regulatory agencies have imposed price controls and limitations on productionby restricting the rate of flow of oil and natural gas wells below actualproduction capacity in order to conserve supplies of oil and natural gas. Weare also subject to changing and extensive tax laws, the effects of whichcannot be predicted. Legal requirements are frequently changed and subject tointerpretation, and we are unable to predict the ultimate cost of compliancewith these requirements or their effects on our operations. Future laws, orexisting laws or regulations, as currently interpreted or reinterpreted orchanged in the future, could result in increased operating costs, fines andliabilities, in amounts which are unknown at this time, any of which couldmaterially adversely affect our results of operations and financial condition.

 

***Our industry is subject to extensive environmentalregulation that may limit our operations and negatively impact our production.***

 

Extensive national,state, provincial and local environmental laws and regulations in theUnited States and foreign jurisdictions affect nearly all of ouroperations. These laws and regulations set various standards regulating certainaspects of health and environmental quality, provide for penalties and otherliabilities for the violation of such standards and establish in certaincircumstances obligations to remediate current and former facilities andlocations where operations are or were conducted. In addition, specialprovisions may be appropriate or required in environmentally sensitive areas ofoperation.

 

Environmental legislationmay require that we, among other things:

 

·       acquire permits before commencing drilling;

 

·       restrict spills, releases or emissions of varioussubstances produced in association with our operations;

 

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·       limit or prohibit drilling activities on protectedareas such as wetlands or wilderness areas;

 

·       take reclamation measures to prevent pollution fromformer operations;

 

·       take remedial measures to mitigate pollution fromformer operations, such as plugging abandoned wells and remediatingcontaminated soil and groundwater;

 

·       take remedial measures with respect to propertydesignated as a contaminated site.

 

The cost of any of theseactions is presently unknown but is likely to be significant.

 

***Compliance with existing or future environmental legislationis unknown but could be substantial.***

 

Compliance with suchlegislation can require significant expenditures and a breach may result in theimposition of fines and penalties. The discharge of oil, natural gas or otherpollutants into the air, soil or water may give rise to liabilities togovernments and third parties and may require us to incur substantial costs toremedy such discharge. Under these laws and regulations, we could be liable forpersonal injury, clean-up costs and other environmental and property damages,as well as administrative, civil and criminal penalties. We could be requiredto cease production on properties if environmental damage occurs. Environmentallegislation is evolving in a manner expected to result in stricter standardsand enforcement, larger fines and liability and potentially increased capitalexpenditures and operating costs. Changes in, or enforcement of, environmentallaws may result in a curtailment of our production activities, or a materialincrease in the costs of production, development drilling or exploration, anyof which could have a material adverse effect on our financial condition andresults of operations or prospects. We are not presently aware of anyenvironmental liabilities or able to predict the ultimate cost of liabilitiesnot yet recognized. We have recorded an asset retirement obligation inconnection with the estimated future costs to plug certain wells in ourMadisonville Project in Texas upon abandonment totaling approximately $53,726as of December 31, 2007.

 

***Our natural gas deliveries to the Madisonville gas treatmentplant may be affected by the demands of Crimson Exploration, Inc. (“Crimson”)and other third parties for access to the plant, and as a result, our access tothe plant could be restricted.***

 

We are dependent upon theMadisonville gas treatment plant to treat our natural gas. We have committedall natural gas production from our interest in the Madisonville Project toMGP, which has in turn committed to provide treatment capacity of up to 68MMcf/d for our natural gas. Third parties may seek access to the gas treatmentplant through regulatory proceedings, which could restrict our access to theplant, disrupt our production operations and negatively impact our revenues. Anexample of such a proceeding is the complaint filed by Crimson with the TexasRailroad Commission described under “Properties—Description of theProperties—Texas—The Madisonville Gas Treatment Plant and Gathering Facilities.”On August 9, 2006, the Texas Railroad Commission issued an order requiringMGP to ratably process, take, transport or purchase natural gas produced byCrimson into the Madisonville gas treatment plant. MGP  completed additional treating facilities toincrease the design capacity from 18 MMcf/d to 68 MMcf/d  in November of 2007, but operations inthese additional facilities were suspended in December 2007 in order tomore effectively deal with the presence of diamondoids in the gas streamproduced from the Rodessa Formation. There is no guarantee that we will be ableto obtain full access to treatment capacity of up to 68 MMcf/d once thephase-in is completed because, for example, Crimson now has the right to haveits natural gas treated at the plant, which may reduce the plant’s ability totreat all of our natural gas, unless the plant’s capacity is further expanded.

 

***Political and/or economic conditions in Indonesia, Canada orthe United States could change in manners that negatively affect ouroperations and prospects in those countries.***

 

Our business activitiesin Indonesia, Canada and the United States are subject to political and economicrisks, including: loss of revenue, property and equipment as a result ofunforeseen events like expropriation, nationalization, war, terrorist attacksand insurrection; increases in import, export and transportation regulationsand tariffs, taxes and governmental royalties; renegotiation of contracts withgovernmental entities; changes in laws and policies governing operations offoreign-based companies; exchange controls, currency fluctuations and otheruncertainties arising out of foreign government sovereignty over internationaloperations; laws and policies affecting foreign trade, taxation and investment;and the possibility of being subject to the exclusive jurisdiction of foreigncourts in connection with legal disputes and the possible inability to subjectforeign persons to the jurisdiction of courts in the United States.

 

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***Terrorist attacks could have an adverseeffect on our oil and natural gas operations, especially overseas.***

 

To date, our operationshave not been disrupted by terrorist activity. It is uncertain how terroristactivity will affect us in the future, or what steps, if any, the Indonesian,Canadian or American government may take in response to terrorist activities.The attack on the New York World Trade Center in 2001 and the subsequentwars in Afghanistan and Iraq have increased the likelihood thatU.S. citizens and U.S. owned interests may be targeted by terroristgroups operating both in the United States and in foreign countries,especially in Indonesia.

 

***We could lose our entire Production Sharing Contract (“PSC”),if BP Migas ascertains we have not discovered commercially produciblehydrocarbons.***

 

It is possible that BPMigas could terminate our entire Production Sharing Contract (“PSC”) if it isdetermined that the hydrocarbons we have discovered are not in commerciallyproducible quantities.  Our IndonesianPSC requires us and our partners to submit to and receive approval from BPMigas for a “Plan of Development”  by specifieddates in order 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 suchobligations are not secured, we will need to record an impairment charge equalto the amount of costs capitalized which were approximately $582,946 as of December 31,2007, and we may lose all of our rights in the Bengara Block.

 

***We may not be able to sell our natural gas production inIndonesia, limiting our ability to obtain a return on our investment there.***

 

Our Indonesian operationslack a local market for natural gas, and if we produce natural gas inIndonesia, it will most likely have to be transported to an area where there isa demand. If no market for natural gas develops locally, we may incur costs fortransportation. If we are not able to sell our natural gas production at acommercially acceptable price or at all, we may not be able to obtain a returnon our investment in our Indonesian property.

 

***We could lose our ownership interests inour properties due to a title defect of which we are not presently aware.***

 

As is customary in theoil and gas industry, only a perfunctory title examination, if any, isconducted at the time properties believed to be suitable for drilling operationsare first acquired. Before starting drilling operations, a more thorough titleexamination is usually conducted and curative work is performed on knownsignificant title defects. We typically depend upon title opinions prepared atthe request of the operator of the property to be drilled. The existence of atitle defect on one or more of the properties in which we have an interestcould render it worthless and could result in a large expense to our business.Industry standard forms of operating agreements usually provide that theoperator of an oil and natural gas property is not to be monetarily liable forloss or impairment of title. The operating agreements to which we are a partyprovide that, in the event of a monetary loss arising from title failure, theloss shall be borne by all parties in proportion to their interest owned.

 

***Our acquisition activities are subject to uncertainties, maynot be successful and provide a return to us on our investments.***

 

We have grown primarilythrough acquisitions and intend to continue acquiring undeveloped oil and gasproperties. Although we perform a review of the properties proposed to beacquired, such reviews are subject to uncertainties. It generally is notfeasible to review in detail every individual property involved in anacquisition. Ordinarily, management review efforts are focused on thehigher-valued properties; however, even a detailed review of all properties andrecords may not reveal existing or potential problems; nor will it permit us tobecome sufficiently familiar with the properties to assess fully theirdeficiencies and capabilities. Inspections are not always performed on everywell, and potential problems, such as mechanical integrity of equipment andenvironmental conditions that may require significant remedial expenditures,are not necessarily observable even when an inspection is undertaken.

** **

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***Weare dependent upon our key officers and employees and our inability to retainand attract key personnel could significantly hinder our growth strategy andcause our business to fail.***

 

While no assurances canbe given that our current management resources will enable us to succeed asplanned, a loss of one or more of our current directors, officers or keyemployees could severely and negatively impact our operations and delay orpreclude us from achieving our business objectives. Stuart Doshi, David Creeland Chris Steinhauser, the three members of our senior management team, have acombined experience of approximately 100 years in the oil and gas industry.Although we have entered into employment agreements with Messrs. Doshi,Creel and Steinhauser, we could suffer the loss of key individuals for onereason or another at any time in the future. There is no guarantee that wecould attract or locate other individuals with similar skills or experience tocarry out our business objectives. We maintain “key man” insurance withrespect to our Chief Executive Officer, Stuart Doshi.

 

***Some of our directors may become subject to conflicts ofinterest which could impair their abilities to act in our best interest.***

 

Nick DeMare, one ofour directors, is a director, officer and/or significant shareholder of othernatural 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 arerequired by law to act honestly and in good faith with a view to our bestinterests and to disclose any interest which they may have in any project oropportunity to us; however, their interests in the other companies may affecttheir judgment and cause such directors to act in a manner that is notnecessarily in our best interests.

 

***Our directors and officers hold significant positions in ourshares and their interests may not always be aligned with those of our othershareholders.***

 

As of December 31,2007 our directors and officers beneficially own approximately 20% of ouroutstanding common stock. This shareholding level will allow the directors,officers and certain beneficial owners to have a significant degree ofinfluence on matters that are required to be approved by shareholders,including the election of directors and the approval of significanttransactions. The short-term interests of our directors, officers and certainbeneficial owners may not always be aligned with the long-term interests of ourpublic shareholders, and vice versa. Because our directors, officers andcertain beneficial owners have a significant degree of influence on mattersthat are required to be approved by our shareholders, they could influence theapproval of transactions.

 

***Our failure to manage internal or acquisition-based growthmay cause operational difficulties and negatively affect our financialperformance.***

 

We expect to experienceinternal and/or acquisition-based growth, which may bring many challenges.Growth in the number of employees, sales and operations will place additionalpressure on already limited resources and infrastructure. No assurances can begiven that we will be able to effectively manage this or future growth. Ourgrowth may place a significant strain on our managerial, operational, financialand other resources. Our success will depend upon our ability to manage ourgrowth effectively which will require that we continue to implement and improveour operational, administrative and financial and accounting systems andcontrols and continue to expand, train and manage our employee base. Oursystems, procedures and controls may not be adequate to support our operationsand our management may not be able to achieve the rapid execution necessary toexploit the market for our business model. If we are unable to manage internaland/or acquisition-based growth effectively, our business, results ofoperations and financial condition will be materially adversely affected.

 

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**Risks Related to Our Common Stock**

 

***The shareholding position of holders of our common stockcould be diluted by future issuances and conversions of other securities.***

 

If our options andwarrants are exercised for common shares, holders of our common stock willexperience immediate and, depending on the magnitude of the exercises,substantial dilution. As of the date of this report, 2,441,688 shares of ourcommon stock are issuable upon exercise of warrants and 2,670,000 shares of ourcommon stock are issuable upon exercise of options.

 

Investors may be subjectto further dilution if we sell additional common shares or issue additionalcommon shares in connection with future financings. If a significant number ofour common shares are sold in the public market, the market price of our commonshares could be depressed. This could hamper our ability to raise capital byissuing additional equity securities.

 

***Our results may be affected by fluctuationsin currency exchange rates.***

 

Our financial statementsare reported in U.S. dollars and all of our revenue, and most of ouroperating costs, are currently denominated in U.S. dollars; however, wehave operations outside the United States and we plan to expend money inIndonesia and Canada, where our operating costs will be denominated in localcurrencies. Fluctuations in exchange rates may increase our relative cost ofoperating in these countries, and may therefore have a negative effect on ourfinancial results.

 

***Non- U.S. holders of our common shares may be subject toU.S. federal income tax on the sale of our common shares and purchasers mayhave IRS withholding requirements***

 

Since we believe that weare a United States real property holding corporation, gain recognized by a nonU.S. holder on the sale of our common shares will be subject to U.S. federalincome tax at normal graduated rates, and a purchaser will be required towithhold for the benefit of the IRS 10% of the purchase price, unless certaintrading requirements are met. There is an exemption from U.S. federal incometax for non-U.S. holders of 5% or less of our common shares (and therefore notax withholding requirements) if our common shares are “regularly traded on anestablished securities market.”  In the event that 100 or fewer personsown 50% or more of our common shares (which had been, may now be and maycontinue to be, the case), temporary Treasury Regulations provide that ourcommon 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 American Stock Exchange (which constitutes anestablished United States securities market for this purpose) and are beingregularly quoted. There can be no assurance, however, that our common shareswill continue to be regularly traded on an established securities market forthis purpose in any particular calendar quarter so as to avoid U.S. federalincome tax on the sale of our common shares by non-U.S. holders of 5% or lessof our common shares and the withholding requirement on the purchaser.

 

At such time that it isno longer the case that 100 or fewer persons own 50% or more of our commonshares, under temporary Treasury Regulations, our common shares would also be “regularlytraded” on an established securities market for a calendar quarter if:  (a) ourcommon shares trade, other than in de minimis quantities, on at least 15 daysduring the calendar quarter; (b) the aggregate number of our common sharestraded during the calendar quarter is at least 7.5% of the average number ofour common shares outstanding during such calendar quarter (reduced to 2.5% ifthere are 2,500 or more record shareholders); and (c) in the event thatour common shares are traded on an established securities market locatedoutside the United States, the common shares are registered under Sec. 12 ofthe Securities Exchange Act of 1934 (which is presently the case). See “MaterialIncome Tax Consequences — Dispositions of Common Shares” for a more detaileddiscussion.

 

***There is a limited public market for our common shares, andthe ability of our shareholders to dispose of their common shares may belimited.***

 

Our common shares havebeen listed on The Toronto Stock Exchange since March 2006, and have beentrading on the American Stock Exchange since February 15, 2007. We cannotforesee the degree of liquidity that will be associated with our common shares.A holder of our common shares may not be able to liquidate his, her or itsinvestment in a short time period or at the market prices that currently existat the time the holder decides to sell. The purchase and sale of relativelysmall common share positions may result in disproportionately large increasesor decreases in the price of our common shares. A trade involving a largenumber of common shares could have an exaggerated effect on the reported marketprice of our common shares.

 

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

 

The stock market ingeneral and the market for natural gas and oil exploration companies have experiencedprice and volume fluctuations that are often unrelated or disproportionate tothe operating results or asset values of companies. These broad market andindustry factors may seriously impact the market price and trading volume ofour common shares regardless of our actual operating performance. The marketprice of our common stock could also fluctuate significantly as a result of:

 

·       actual or anticipated quarterly variations in ouroperating results and our reserve estimates;

 

·       changes in expectations as to our future financialperformance or changes in financial estimates, if any, of public marketanalysts;

 

·       announcements relating to our business or the businessof our competitors;

 

·       conditions generally affecting the oil and natural gasindustry, including changes in oil and natural gas prices;

 

·       speculation in the press or investment community;

 

·       general market and economic conditions;

 

·       the success of our operating strategy; and

 

·       the operating and stock price performance of othercomparable companies.

 

***The sale of large numbers of our common stock may depressthe market price of our common stock.***

 

The sale of a substantialnumber of shares of our common stock in the public market, or the perceptionthat substantial sales may occur, could cause the market price of our commonstock to decrease. Substantially all of the shares of our common stock arefreely transferable or will be transferable in compliance with restrictionsunder the Securities Act of 1933, as amended.

 

***We will continue to incur significant expenses as a resultof being a public company, which may negatively impact our financialperformance.***

 

We have incurred and willcontinue to incur significant legal, accounting, insurance and other expensesas a result of being a public company. The Sarbanes-Oxley Act of 2002, as wellas related rules implemented by the Securities and Exchange Commission, orSEC, and the American Stock Exchange, have required changes in corporategovernance practices of public companies. Compliance with these laws, rules andregulations has increased our expenses, including our legal and accountingcosts, and made some activities more time-consuming and costly. We also believethese laws, rules and regulations have made it more expensive for us toobtain director and officer liability insurance, and in the future we may berequired to accept reduced policy limits and coverage or incur substantiallyhigher costs to obtain the same or similar coverage. As a result, it may bemore difficult for us to attract and retain qualified persons to serve on ourboard of directors or as officers. Furthermore, any additional increases inlegal, accounting, insurance and certain other expenses that we may experiencein the future could negatively impact our financial performance and have amaterial adverse effect on our results of operations and financial condition***.***

 

**Item 1B. *UnresolvedStaff 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.

 

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** **

**Descriptionof the Properties**

** **

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

 

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

 

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

 

·       **Indonesia**—onshore East Kalimantan Province;

 

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 4,941 gross and net acres of leases in the RodessaFormation interval, as well as approximately 4,348 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 the MadisonvilleField.

 

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 629 gross and net acres. The Magness Wellcommenced production in May of 2003.

 

The first developmentwell, the Fannin Well, was drilled and completed in 2004. We own a 100% workinginterest (69.2483% net revenue interest) in the Fannin Well located in thesurrounding production unit consisting of 704 gross (704 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.

 

In 2006, we drilled theWilson and Mitchell wells. We own a 100% working interest (70% net revenueinterest) in the Wilson and Mitchell wells. Presently, the Fannin and Magnesswells are producing at a combined restricted rate of approximately 13.5 MMcf/dwhile the Wilson and Mitchell wells are shut-in. The production rate ispresently restricted while awaiting a planned expansion of the MadisonvilleField gas treatment plant to 68 MMcf/d treating capacity.

 

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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 and probable undeveloped locations.Production began in May 2003 and stabilized at a rate of 18 MMcf/d ofraw gas from the Magness Well. The Magness and Fannin wells are currentlyproducing at a combined restricted rate of approximately 13.5 MMcf/d.Current net sales production is approximately 8 MMcf/d. In addition, weown a working interest in certain leases and farmout rights which cover depthsbelow the Rodessa Formation.

 

The hydrogen sulphide,carbon dioxide and nitrogen combined comprise about 28% of the gas content. Asdescribed below, an unaffiliated third party purchases the untreated naturalgas from us at the well site point of delivery for a net price equal to theweighted average price per MMBTU that the third party receives for the naturalgas delivered to the sales pipeline less certain gathering, treatment andtransportation charges. As a result of the charges, we receive a net price thatis substantially lower than we would otherwise receive if the gas did notcontain the 28% of impurities. In addition, the high concentrations of hydrogensulphide and carbon dioxide result in higher capital and operating costs forour wells. For example, the hydrogen sulphide and carbon dioxide are corrosiveto the wellbores. This means we have to utilize higher grade specification welltubing and casing which is more expensive than what we would utilize absent theimpurities. In addition, we continuously treat the wellbores with chemicalsdesigned to inhibit the corrosive effects of the impurities. We also maintainfield personnel at or near the wellsites who monitor the wells on a twenty fourhour basis and equip the wellsites with extensive safety equipment systems dueto the toxic properties of the hydrogen sulphide and carbon dioxide. Thesefactors and others result in higher capital and operating costs for our wellsin the Madisonville Project.

 

*The Madisonville Gas Treatment Plant and GatheringFacilities*

* *

In order to produce theproven 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.The natural gas plant is currently capable of treating approximately up to15 MMcf/d of inlet natural gas.

 

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 will represent a total treating capacityof 68 MMcf/d for the Madisonville treatment plant. The MGP Agreementprovides that the newly installed gas treatment facilities will be electricallydriven. Currently, the existing in-service treatment plant utilizes some of thenatural gas produced and delivered from our well(s). The conversion toelectricity on the expanded portion of the treatment plant is expected toreduce shrinkage of our natural gas that occurs in the treating process.

 

Originally, the MGPAgreement required MGP to complete the additional treating facilities by March 1,2006.  However, due to events of forcemajeure, construction of the additional treating facilities were just completedin October 2007 and early phase operations at the additional treatingfacilities were recently suspended.  Inearly November 2007, MGP began accepting 20 million cubic feet of gas perday MMcfd at the inlet of the additional treating facilities.   Subsequentlyin December 2007, MGP temporarily suspended the operations of theadditional treating facilities in orderto make modifications to more effectively deal with the presence of diamondoidsin the gas stream produced from the Rodessa Formation. A diamondoid is a rare,naturally occurring compound that can segregate out of the gas stream upon adecrease in temperature and pressure 

 

20

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andas such, could cause operational problems for the nitrogen rejection portion ofthe additionaltreating facilities.  MGP has obtained a detailed laboratorycomposition analysis of the diamondoids and is currently finalizing plans formodifications to the operating system. MGP indicates that removal of the diamondoids will requireflowing the natural gas stream through a diesel contactor after the gas streamhas had the hydrogen sulfide and carbon dioxide removed.  Through this contactor process, the dieselwill absorb the diamondoids from the gas stream prior to entry into thenitrogen removal tower.  MGP expects to complete installation of thesystem modifications required in the new plant by the second quarter of2008.  In the meantime, the existing, inservice portion of the plant continues to treat approximately 15 million cubicfeet per day of inlet gas.

 

We have proceeded todrill and complete our new development wells notwithstanding MGP’s delay incompleting the expansion of the treatment plant and subsequent suspension ofoperations in December 2007. To the extent that production begins at thenew wells before operations resume, as is the case with the Fannin Well whichwas placed on production in March 2006, production of the wells will berestricted as necessary. The term of the MGP Agreement commenced August 1,2005 and continues so long as we own any oil and gas leases in the MadisonvilleField, provided that it shall terminate on July 31, 2035 unless extended.Under the terms of the MGP Agreement, we have committed all natural gas productionfrom our interest in the Madisonville Project to MGP. MGP purchases theuntreated natural gas from us at the well site point of delivery for a netprice equal to the weighted average price per MMBTU that MGP receives for thenatural gas delivered to the sales pipeline less certain gathering, treatmentand transportation charges. The gathering, treatment and transportation priceadjustments are described below. All proceeds from MGP’s sale of RodessaFormation gas are deposited in an escrow account and then disbursed inaccordance with the joint direction of MGP and ourselves.

 

The MGP Agreementprovides that certain gathering, treating and transportation fees shall be paidto MGP from the escrow account. The MGP Agreement provides that MGP will receivea gathering and marketing fee of $0.07 and $0.01 per Mcf, respectively, of gasmeasured and delivered to the natural gas treatment plant. In addition, for thefirst 18,000 Mcf/d of gas measured and delivered to the inlet flange ofthe gas treatment plant, MGP will receive a treating fee of $1.50 per Mcf. Thistreating fee will remain in effect until September 30, 2010. For any gasvolumes in excess of 18,000 Mcf/d of gas delivered to the inlet flange ofthe gas treatment plant, MGP will receive a treating fee of $1.10 per Mcf.Beginning October 1, 2010, this fee of $1.10 per Mcf shall be charged forall gas measured and delivered to the plant. One-quarter (1/4)of the foregoing treating fees are adjusted using the Producer Price Index forIndustrial Commodities (“**PPI**”) andone-quarter (1/4) using the Consumer Price Index (“**CPI**”). One-half (1/2) of the foregoinggathering and marketing fees are adjusted using the CPI. We have the right,upon giving 60 days notice, to terminate the marketing fee whereupon weshall assume the sole responsibility of marketing the natural gas sold.The **PPI** and the **CPI**are price indices published by the U.S. Department of Labor.

 

For the first18,000 Mcf/d of gas measured and delivered to the inlet flange of the gastreatment plant, Gateway will receive a transportation fee of $0.10 per Mcf.This fee will remain in effect through July 31, 2008. Beginning August 1,2008 and terminating on July 31, 2010, the fee shall be reduced to $0.08per Mcf for the first 18,000 Mcf/d of gas measured and delivered to theinlet flange of the gas treatment plant. For any gas volumes in excess of18,000 Mcf/d of gas measured and delivered to the inlet flange of the gastreatment plant, Gateway will receive a transportation fee of $0.12 per Mcf measuredand delivered from the outlet flange of the plant. This fee will remain ineffect through July 31, 2008 and shall be reduced to $0.10 per Mcfthereafter. After July 31, 2010, this transportation fee shall be $0.10per Mcf for all volumes delivered from the outlet flange of the plant.

 

The foregoing gathering,treatment and transportation price adjustments are inclusive of all costs andexpenses to gather, separate, treat, dehydrate and transport natural gasproduced and delivered from our well(s).

 

Our natural gasdeliveries to the Madisonville gas treatment plant may be affected by thirdparty demands for access to the plant. On July 20, 2005 CrimsonExploration Inc. (“**Crimson**”)filed a complaint with the Texas Railroad Commission (“**TRC**”) against Gateway and Hanover. Thecomplaint alleged discrimination by Hanover and Gateway, and requested that theTRC issue an order requiring Hanover and Gateway to ratably process, take,transport, or purchase natural gas produced by Crimson into the Madisonville Fieldgas treatment plant. The complaint did not allege any wrongdoing by Redwood orRedwood LP; however, the complaint referred to the contractualrelationship between each of Redwood LP, Hanover, and Gateway which wasterminated July 25, 2005 as the basis for its discrimination complaint.Redwood received a subsequent notice dated January 13, 2006 from the TRCinforming Redwood that (i) Crimson had filed a request to docket itscomplaint against MGP for failure to ratably take gas pursuant to Texasregulations and (ii) a pre-hearing conference was held on January 25,2006 relating to the complaint. Redwood withdrew from the proceeding.

 

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On January 23, 2006,our counsel received a letter from counsel for MGP reaffirming that regardlessof the outcome of the proceedings before the TRC, MGP nonetheless recognizesthat it has a contractual obligation to treat 68 MMcf/d of natural gasproduced by Redwood LP and delivered to the treatment plant. After consultationwith legal counsel, we believe that our contract with MGP is fully enforceable.

 

On August 9, 2006,the Texas Railroad Commission issued an order requiring MGP to ratably process,take, transport or purchase natural gas produced by Crimson into the Madisonvillegas treatment plant. The gas treatment plant is currently operating atcapacity. There is no guarantee that we will be able to maintain full access totreatment capacity of up to 68 MMcf/d at the Madisonville Plant at alltimes because, for example, Crimson now has the right to have its natural gastreated at the plant, which may reduce the plant’s ability to treat all of ournatural gas, unless the plant’s capacity is further expanded.

 

To date, Crimson haspermitted four wells to be drilled to the Rodessa Formation. The drilling oftwo of these wells has been completed to a depth of approximately 12,635 feet.Crimson has also drilled an injection well for disposal of waste productsresulting from the treatment of their natural gas.  Crimson is presently delivering gas to thetreatment plant.

 

We have committed to athree-well drilling program to facilitate the expansion of the gas treatmentplant. We have drilled two of the three required wells to the Rodessaformation.  The commitment requires us todrill the third well sufficient to test the Smackover Formation (estimated tobe encountered at approximately 18,000 feet) on or before September 30,2008. We estimate the 18,000 foot well will cost $12 million to drill andcomplete. We have granted MGP a security interest in the Madisonville Fieldproperties to secure the three well commitment. The security interest shall besubordinated to any third party lender in the event we secure future debtagainst the property. MGP granted us a similar security interest in the gastreatment plant to secure its obligation to expand the treatment plant on atimely basis.

 

*OtherInterests in the Madisonville Project*

* *

Our working interest inthe Madisonville Project is subject to a net profits interest in favor of the thirdparty that sold us our working interests in the Madisonville Project. The netprofits interest is 12.5% (proportionately reduced to our interest) of the netoperating profits until payout is achieved. After payout, the net profitsinterest increases to 30% (proportionately reduced to our interest). “Payout”,for purposes of the net profits interest, is defined and achieved at such timeas we have recouped from net operating cash flows our total net investment inthe Madisonville Project plus a 33% cash on cash return.

 

*South Dry Hollow Project, Lavaca County, SouthTexas*

 

We own a 15% non-operatedworking interest in approximately 2,000 gross and 300 net acres of leases inLavaca County, South Texas.  A test well,the Willstar Eichhorn No. 1 well (the “Willstar well”), has commenceddrilling and is expected to be drilled to a total depth of 17,000 feet.  The primary objective of this well is to testthe Rochelle sands in the Lower Wilcox formation.  Secondary objectives include the “10,500”,Peck, Dagg, Lampley and Massive sandstone formations in the Wilcoxformation.  The Willstar well is avertical well located approximately 800 feet south of the Eichhorn Gas Unit No. 1well drilled by Newfield Exploration Company (the “Newfield well”) in2002.  The Newfield well was completed in2002 in the Lampley member of the Wilcox formation at an initial rate of 3.8MMcfd and has produced approximately 0.9 Bcf of natural gas.  The Newstar well also encountered natural gasshows  in the Rochelle, “10,500”, Peck,Dagg, and Massive members of the Wilcox formation which were not tested.

 

***Alaska***

*** ***

*TheCook Inlet Alaska CBM Project*

* *

We entered into anagreement with Pioneer Oil Company, Inc. (“**Pioneer**”)dated April 20, 2005, wherein we secured the Cook Inlet Option to acquirea 100% working interest, 81% net revenue interest, in approximately116,806 acres onshore 

 

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in Cook Inlet, Alaska. We have since acquired 5,368additional acres. We believe this acreage to be prospective for both coal bedmethane and conventional gas production.

 

The 122,174 acrelease position consists of two separate target areas that have been selectedfor exploration. These areas are called the Point MacKenzie and Trading BayProspects, respectively.

 

The Point MacKenzieProspect is located twelve miles northwest of Anchorage. The Trading BayProspect is located 50 miles west of Anchorage across the Cook Inlet. TheCook Inlet basin contains a thick section of terrestrial Tertiary rocks whichincludes shales, sandstones, and coals. The coals occur in seams which arecommonly 20 feet thick and can be as thick as 70 feet. Accessibleonshore areas have 200 to 300 feet of coal shallower than5,000 feet. Gas content for these coals ranges from 80 to 250 standardcubic feet per ton, but testing is restricted to a very small number ofbore holes and is almost completely unknown for most of the inlet.

 

Markets for natural gasin the Cook Inlet area include power generation, heating, fertilizer productionand liquefied natural gas exports. An extensive pipeline system supplies thesefacilities and crosses the Point MacKenzie Prospect and Trading Bay Prospectlease blocks. These pipelines are only partially filled with gas and couldaccommodate additional production.

 

In addition to coal bedmethane reserve potential, preliminary log analysis indicates the PointMacKenzie Prospect and Trading Bay Prospect lease blocks may also containconventional accumulations of natural gas reserves in Tertiary sandstones.

 

The terms of the CookInlet Option provide for us to pay total consideration of $20 per acre, orapproximately $2.3 million, for the leases. The Cook Inlet Option providesthat we will pay the total lease consideration in two installments. We paid thefirst installment totaling $1,068,063 on August 17, 2005 and we havereceived assignment of the 100% working interest in the leases. Within threeyears from the date of receipt of assignment of the 100% working interest inthe leases, we have the option to conduct a $2.5 million work program onthe leases over a three-year period, and, after completion of the work programand an evaluation of the results, to remit the final additional acreageconsideration of $10 per acre for the leases. The Cook Inlet Option providesthat if we fail to pay the lease consideration when due, fail to perform thework program or otherwise default under the Cook Inlet Option, we shall forfeitour interest and reassign the leases to Pioneer, and we will have no furtherliability to Pioneer.

 

Approximately one to twomiles of pipeline will be required to tie in any wells drilled at a currentlypreferred location at the Point MacKenzie Prospect, and approximately four tofive miles of the pipeline will be required to tie in any wells drilled at acurrently preferred location at the Trading Bay Prospect. We have not yetprepared an estimate of the cost to tie these wells in.

 

We are aware of two majorpipelines which transverse the acreage blocks, the Enstar 20” line and theUnoCal-Marathon 16” line. We estimate the UnoCal-Marathon 16” linepresently has available unused capacity of approximately 40 MMcf/d. Inaddition, we estimate the Enstar 20” line has available unused capacity ofapproximately 100 MMcf/d.

 

***California***

*** ***

*LokernProject*

* *

We have a workinginterest in the Lokern Project, located in the southern San Joaquin basin, nearBakersfield, California. The primary exploration objective is the MioceneStevens formation. The secondary objectives include the Miocene Reef Ridge andPliocene Etchegoin sands. The Stevens formation is Upper 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 that 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 third party,to a depth of 15,000 feet in 2009.

 

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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*

* *

The Swan Hills Project islocated in the Central Alberta Basin, Alberta, Canada. The primary explorationobjective is the Swan Hills Formation at approximately 9,000 feet. Secondaryobjectives will include the shallower Gilwood, Nordegg and Falher formations.

 

We, through our wholly-ownedsubsidiary, GeoPetro Canada, have reviewed 3-D seismic data over the prospectand plan to participate in the drilling of a test well. We have a 33% workinginterest in approximately 4,480 leased acres.

 

***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.

 

The Bengara Block islocated in the Tarakan Basin, mostly onshore but partially offshore astride theBulungan River Delta in the Indonesian province of East Kalimantan. Itoriginally covered a single contiguous area of approximately 1.2 milliongross acres, of which 300,000 gross acres were relinquished in 2001 and anadditional 300,000 gross acres were relinquished in 2007 by C-G Bengara inaccordance with the terms of the Bengara II PSC. C-G Bengara has tenderedan additional relinquishment such that the remaining acreage within the BengaraII PSC total approximately 240,000 acres, or 970 square kilometers.  The remaining 240,000 acres is considered byC-G Bengara to be the most prospective portion of the original 1.2 million acreblock and is pending approval from BP Migas.

 

*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 barge positionedon one of the Bulungan River Delta mouth channel distributaries. The well wasdrilled to a total depth of 10,800 feet and tested 19.5 million cubic feetof gas per day together with 600 bbls of 54 degree API condensate perday from a 33 feet thick sandstone section near 6,000 feet. The wellwas plugged and abandoned as a natural gas discovery. Several other gas zonesindicated on logs were not tested. The well was not produced nor were anyconfirmation wells drilled due to the lack of a local natural gas market at thetime the well was drilled. The Makapan Gas Field gas is a “Wet’ gas with ahigh LPG fraction which may be commercial to extract at the wellhead for athird revenue source in addition to the gas and condensate. The Makapan GasField lies mostly offshore in very shallow water, less than 10 feet,amidst numerous islands of the Bulungan 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.

 

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

 

Several separate andunique geologic plays within the Bengara Block as well as a number of prospectsand leads have been identified. Some well-defined prospects present immediatedrilling targets. Exploration within the Bengara Block is in its formativestages 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 commercialhydrocarbons are discovered within the contract area. At the end ofsix years, unless mutually extended by C-G Bengara and BP Migas, thecontract expires if no commercially producible hydrocarbons have beendiscovered in the contract area. C-G Bengara and BP Migas have mutually extendedthe early termination provisions until December 3, 2008. C-G Bengara mayterminate the contract at any time by relinquishing all of its rights andobligations under the contract area. C-G Bengara is required to relinquish 25%of the contract area within the first three years of the contract, a further25% of the contract area within six years from the commencement of the contractand an additional area within the first ten years so that the area retainedthereafter shall not be in excess of 970 square kilometers, or 20% of theoriginal total contract area, whichever is less. C-G Bengara may designatewhich areas are to be relinquished subject to approval by BP Migas. C-GBengara’s obligation to relinquish parts of the original contract area underthese provisions does not apply to the surface area of any field in whichpetroleum has been discovered. To date, 600,000 gross acres have been relinquished by C-G Bengara inaccordance with the terms of the Bengara II PSC. In 2007, C-G Bengaratendered an additional relinquishment such that the remaining acreage withinthe Bengara II PSC shall total approximately 240,000 acres, or 970 squarekilometers.  The remaining 240,000 acresis considered by C-G Bengara to be the most prospective portion of the original1.2 million acre block and is pending approval from BP Migas.

 

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  |   |

 

Inorder to maintain the Bengara II PSC in effect, C-G Bengara is required tocomplete the following work programs and expenditures during the first tenyears of the contract, unless the requirement is extended or waived byBP Migas:

** **

**25**

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| **Contract Year** | ** ** | **Work Program**            | ** ** | **Amount** | ** ** | **Our 12% Share** | ** ** |
|------------------------|------------|----------------------------------|------------|------------|------------|-----------------------------|------------|
| 1998                   |       | Geologic and geophysical studies |       | $          | 500,000    |                        | $          | 60,000 |   |
| 1999                   |       | Seismic reprocessing             |       | 500,000    |       | 60,000                      |       |
| 2000                   |       | Drill two wells                  |       | 6,000,000  |       | 720,000                     |       |
| 2001                   |       | Geologic and geophysical studies |       | 1,000,000  |       | 120,000                     |       |
| 2002                   |       | Drill one well                   |       | 5,000,000  |       | 600,000                     |       |
| 2003                   |       | Acquire seismic                  |       | 3,750,000  |       | 450,000                     |       |
| 2004                   |       | Drill one well                   |       | 5,250,000  |       | 630,000                     |       |
| 2005                   |       | Evaluate well results            |       | 1,000,000  |       | 120,000                     |       |
| 2006                   |       | Geologic and geophysical studies |       | 1,000,000  |       | 120,000                     |       |
| 2007                   |       | Geologic and geophysical studies |       | 1,000,000  |       | 120,000                     |       |
|                   |       | TOTAL                            |       | $          | 25,000,000 |                        | $          | 3,000,000 |   |

 

C-G Bengara has fulfilledthe minimum work and cash expenditure requirements described above. Uponestablishing commercial production, if ever, C-G Bengara and BP Migasshall share ratably in the first 20% of oil and natural gas produced in thecontract area within a given year according to the percentages specified below.After the first 20% of production, C-G Bengara is entitled to receive 100% ofproduction until cost recovery has been achieved. Cost recovery generallyincludes 100% of the operating and drilling costs and depreciation of fixedassets applicable to oil and natural gas operations within the contract area.After C-G Bengara has received oil and natural gas production with a valuesufficient to achieve cost recovery in a given year, C-G Bengara andBP Migas shall then share ratably in the production according to thepercentages 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                         | %          |

 

Upon the completion offive years after commercial production commences, C-G Bengara is furthersubject to a domestic market obligation. This obligation requires C-G Bengarato sell and deliver to BP Migas, to meet Indonesia’s domestic crude oilneeds, a specified quantity of crude oil at a price which is only 15% of themarket price of the oil. However, for new fields, for a period of five yearsstarting on the month of the first delivery of crude oil produced from a newfield, the fee per barrel for such crude oil supplied to the Indonesiandomestic market shall be the market price, with the condition that the excessover the 15% of market price shall preferably be used to assist financing ofcontinued exploration efforts in the contract area.

 

Upon the first commercialdiscovery of oil or natural gas in the contract area, BP Migas has theright to demand that 10% of C-G Bengara’s undivided interest in the totalrights and obligations under the Bengara II PSC be offered to itselfor an entity owned by Indonesian nationals. The 10% interest shall be offeredat a dollar amount equal to 10% of C-G Bengara’s cumulative costs incurredin the contract area.

 

*Current and Planned Activities in the Bengara Block*

 

In accordance with theterms of our agreement dated September 29, 2006 which sold 70% of ourinterest in C-G Bengara to CNPC, CNPC:

 

1.                                       Purchased 14,000 and 21,000 shares of C-GBengara from us and Continental, respectively, at a cost of $1 per share. As aresult of the transaction, we and Continental own 6,000 and 9,000C-G Bengara shares, respectively, retaining a 12% and 18% interest in C-GBengara, respectively.

 

2.                                       Paid the sum of $18.7 million (the “**Earning Obligation**”) into a special jointventure account at a Hong Kong international bank. The funds are under jointsignature control of CNPC, ourselves and Continental, and are being expendedexclusively to pay for 2006 and 2007 exploration and/or appraisal drilling inthe Bengara II PSC area.

 

3.                                       Agreed to provide development loans topay 100%, and thereby “carry” our share and Continental’s share of all C-GBengara’s exploitation, drilling, and development expenditures attributable tothe Bengara II PSC, after the Earning Obligation funds are expended and a Planof Development has been approved by BP Migas, until an additional amount ofU.S. $41.3 million over and above the Earning Obligation funds has beenexpended.

 

26

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4.                                       Agreed to pay a cash bonus totaling$5,000,000, in the proportions of $2,000,000 to us and $3,000,000 toContinental, respectively, contingent upon and within fourteen business days ofthe receipt by C-G Bengara of the written approval from governmental authoritiesapproving the development of the first commercial oil or gas discovery withinthe Bengara II PSC contract area.

 

During 2007, C-G Bengaradrilled a total of four wells on the Bengara II PSC.  The results are as follows:

 

A.                                   The Seberaba-1 was originally planned toreach a total depth of 4,000 meters (13,120 feet). Drilling of the Seberaba-1terminated at a depth of 2,914 meters (9,558 feet) in the third of threesidetracks made from the original wellbore. Testing activity of the Seberaba-1 has been suspended. Approximately 150barrels of crude oil has been recovered by swabbing.  Flow test and pressure build up tests to datehave proved inconclusive due to apparent formation damage.  Any future re-entry is expected to beconducted with a different drilling mud and testing fluid program to avoiddamage to the target reservoir intervals.

 

B.                                     Drilling of the Seberaba-3 has beencompleted to a total depth of 2,594 meters (8,508 feet). An open hole drillstem test successfully flowed oil and minor gas at surface from one zone. Theopen hole test confirms lateral continuity of the Seberaba reservoir with atleast one of the three zones from which oil was recovered during testing of theSeberaba-1 discovery well.  TheSeberaba-3 has been logged and casing has been set.

 

C.                                     Drilling activity on the Seberaba-4 hasbeen terminated.  Seberaba-4 failed toencounter an expected reservoir sand anticipated at 2,450 meters (8,036 feet)probably because the wellbore penetrated a normal fault and the expectedreservoir interval was faulted out. The Seberaba-4 wellbore has been suspendedand preserved for possible re-entry.

 

D.                                    Drilling of the Punga-1 has beencompleted at a total depth of 2,500 meters (8,200 feet). The well has beenlogged and casing has been set. A testing program may be conducted in thefuture by CG-B2 to evaluate zones with oil and gas shows.

 

The technical informationprovided by 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. Further testing of the Punga-1 welland Seberaba-3 well is expected to be conducted in 2008. In addition to these welltest results, C-G Bengara feels additional technical information is neededprior to finalizing the formal plan of development and submitting it forapproval to Indonesian oil and gas authorities. Approval of the formal plan ofdevelopment will automatically invoke the final 20-year production period ofthe Bengara-II PSC through December 3, 2027.  C-G Bengara has submitted the preliminaryplan to the Indonesian authorities together with a request for additional timeof three years to implement the plan and thereby obtain the additional dataneeded to further appraise and prove up the Seberaba discovery prior tocompleting and submitting the formal plan of development. Approval is expectedbut not assured.

 

*CGXploration*

* *

In November 2005, weand Continental formed CG Xploration to pursue new venture oil and gasexploration and production projects and obtain new exploration concessions inIndonesia. CG Xploration Inc. is incorporated in Delaware and isowned 50% by us and 50% by Continental. CG Xploration Inc. willactively pursue and may acquire new venture opportunities on behalf ofourselves and Continental. To date, CG Xploration has made noacquisitions.

 

**NaturalGas Reserves**

** **

Our estimated total netproved reserves of natural gas and oil as of December 31, 2007, 2006 and2005, and the present values of estimated future net revenues attributable tothose reserves as of those dates, are presented in the following tables.

 

27

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**“Proveddeveloped oil and gas reserves”**means reserves that can be expected to be recovered through existing wells withexisting equipment and operating methods. Additional oil and gas expected to beobtained through the application of fluid injection or other improved recoverytechniques for supplementing the natural forces and mechanisms of primaryrecovery should be included as “proved developed reserves” only after testingby a pilot project or after the operation of an installed program has confirmedthrough production response that increased recovery will be achieved.

** **

**“Proveddeveloped nonproducing reserves”** means reserves expected to be recovered from zones behind casing inexisting wells.

** **

**“Provedoil and gas reserves”** meansestimated quantities of crude oil, natural gas, and natural gas liquids whichgeological and engineering data demonstrate with reasonable certainty to berecoverable in future years from known reservoirs under existing economic andoperating conditions, i.e., prices and costs as of the date the estimate is made.Prices include consideration of changes in existing prices provided only bycontractual arrangements, but not on escalations based upon future conditions.

** **

(i)                                     Reservoirsare considered proved if economic producibility is supported by either actualproduction or conclusive formation test. The area of a reservoir consideredproved includes (A) that portion delineated by drilling and defined bygas-oil and/or oil-water contacts, if any; and (B) the immediatelyadjoining portions not yet drilled, but which can be reasonably judged aseconomically productive on the basis of available geological and engineeringdata. In the absence of information on fluid contacts, the lowest knownstructural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

(ii)                                  Reserveswhich can be produced economically through application of improved recoverytechniques (such as fluid injection) are included in the “proved”classification when successful testing by a pilot project, or the operation ofan installed program in the reservoir, provides support for the engineeringanalysis on which the project or program was based.

 

(iii)                               Estimatesof proved reserves do not include the following:

 

(A)                              oilthat may become available from known reservoirs but is classified separately as“indicated additional reserves”;

 

(B)                                crudeoil, natural gas, and natural gas liquids, the recovery of which is subject toreasonable doubt because of uncertainty as to geology, reservoircharacteristics, or economic factors;

 

(C)                                crudeoil, natural gas, and natural gas liquids, that may occur in undrilledprospects; and

 

(D)                               crudeoil, natural gas, and natural gas liquids, that may be recovered from oilshales, coal, gilsonite and other such sources.

 

**“Provedundeveloped reserves**” meansreserves that are expected to be recovered from new wells on undrilled acreage,or from existing wells where a relatively major expenditure is required forrecompletion. Reserves on undrilled acreage shall be limited to those drillingunits offsetting productive units that are reasonably certain of productionwhen drilled. Proved reserves for other undrilled units can be claimed onlywhere it can be demonstrated with certainty that there is continuity ofproduction from the existing productive formation. Under no circumstancesshould estimate for proved undeveloped reserves be attributable to any acreagefor which an application of fluid injection or other improved recoverytechnique is contemplated, unless such techniques have been proved effective byactual tests in the area and in the same reservoir.

** **

The 2007 and 2006estimates were prepared by MHA Petroleum Consultants, independent reservoirengineers, and are part of their reserve reports on our natural gas and oilproperties. The 2005 estimates were prepared by Sproule Associates Inc., independent reservoir engineers,and are part of their reserve reports on our natural gas and oilproperties.  MHA Petroleum Consultants’and Sproule Associates Inc.’s estimateswere based on a review of geologic, economic, ownership and engineering datathat we provided. In estimating the reserve quantities that are economicallyrecoverable, MHA Petroleum ConsultantsandSproule Associates Inc. usedend-of-period natural gas and oil prices. In accordance with U.S. Securitiesand Exchange Commission regulations, no price or cost escalation or reductionwas considered. All of our proved reserves are attributable to our MadisonvilleProject in Madison County, Texas.

 

28

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| ** **                     | ** ** | **AS OF DECEMBER 31,** | ** ** |
|--------------------------------|------------|---------------------------------------|------------|
| ** **                     | ** ** | **2007**                              | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                     | ** ** | **(MMcf)**                            | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
| Proved developed               |       | 10,495                                |       | 12,335 |   | 4,645 |   |
| Proved developed non-producing |       | 12,644                                |       | 12,365 |   | 8,903 |   |
| Proved undeveloped             |       | —                                |       | — |   | 7,881 |   |
|                           |       |                                  |       |   |   |   |   |
| Total                          |       | 23,139                                |       | 24,600 |   | 21,428 |   |

 

In accordance with Securitiesand Exchange Commission regulations, estimates of our proved reserves andfuture net revenues are made using sales prices estimated to be in effect as ofthe date of such reserve estimates and are held constant throughout the life ofthe properties, except to the extent a contract specifically provides forescalation. Estimated quantities of proved reserves and future net revenuestherefrom are affected by natural gas and oil prices, which have fluctuatedsignificantly in recent years. We filed reports with the U.S. Departmentof Energy in June 2007 and the Alberta Securities Commission in March 2007  that included total proved reserves inclusiveof royalties and net profits interests as of December 31, 2006 totaling43,517 MMcf. The total net proved reserves, excluding royalties and net profitsinterests, as of December 31, 2006 was 24,600 MMcf. The difference betweenthe two numbers represents proved reserves attributable to royalties and netprofits interests.

 

***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 flowswere computed by applying year-end prices to estimated annual future productionfrom proved gas reserves. The average year-end prices for gas were as indicatedbelow. Future development drilling and production costs were computed byapplying year-end costs to be incurred in producing and further developing theproved reserves. Future income tax expenses were computed by applying,generally, year-end statutory tax rates (adjusted for permanent differences,tax credits and allowances) to the estimated net future pre-tax cash flows. Thediscount was computed by application of a 10% discount factor. The calculationsassume the continuation of existing economic, operating and contractualconditions. However, such arbitrary assumptions have not proven to be the casein the past. Other assumptions of equal validity could give rise tosubstantially different results.

 
| ** **                                                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                | ** ** | ** **                                 | ** ** | **(in thousands)** | ** ** | ** ** | ** ** |
| Future cash inflows                                       |       | $                                          | 135,264    |   | $ | 101,867 |   | $ | 162,459 |   |
| Future production costs                                   |       | (45,649                                    | )          | (37,783 | ) | (60,176 | ) |
| Future development costs                                  |       | (1,075                                     | )          | (1,075 | ) | (6,560 | ) |
| Future income taxes                                       |       | (13,762                                    | )          | (8,128 | ) | (18,941 | ) |
| Future net cash flows                                     |       | 74,778                                     |       | 54,882 |   | 76,782 |   |
| 10% annual discount                                       |       | (14,570                                    | )          | (8,341 | ) | (13,293 | ) |
| Standardized measure of discounted future net cash  flows |       | $                                          | 60,208     |   | $ | 46,541 |   | $ | 63,489 |   |

 

29

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***Pricing Assumptions***

*** ***

**SEC regulations require that thegas and oil prices used in the MHA Petroleum Consultants and Sproule Associates Inc. reservereports included herewith are the period-end prices for natural gas at December 31,2007, 2006 and 2005, respectively. These prices are projected without inflationfor the life of the wells included in the reserve reports. The pricingassumptions are listed below:**

 

| ** **             | ** ** | **YEAR-END PRICE** | ** ** | ** **             | ** ** |
|------------------------|------------|-------------------------|------------|------------------------|------------|
| **2007 REPORT**   | ** ** | **2006 REPORT**    | ** ** | **2005 REPORT**   | ** ** |
| **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)**  | ** ** | **Gas ($/MMBtu)** | ** ** |
|                   |       |                    |       |                   |       |
| $6.81                  |       | $5.40                   |       | $7.80                  |       |

 

 

**DrillingActivities**

** **

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

 
| ** **                        | ** ** | **Productive** | ** ** | **Dry** | ** ** | **Total Wells** | ** ** |
|-----------------------------------|------------|----------------|------------|---------|------------|----------------------|------------|
| ** **                        | ** ** | **Gross**      | ** ** | **Net** | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Year ended December 31, 2007 |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Exploratory                       |       | 0              |       | 0       |       | 2                    |       | 1 |   | 2 |   | 1 |   |
| Development                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |
|                              |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Year ended December 31, 2006 |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Exploratory                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |
| Development                       |       | 2              |       | 2       |       | 0                    |       | 0 |   | 2 |   | 2 |   |
|                              |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Year ended December 31, 2005 |       |           |       |    |       |                 |       |   |   |   |   |   |   |
| Exploratory                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |
| Development                       |       | 0              |       | 0       |       | 0                    |       | 0 |   | 0 |   | 0 |   |

 

 

**Acreageand Productive Wells**

** **

The following table setsforth our ownership interest in undeveloped acreage, developed acreage andproductive wells in the areas indicated where we own a working interest as of December 31,2007. Gross represents the total number of acres or wells in which we own aworking interest. Net represents our proportionate working interest resultingfrom our ownership in gross acres or wells. Productive wells are wells in whichwe have a working interest and that are capable of producing natural gas oroil. Wells that are completed in more than one producing horizon are counted asone well.

 
| ** ** | ** ** | **Undeveloped Acreage** | ** ** | **Developed Acreage** | ** ** | **Producing Wells** | ** ** | **Non-Producing Wells** | ** ** |
|------------|------------|------------------------------|------------|----------------------------|------------|--------------------------|------------|------------------------------|------------|
| ** ** | ** ** | **Gross**                    | ** ** | **Net**                    | ** ** | **Gross**                | ** ** | **Net**                      | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|       |       |                         |       |                       |       |                     |       |                         |       |   |   |   |   |   |   |   |   |
| Indonesia  |       | 239,692                      |       | 28,763                     |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
| Canada     |       | 4,480                        |       | 1,493                      |       | —                   |       | —                       |       |   |   |   |   |   |   |   |   |
| Texas      |       | 2,664                        |       | 2,664                      |       | 2,027                    |       | 2,027                        |       | 2 |   | 2.00 |   | 4 |   | 3.02 |   |
| California |       | 1,280                        |       | 1,280                      |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
| Alaska     |       | 122,174                      |       | 122,174                    |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
|       |       |                         |       |                       |       |                     |       |                         |       |   |   |   |   |   |   |   |   |
| Total      |       | 370,290                      |       | 156,374                    |       | 2,027                    |       | 2,027                        |       | 2 |   | 2.00 |   | 4 |   | 3.02 |   |

----

 

30

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The following table setsforth as of December 31, 2007, the expiration periods of the gross and netundeveloped acreage:

 
| ** **                       | ** ** | **Undeveloped Acreage** | ** ** |
|----------------------------------|------------|-------------------------|------------|
| ** **                       | ** ** | **United States**       | ** ** | **Indonesia** | ** ** | **Canada** | ** ** |
| ** **                       | ** ** | **Gross**               | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Twelve months ended              |       |                    |       |   |   |   |   |   |   |   |   |   |   |
| December 31, 2008                |       | 122,729                 |       | 122,729 |   | 239,692 |   | 28,763 |   | — |   | — |   |
| December 31, 2009                |       | 1,585                   |       | 1,585 |   | — |   | — |   | — |   | — |   |
| December 31, 2010                |       | 1,351                   |       | 1,351 |   | — |   | — |   | — |   | — |   |
| December 31, 2011                |       | —                  |       | — |   | — |   | — |   | — |   | — |   |
| December 31, 2012 and thereafter |       | 453                     |       | 453 |   | — |   | — |   | 4,480 |   | 1,493 |   |
|                             |       | 126,118                 |       | 126,118 |   | 239,692 |   | 28,763 |   | 4,480 |   | 1,493 |   |

 

**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,** | ** ** |
|--------------------------|------------|--------------------------------------------|------------|
| ** **               | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| Production:              |       |                                       |       |   |   |   |   |
| Natural gas  (MMcf)      |       | 2,005                                      |       | 2,229 |   | 1,991 |   |
| Natural gas  (MMcfd)     |       | 5.49                                       |       | 6.81 |   | 5.46 |   |
|                     |       |                                       |       |   |   |   |   |
| Average Sales Prices (1) |       |                                       |       |   |   |   |   |
| Natural gas  ($per Mcf)  |       | $                                          | 3.44       |   | $ | 3.01 |   | $ | 4.01 |   |
|                     |       |                                       |       |   |   |   |   |
| Lease Operating Expense  |       |                                       |       |   |   |   |   |
| ($per Mcf)               |       | $                                          | 0.78       |   | $ | 0.72 |   | $ | 0.44 |   |

----

(1)             Representssales price realized net of treatment costs.

 

**Business Risks** and Other Special Considerations

** **

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

 

**Item 3. *LegalProceedings***

 

From time to time, we areparty to litigation or other legal and administrative proceedings that we considerto be a part of the ordinary course of our business. Currently, we are notinvolved in any legal proceedings nor are we party to any pending or threatenedclaims that could, individually or in the aggregate, reasonably be expected tohave a material adverse effect on our financial condition, cash flow or resultsof operations.

 

31

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**Item 4. *Submission ofMatters to a Vote of Security Holders***

 

Notapplicable.

 

**PART II**

 

**Item 5.**          ***Market for theRegistrant’s Common Equity,Related Shareholder Matters and Issuer Purchases of Equity Securities***

 

Our common stock tradeson the American Stock Exchange under the symbol “GPR”. Our common stock is alsolisted on the Toronto Stock Exchange under the symbol “GEP.s”. On March 28,2008, the last reported sale prices for our common stock on the American StockExchange and Toronto Stock Exchange were $2.65 and $2.60, respectively. Thefollowing table sets forth the high and low sale prices of our common shares asreported on the American Stock Exchange and the Toronto Stock Exchange and bidprices as quoted in the United States in the “pink sheets” over-the-countermarket for the periods presented. Prior to the first quarter of 2006, there wasno trading market for our common shares.

 
| ** **                                           | ** ** | **American Stock  Exchange (1)** | ** ** | **Toronto Stock  Exchange (2)** | ** ** | **U.S. Pink Sheets** | ** ** |
|------------------------------------------------------|------------|--------------------------------------------|------------|-------------------------------------------|------------|--------------------------------|------------|
| ** **                                           | ** ** | **High**                                   | ** ** | **Low**                                   | ** ** | **High**                       | ** ** | **Low** | ** ** | **High** | ** ** | **Low** | ** ** |
| **2008**                                             | ** ** | ** **                                 | ** ** | ** **                                | ** ** | ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| First Quarter  through March   , 2008 |       | $                                          | 3.58       |                                      | $          | 2.00                           |       | $ | 3.00 |   | $ | 2.25 |   | N/A |   | N/A |   |
| **2007**                                             |       |                                       |       |                                      |       |                           |       |   |   | N/A |   | N/A |   |
| Fourth Quarter                                       |       | $                                          | 4.20       |                                      | $          | 2.79                           |       | $ | 4.00 |   | $ | 2.50 |   | N/A |   | N/A |   |
| Third Quarter                                        |       | $                                          | 4.05       |                                      | $          | 3.55                           |       | $ | 3.35 |   | $ | 2.50 |   | N/A |   | N/A |   |
| Second Quarter                                       |       | $                                          | 4.75       |                                      | $          | 3.50                           |       | $ | 2.95 |   | $ | 2.30 |   | N/A |   | N/A |   |
| First Quarter                                        |       | $                                          | 6.25       |                                      | $          | 2.66                           |       | $ | 3.39 |   | $ | 2.61 |   | $ | 4.10 |   | $ | 2.66 |   |
| **2006**                                             | ** ** | ** **                                 | ** ** | ** **                                | ** ** | ** **                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Fourth Quarter                                       |       | N/A                                        |       | N/A                                       |       | $                              | 3.05       |   | $ | 2.35 |   | $ | 3.25 |   | $ | 2.25 |   |
| Third Quarter                                        |       | N/A                                        |       | N/A                                       |       | $                              | 3.40       |   | $ | 2.76 |   | $ | 3.50 |   | $ | 2.25 |   |
| Second Quarter                                       |       | N/A                                        |       | N/A                                       |       | $                              | 3.98       |   | $ | 3.15 |   | $ | 9.00 |   | $ | 3.68 |   |
| First Quarter                                        |       | N/A                                        |       | N/A                                       |       | $                              | 3.50       |   | $ | 3.50 |   | $ | 10.05 |   | $ | 3.50 |   |

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(1)             Our common stock commencedtrading on the American Stock Exchange on February 15, 2007.

 

(2)             Our common stock isquoted in U.S. dollars on the Toronto Stock Exchange.  Our common stock commenced trading on theToronto Stock Exchange on March 30, 2006.

 

As of March 28,2008, there were 369 holders of record of our common shares.

 

Over-the-countermarket quotations reflect inter-dealer prices, without retail mark-up,mark-down or commission, and may not necessarily represent actual transactions.

 

**Dividends**

 

On March 28,2007, all outstanding shares of Series AA 8% Convertible Preferred Stockconverted to common shares. Dividends on Series AA preferred stock are nolonger payable. The holders of Series AA preferred stock were entitled toreceive ratably such cash dividends, as were declared from time to time by theboard of directors out of funds legally available therefore and, when declared,dividends were paid at the rate of $0.28 per share per annum, paid on acalendar quarter basis. Prior to the conversion, we had declared and paiddividends on a quarterly basis with respect to all outstanding shares of Series AApreferred stock at the rate of $0.28 per share per year from the time the Series AAstock was issued.

 

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.

 

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**Use ofProceeds**

 

On ourregistration statement on Form S-1 (Reg. No. 333-135485) weregistered up to 16,499,991 shares of our common stock, no par value per share,including 5,943,105 shares of common stock issuable upon exercise of warrantsand options, 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 our registration statement on Form S-1 (Reg. No. 333-146557) weregistered up to 2,002,599 shares of outstanding common stock and the resale ofup to 780,857 shares of common stock issuable upon exercise of warrants, forresale by selling shareholders. The registration statement was declaredeffective by the Securities and Exchange Commission in October  2007. Theoffering commenced in October 2007 and has not terminated. We will notreceive any proceeds from the sale of our common stock by the sellingshareholders under the registration statements; however if all warrants andoptions to acquire our common stock being registered thereunder are exercised,we will realize cash proceeds of approximately $13,787,973, which we expect touse for general working capital purposes and the drilling of wells in ourTexas, Alaska, California and Indonesian prospects.

 

Ifless than the $13,787,973 proceeds are realized from the exercise of suchwarrants and options, the proceeds will be spent in the following order ofpriority:

 

1.   Alaska Cook Inlet Project, up to approximately $3.0 million will be expendedfor the drilling of pilot program wells.

 

2.   Madisonville Project, Madison County, Texas. Up to approximately $12 millionwill be expended in the Madisonville Field area towards the drilling andcompletion of one deep exploratory well location to an estimated depth of18,000 feet.

 

3.   General working capital.

 

We donot know if, or how many, of the warrants or options will be exercised. This isour best estimate of our use of proceeds generated from the possible exerciseof warrants or options based on the current state of our business operations,our current plans and current economic and industry conditions. Any changes inthe projected use of proceeds will be made at the sole discretion of our boardof directors.

 

**UnregisteredSales of Securities**

 

On November 1, 2007,we issued 50,000 shares of common stock to an officer and director, anaccredited investor, pursuant to an exercise of stock options at $2.00 pershare for proceeds of $100,000. On November 29, 2007 we issued 50,000shares of common stock to a former officer and director, pursuant to an exerciseof stock options at $2.00 per share for proceeds of $100,000. These shares wereissued pursuant to Rule 701 promulgated under the Securities Act, in thatthey were offered and sold pursuant to a written contract relating tocompensation, as provided by Rule 701.

 

On November 9, 2007,we issued 18,000 shares of common stock pursuant to an exercise of stockwarrants at $3.50 per share for proceeds of $63,000. These shares were issuedto one investor. The private placement was exempt from the registrationrequirements of the Securities Act pursuant to Section 4(2) of theSecurities Act and Rule 506 of Regulation D. The investor in the privateplacement was either an accredited investor, as defined in Rule 501(a), orone we reasonably believed to be. The purchase agreement signed by the investorcontained customary and appropriate representations and warranties regardingthe investor’s status as an accredited investor, and that the investor wasacquiring the securities for his or her own account and not with a view toresale or distribution. It also contained questions further attesting to his orher status as an accredited investor. In addition, we did not accomplish theoffer or sale of the securities sold in the private placement through anymanner of general solicitation or general advertising. Moreover, it wasdisclosed to the investor prior to sale that, except as otherwise may beprovided in any registration rights granted to him or her, the securitiespurchased would not be registered under the Securities Act and could thereforenot be resold unless first registered under the Securities Act or an exemptionfrom registration was available. We placed a legend on each certificaterepresenting the securities sold stating that the securities have not been registeredunder the Securities Act and further setting forth customary and appropriaterestrictions on the transferability of the securities. Finally, we madeavailable to the investor, prior to purchase, the opportunity to ask questionsand receive answers concerning the terms and conditions of the privateplacement.

 

During December 2007,we issued 121,662 shares of common stock to one individual who is both anofficer and a director, two individuals who are directors, and one individualwho is an employee, all pursuant to a net exercise of stock options.  All of the options were exercisable at $2.00per share. A net exercise is the security holder’s election to receive that 

 

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number of shares of our common stock that is equal tothe quotient of: i) the fair market value of such shares, less the exerciseprice then in effect, multiplied by the number of  shares that the security holder wouldotherwise have been entitled to purchase; over ii) the fair market value of thecommon stock.   In the case of those individuals who were employeesat the time of exercise, the number of common shares issued to theseindividuals is further reduced by the quotient of: the employee’s shares ofpayroll taxes attributable to the option exercise over the fair market value ofthe common stock.  The common sharesissued pursuant to the net exercise were as follows:

 
| **# Shares** | ** ** | **Exercise** | ** ** | **Date of**  | ** ** |
|--------------|------------|--------------|------------|--------------|------------|
| **Issued**   | ** ** | **Price**    | ** ** | **Exercise** | ** ** |
| 78,767       |       | 2.00         |       | 12/19/2007   |       |
| 9,870        |       | 2.00         |       | 12/12/2007   |       |
| 17,272       |       | 2.00         |       | 12/21/2007   |       |
| 15,753       |       | 2.00         |       | 12/26/2007   |       |
| 121,662      |       |         |       |         |       |

 

Theseshares were issued pursuant to Rule 701 promulgated under the SecuritiesAct, in that they were offered and sold pursuant to a written contract relatingto compensation, as provided by Rule 701.

 

InDecember 2007, we issued 128,301 shares of common stock to an individual who isboth an officer and director pursuant to a net exercise of stock options at$2.00 per share. Because the individual was an employee at the time ofexercise, the number of common shares issued to this individual was furtherreduced by the quotient of: the employee’s share of payroll taxes attributableto the option exercise over the fair market value of the common stock. Theprivate placement was exempt from the registration requirements of theSecurities Act pursuant to Section 4(2) of the Securities Act andRule 506 of Regulation D. The investor in the private placement was anaccredited investor, as defined in Rule 501(a). The option exercise agreementsigned by the investor contained customary and appropriate representations andwarranties regarding the investor’s status as an accredited investor, and thatthe investor was acquiring the securities for his or her own account and notwith a view to resale or distribution. It also contained questions furtherattesting to his or her status as an accredited investor. In addition, we didnot accomplish the offer or sale of the securities sold in the privateplacement through any manner of general solicitation or general advertising.Moreover, it was disclosed to the investor prior to sale that, except asotherwise may be provided in any registration rights granted to him or her, thesecurities purchased would not be registered under the Securities Act and couldtherefore not be resold unless first registered under the Securities Act or anexemption from registration was available. We placed a legend on eachcertificate representing the securities sold stating that the securities havenot been registered under the Securities Act and further setting forthcustomary and appropriate restrictions on the transferability of thesecurities. Finally, we made available to the investor, prior to purchase, theopportunity to ask questions and receive answers concerning the terms and conditionsof the private placement.

 

**PerformanceGraph**

 

The following graph shows a comparisonfrom February 15, 2007 (the date our common stock began trading on the AmericanStock Exchange) through December 31, 2007 of cumulative stockholders totalreturn for our common stock, companies we deem to be in our industry peer groupand the Russell Microcap Index (IWC). The comparable companies are Kodiak Oil and Gas Corporation (KOG), PetroResources Corporation (PRC), and **American Oil & Gas Incorporated(AEZ).**

 

**All ofthese cumulative returns are computed assuming the value of the investment inGeoPetro common stock and each stock as $100.00 on February 15, 2007, and thereinvestment of dividends at the frequency with which dividends were paidduring the applicable months.  The monthscompared are February through December of 2007.  Since our common stock began trading on theAmerican Stock Exchange, we have not declared any dividends to be paid to ourcommon stockholders and do not have any present plans to declare dividends.**

 

**COMPARISONOF CUMULATIVE RETURN AMONG GEOPETRO RESOURCES COMPANY,RUSSELL MICROCAP INDEX (“IWC”) AND SELECTED PEER GROUP ISSUERS**

****

 

**Item 6.*Selected Consolidated 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 consolidated statementsof operations data for the years ended December 31, 2005, 2006 and 2007and the balance sheet data as of December 31, 2006 and 2007 are derivedfrom our audited consolidated financial statements included elsewhere in thisreport. The consolidated statements of operations data for the years ended December 31,2003 and 2004 and the balance sheet data as of December 31, 2003, 2004 and2005 are derived from our audited consolidated financial statements notincluded in this report.   Historicalresults are not necessarily indicative of the results to be expected in thefuture, and the results for the years presented should not be consideredindicative of our future results of operations.

 

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| ** **                                                 | ** ** | **For The Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2007**                                                      | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Consolidated Statement of Operations:**                  | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Revenues**                                               |       | $                                                             | 6,890,777  |   | $ | 6,716,360 |   | $ | 7,975,990 |   | $ | 5,825,072 |   | $ | 2,452,648 |   |
| **Lease  operating expense**                               |       | 1,558,900                                                     |       | 1,602,932 |   | 878,176 |   | 780,237 |   | 582,889 |   |
| **General  and administrative**                            |       | 2,807,091                                                     |       | 2,347,447 |   | 1,551,747 |   | 1,963,649 |   | 1,259,269 |   |
| **Net  profits expense**                                   |       | 679,337                                                       |       | 632,708 |   | 856,837 |   | 579,590 |   | 225,869 |   |
| **Impairment  expense**                                    |       | 1,111,151                                                     |       | 38,849 |   | — |   | 2,038,422 |   | 473,496 |   |
| **Depreciation  and depletion expense**                    |       | 2,269,995                                                     |       | 2,406,612 |   | 1,832,693 |   | 2,077,004 |   | 798,555 |   |
| **Earnings  (loss) from operations**                       |       | (1,535,697                                                    | )          | (312,188 | ) | 2,856,537 |   | (1,613,830 | ) | (887,430 | ) |
| **Net  income (loss)**                                     |       | (1,616,804                                                    | )          | (482,406 | ) | 2,640,471 |   | (2,077,615 | ) | (1,684,692 | ) |
| **Net  income (loss) attributable to common shareholders** |       | $                                                             | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) | $ | (1,943,565 | ) |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Earnings (Loss) per Share:**                             | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Basic**                                                  |       | $                                                             | (0.05      | ) | $ | (0.04 | ) | $ | 0.10 |   | $ | (0.14 | ) | $ | (0.12 | ) |
| **Diluted**                                                |       | $                                                             | (0.05      | ) | $ | (0.04 | ) | $ | 0.09 |   | $ | (0.14 | ) | $ | (0.12 | ) |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Weighted  Average Number of Common Shares Outstanding:** | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Basic**                                                  |       | 29,830,447                                                    |       | 25,990,868 |   | 20,890,841 |   | 18,901,607 |   | 16,497,898 |   |
| **Diluted**                                                |       | 29,830,447                                                    |       | 25,990,868 |   | 24,001,888 |   | 18,901,607 |   | 16,497,898 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Production Data:**                                       | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural  gas (Mcf)**                                     |       | 2,005,359                                                     |       | 2,229,059 |   | 1,991,105 |   | 2,316,895 |   | 1,217,327 |   |
| **Natural  gas (Mcfd)**                                    |       | 5,494                                                         |       | 6,107 |   | 5,455 |   | 6,348 |   | 3,335 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Production Data reduced by net profits  interests:**     |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Natural  gas (Mcf)**                                     |       | 1,754,689                                                     |       | 1,950,427 |   | 1,742,217 |   | 2,027,283 |   | 1,065,161 |   |
| **Natural  gas (Mcfd)**                                    |       | 4,807                                                         |       | 5,344 |   | 4,773 |   | 5,554 |   | 2,918 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Average Sales Prices:**                                  | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural  gas (per Mcf)**                                 |       | $                                                             | 3.44       |   | $ | 3.01 |   | $ | 4.01 |   | $ | 2.51 |   | $ | 2.01 |   |
|                                                            |            |                                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 
| ** **                                | ** ** | **For the Years Ended December 31,** | ** **  |
|-------------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                                | ** ** | **2007**                                                      | ** **  | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Balance Sheet Information:**            | ** ** | ** **                                                    | ** **  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Current assets                            |       | $                                                             | 5,723,680   |   | $ | 2,366,081 |   | $ | 1,718,893 |   | $ | 1,579,388 |   | $ | 2,967,626 |   |
| Total assets                              |       | 44,116,606                                                    |        | 39,061,478 |   | 25,014,826 |   | 22,771,411 |   | 18,875,981 |   |
| Current liabilities                       |       | 2,361,827                                                     |        | 3,604,342 |   | 3,574,466 |   | 7,582,377 |   | 1,471,248 |   |
| Long-term liabilities                     |       | 53,726                                                        |        | 48,842 |   | 26,641 |   | 24,705 |   | 5,242,554 |   |
| Redeemable Series AA Preferred Stock |       | —                                                        |        | 5,924,068 |   | 5,924,068 |   | 5,924,068 |   | 5,924,068 |   |
| Deficit                                   |       | $                                                             | (12,010,789 | ) | $ | (10,393,985 | ) | $ | (9,382,179 | ) | $ | (11,493,253 | ) | $ | (8,886,275 | ) |

 

**Item 7. *Management’sDiscussion and Analysisof Financial Condition and Results of Operations***

 

*Thefollowing discussion and analysis should be read in conjunction withaccompanying financial statements and related notes included elsewhere in thisreport. It contains forward looking statements that reflect our future plans,estimates, beliefs and expected performance. The forward looking statements aredependent upon events, risks and uncertainties that may be outside our control.Our actual results could differ materially from those discussed in theseforward looking statements.*

 

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*Factorsthat could cause or contribute to such differences include, but are not limitedto, market prices for natural gas and oil, economic and competitive conditions,regulatory changes, estimates of proved reserves, potential failure to achieveproduction from development drilling projects, capital expenditures and otheruncertainties, as well as those factors discussed below and elsewhere in thisreport, particularly in “Risk Factors” and “Cautionary Notes Regarding ForwardLooking Statements”, all of which are difficult to predict and which expresslyqualify all subsequent oral and written forward-looking statements attributableto us or persons acting on our behalf. In light of these risks, uncertaintiesand assumptions, the forward looking events discussed may not occur. We do nothave any intention or obligation to update forward-looking statements includedin this report after the date of this report, except as required by law.*

 

**Overview**

 

We are an oil and gascompany in the business of exploring and developing oil and natural gasreserves on a worldwide basis. Since inception, we have conducted leaseholdacquisition, exploration and drilling activities on our North American,Australian and Indonesian prospects. These projects currently encompassapproximately 372,317 gross (158,401 net) acres, consisting of mineralleases, production sharing contracts and exploration permits that give us theright to explore for, develop and produce oil and natural gas. Most of theseproperties are in the exploration, appraisal or development drilling phase andhave not begun to produce revenue from the sale of oil and natural gas.Excluding minor interest and dividend income, our only significant cash inflowsuntil 2003 were the recovery of capital invested in projects through sale orother divestiture of interests in oil and gas prospects to industry partners.

 

Since 2003, substantiallyall of our revenue has been generated from natural gas sales derived from theMagness #1, the Fannin #1, and the Mitchell #1 wells in the Madisonville Fieldin East Texas under spot gas purchase contracts at market prices. Natural gassales from the Madisonville Field are expected to account for substantially allof our revenues for 2008. We expect the majority of our capital expenditures in2008 to be the costs of drilling and completing wells in the MadisonvilleField.

 
| ** **                                                 | ** ** | **For The Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2007**                                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| **Consolidated Statement of Operations:**                  | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Revenues**                                               |       | $                                                             | 6,890,777  |   | $ | 6,716,360 |   | $ | 7,975,990 |   |
| **Lease  operating expense**                               |       | 1,588,900                                                     |       | 1,602,932 |   | 878,176 |   |
| **General  and administrative**                            |       | 2,807,091                                                     |       | 2,347,447 |   | 1,551,747 |   |
| **Net  profits expense**                                   |       | 679,337                                                       |       | 632,708 |   | 856,837 |   |
| **Impairment  expense**                                    |       | 1,111,151                                                     |       | 38,849 |   | — |   |
| **Depreciation  and depletion expense**                    |       | 2,269,995                                                     |       | 2,406,612 |   | 1,832,693 |   |
| **Earnings  (loss) from operations**                       |       | (1,535,697                                                    | )          | (312,188 | ) | 2,856,537 |   |
| **Net  income (loss)**                                     |       | (1,616,804                                                    | )          | (482,406 | ) | 2,640,471 |   |
| **Net  income (loss) attributable to common shareholders** |       | $                                                             | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   |

 

**Revenue and Operating Trends in2008**

 

As discussed in the “Properties— Texas — Madisonville Project” section in this prospectus, in order to producethe 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. In 2003, the construction andinstallation of a natural gas treatment plant with a designed capacity of 18million cubic feet of gas per day (“MMcf/d”) and associated pipeline andgathering facilities were completed. The treatment plant and associatedpipeline and gathering facilities are owned by an unaffiliated third party.

 

In 2005 we secured acommitment from MGP to install and make operational additional treatingfacilities capable of treating 50 MMcf/d, which combined with the capacity ofthe current in-service treating facilities will represent a total designedtreating capacity of 68 MMcf/d for the Madisonville treatment plant. In early October 2007,MGP completed the additional treating facilities and the additional treatingcapacity at such facilities was being phased in.  In December 2007, the phase-in of operationsat the additional treating facilities were suspended in order to makemodifications to deal with the 

 

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presence of diamondoidsin the gas stream produced from the Rodessa Formation, which modifications areexpected to be completed by the second quarter of 2008.

 

Upon completion of thephase-in, we expect to produce our wells at a higher rate as the well rates havepreviously been restricted due to capacity limitations in the gas treatmentplant. In addition, we expect to fracture stimulate the Wilson Well in thesecond or third quarter of 2007, and provided such stimulation is successful,we will place the Wilson Well on production.

 

In addition, our contractwith MGP provides that for the first 18,000 Mcf/d of gas measured and deliveredto the inlet flange of the gas treatment plant, MGP will receive a treating feeof $1.50 per thousand cubic feet (“Mcf”) (this fee is presently $1.55 per Mcfadjusted for inflation). For any gas volumes in excess of 18,000 Mcf/d of gasdelivered to the inlet flange of the gas treatment plant, the treating feereceived by MGP is reduced from $1.50 to $1.10 per Mcf ($1.14 per Mcf adjustedfor inflation). We record our revenues net of these treating fees. Thus, if weare able to increase our inlet production volumes over 18 MMcf/d on a sustainedbasis, we expect to experience a disproportionately higher increase in revenuedue to lower average treating fees per Mcf.

 

While there can be noassurance, the higher production rates from our wells combined with the loweraverage treating fees per Mcf, may result in higher net production andincreased revenue during 2008 as compared to 2007 and  prior periods.

 

**IndustryOverview for the year ended December 31, 2007**

 

The twelve months ended December 31,2007 saw strengthening natural gas prices. The Houston Ship Channel price, theindex price prevailing in the locale of our Madisonville Project in MadisonCounty, Texas, as quoted in Gas Daily as of December 28, 2007, was $6.81 perMcf versus  $5.40 per Mcf as of December 29, 2006. Natural gas pricesimproved during the year due to higher demand induced by cold temperaturesexperienced in many parts of the United States, among other factors.

 

**CompanyOverview in 2007**

 

Our net loss after taxesfor the year ended December 31, 2007 was $1,616,804. From our inception,through mid-2003, we only received nominal revenues from our oil and naturalgas activities, while incurring substantial acquisition and exploration costsand overhead expenses which have resulted in an accumulated deficit through December 31,2007 of $12,010,789. Commencing in May 2003, we placed our MadisonvilleProject into production. Substantially all of our oil and natural gas sales forthe year ended December 31, 2007 were derived from our MadisonvilleProject, from three producing wells, the UMC Ruby Magness #1 well (the “MagnessWell”), the Angela Farris Fannin #1 well (the “Fannin Well”), and the Mitchell#1 well (the “Mitchell Well”).

 

**Comparisonof Results of Operations for the year ended December 31, 2007 and 2006**

 

During the twelve monthsended December 31, 2007, we had oil and natural gas revenues of$6,890,777. Our net production was 2,005,359 Mcf of natural gas at an averageprice of $3.44 per Mcf. During the twelve months ended December 31, 2006,we had oil and natural gas revenues of $6,716,360. Our net production for thetwelve months ended December 31, 2006 was 2,229,059 Mcf at an averageprice of $3.01 per Mcf. Revenues increased in the twelve months ended December 31,2007 as compared to the prior year period due to higher gas prices but 10%lower production volumes. Prices were approximately 14% higher for the twelvemonths ended December 31, 2007 versus the same period in 2006.

 

During the twelve monthsended December 31, 2007, we incurred lease operating expense of$1,558,900. Our average lifting cost for the 2007 period was $0.78 per Mcf.During the twelve months ended December 31, 2006, we incurred leaseoperating expense of $1,602,932. Our average lifting cost for the 2006 periodwas $0.72 per Mcf. The average lifting cost per Mcf in 2006 was lower due to higherproduction volume in 2006.

 

During the twelve monthsended December 31, 2007, we incurred net profits interest expense of$679,337 associated with the Magness, the Fannin, and the Mitchell wells ascompared to $632,708 during the twelve months ended December 31, 2006. The7% increase resulted from higher gas prices in the twelve months ended December 31, 2007 versus 2006. The netprofit interest is 12.5% of the net operating profit from our Magness, Fannin,and  Mitchell wells.

 

General andadministrative (“**G&A**”) expenses for the twelvemonths ended December 31, 2007 were $2,807,091 compared to $2,347,447 forthe twelve months ended December 31, 2006. This represents a $459,644increase over the prior 

 

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year period due primarilyto U.S. and Canada public company filing fees, costs associated with our SECregistration statement, and ongoing filing requirements.  The $459,644 increase over the prior yearperiod due to primarily to:

 

1.               $128,232 in filing fees related to ourSEC registration,

 

2.               $331,412 public company filing fees inU.S. and Canada, ongoing filing requirements and costs associated with SECcompliance.

 

For the year ended December 31,2007, impairment expense was incurred in amount of $1,111,151 as compared to$38,849 in the same period of 2006.  The2007 and 2006  impairment write-downswere due to dry holes drilled  associatedwith the Canadian oil and gas properties, which resulted in ceiling test writedowns.

 

Depreciation, depletionand amortization expense (“DD&A”) for the twelve months ended December 31,2007 was $2,269,995 as compared to $2,406,612 in the same period of 2006, whichamounts primarily represent amortization of the oil and gas properties for thetwelve months ended December 31, 2007 and 2006, respectively. The decreasewas due to lower net production in the twelve months period of 2007 and anincrease in the amount of capitalized cost in the U.S. oil and gas properties.

 

Loss from operationstotaled $1,535,697 for the twelve months ended December 31, 2007 ascompared to $312,188 for the twelve months ended December 31, 2006. Theincrease in the loss from operations was due primarily to higher G&A costand impairment expense associated with the Canadian oil and gas properties inthe twelve months ended December 31, 2007 versus 2006.

 

Other income for thetwelve months ended December 31, 2007 and 2006 consisted of interestincome in the amount of $174,560 and $198,050, respectively. The reason for thedecreased interest income was lower average cash and cash equivalent balancesduring the 2007 period as compared to 2006 period.

 

During the twelve monthsended December 31, 2007 and 2006, we incurred interest expense of $306,340and $306,682, respectively. The interest expense comparisons between the yearended 2007 and 2006 were relatively consistent.

 

Net loss before taxes forthe twelve months ended December 31, 2007 was $1,667,477 as compared to$420,820 for the twelve months ended December 31, 2006. The increase innet loss during the twelve months ended December 31, 2007 was primarilydue to higher G&A cost and Canadian impairment write-off in the twelvemonths ended December 31, 2007 versus 2006.

 

Income tax refund for thetwelve months ended December 31, 2007 was $50,673 compared to income taxexpense of $61,586 in the same period of 2006. Income tax benefit in 2007 wasdue to a refund of prior year alternative minimum tax paid offset by a currentyear state tax payable.

 

**IndustryOverview for the Year Ended December 31, 2006**

 

The year 2006 sawsoftening natural gas prices. The Houston Ship Channel price, the index priceprevailing in the locale of our Madisonville Project in Madison County, Texas,as quoted in Gas Daily as of December 29, 2006, was $5.40 versus $7.80 asof December 31, 2005. In the year of 2005, the natural gas prices werestrong as a result of hurricane related supply disruptions and generally tightsupplies of natural gas in the United States. Availability of capital,particularly equity capital for junior oil and natural gas companies, continuedto show improvement in 2006. As a result of the initial public offering inCanada in March 2006, we were able to drill two wells in our MadisonvilleProject during 2006.

 

**CompanyOverview in 2006**

 

Our net loss after taxesfor the year ended December 31, 2006 was $1,011,806. From our inception,through mid-2003, we only received nominal revenues from our oil and naturalgas activities, while incurring substantial acquisition and exploration costsand overhead expenses which have resulted in an accumulated deficit through December 31,2006 of $10,393,985. Commencing in May 2003, we placed our MadisonvilleProject into production. Substantially all of our oil and natural gas sales forthe year ended December 31, 2006 were derived from our MadisonvilleProject, from two producing wells, the UMC Ruby Magness #1 well (the “MagnessWell”) and the Angela Farris Fannin #1 well (the “Fannin Well”).

 

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**Comparisonof Results of Operations for the twelve months ended December 31, 2006 and2005**

 

During the twelve monthsended December 31, 2006, we had oil and natural gas revenues of$6,716,360. Our net production was 2,229,059 thousand cubic feet (Mcf) ofnatural gas at an average price of $3.01 per Mcf. During the twelve monthsended December 31, 2005, we had oil and natural gas revenues of$7,975,990. Our net production for the twelve months ended December 31,2005 was 1,991,105 Mcf at an average price of $4.01 per Mcf. Revenues decreasedin the twelve months ended December 31, 2006 as compared to the prior yearperiod due to lower gas prices in spite of 12% higher production volumes.Prices were approximately 25% lower for the twelve months ended December 31,2006 versus the same period in 2005.

 

During the twelve monthsended December 31, 2006, we incurred lease operating expenses of$1,602,932. Our average lifting cost for the 2006 period was $0.72 per Mcf.During the twelve months ended December 31, 2005, we incurred leaseoperating expenses of $878,176. Our average lifting cost for the 2005 periodwas $0.44 per Mcf. The higher average lifting cost in 2006 was due to higherlease operating costs and production taxes attributable to the Fannin #1 well.The primary reason for the increase in average lifting cost per Mcf wereincreases in production costs related to the Fannin #1 well which was placed inproduction in March 2006. The production for the Magness and the Fanninwells is at present limited to the current treatment plant’s capacity of up to18,000 Mcf/d. Therefore, the production from the Fannin #1 and the Magness #1wells is limited to a rate that is below the combined productive flowcapability of the wells. A majority of the lease operating costs are fixedcosts such as chemical treatments for the wells, insurance, ad valorem tax, andsalaries paid to the field personnel. During the twelve months ended December 31,2006, the total lease operating costs for the Magness #1 well were $752,924versus $878,176 in the same period of 2005. The net production of the Magness#1 well was 1,155,840 Mcf for the twelve months ended December 31, 2006compared to 1,991,105 Mcf in same period of 2005. Some of the productiondecrease is attributable to natural declines and some of the decrease isattributable to the fact that the Magness #1 well shared the treating capacityof the treatment plant with the Fannin #1 well in 2006 whereas in thecomparable 2005 period it did not. As a result, the average lifting cost forMagness #1 well was $0.65 per Mcf for the twelve months ended December 31,2006 versus $0.44 per Mcf in the same period of 2005. The Fannin #1 well’saverage lifting cost was higher than the Magness #1 well due mainly to theseverance tax of $230,600 which was incurred on the Fannin #1 well for thetwelve months ended December 31, 2006. The Magness #1 well is exempt fromthe severance tax. The average lifting cost for the Fannin #1 well was $0.79per Mcf for the twelve months ended December 31, 2006.

 

During the twelve monthsended December 31, 2006, we incurred net profits interest expense of$632,708 associated with the Magness and Fannin wells as compared to $856,837during the twelve months ended December 31, 2005. The 26% decreaseresulted from lower net revenues from the wells in the twelve months ended December 31,2006 versus 2005. The net profits interest is 12.5% of the net operatingprofits from our Magness and Fannin wells.

 

General andadministrative expenses for the twelve months ended December 31, 2006 were$2,347,447 compared to $1,551,747 for the twelve months ended December 31,2005. This represents a $795,700 increase over the prior year period due toprimarily to:

 

1.               $198,000 of stock based compensation,

 

2.               a $265,000 increase in directors andofficers liability insurance,

 

3.               $48,000 in filing fees related to ourpublic listing on the Toronto Stock Exchange; and

 

4.               $285,000 in legal, audit, printing andfiling fees associated with the S-1 registration statement which was preparedfor the resale of some of our common stock.

 

For the year ended December 31,2006, impairment expense was incurred in amount of $38,849 as compared to $0 inthe same period of 2005. The 2006 impairment write-downs were associated withthe Canadian cost pool. The remaining costs of drilling a dry hole in Canada of$38,849 were expensed in 2006.

 

Depreciation, depletionand amortization expense, also known as DD&A, for the twelve months ended December 31,2006 was $2,406,612 as compared to $1,832,693 in the same period of 2005, whichamounts represent amortization of the U.S. full cost pool for the twelvemonths ended December 31, 2006 and 2005, respectively. The increase wasdue to higher 

 

39

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net production in thetwelve months period of 2006 and an increase in the amount of capitalized costin the U.S. full cost pool.

 

Loss from operationstotaled $312,188 for the twelve months ended December 31, 2006 as comparedto income from operations of $2,856,537 for the twelve months ended December 31,2005. The decrease in the income from operations was due primarily to lower gasprices, higher lease operating expenses, and higher G&A expenses.

 

Other income for thetwelve months ended December 31, 2006 and 2005 consisted of interestincome in the amount of $198,050 and $18,969, respectively. The reason for theincreased interest income was higher average cash and cash equivalent balancesduring 2006 period as compared to 2005 period resulting from net proceedsreceived from common stock offerings completed by us in 2006.

 

During the twelve monthsended December 31, 2006 and 2005, we incurred interest expense of $306,682and $217,768, respectively. The higher interest expense in the current yearperiod was due to $194,691 in expense related to the amortization of debtissuance costs in connection with a debt financing in January 2006consisting of: (i) the fair market value assigned to common stock warrantsissued, and (ii) a loan origination fee paid.

 

Net loss before taxes forthe twelve months ended December 31, 2006 was $420,820 as compared to netincome before taxes of $2,657,738 for the twelve months ended December 31,2005. The loss incurred during 2006 was primarily due to lower gas income,higher lease operating expenses as well as higher general and administrativecosts.

 

Income tax expense forthe twelve months ended December 31, 2006 was $61,586 compared to $17,267in the same period of 2005. The increased income tax expense was due to 2005alternative minimum tax paid in 2006.

 

**Industry Overview for the Year Ended December 31, 2005**

 

The year 2005 sawcontinued strong natural gas prices as a result of hurricane related supplydisruptions and generally tight supplies of natural gas in theUnited States. The Houston Ship Channel price, the index price prevailingin the locale of our Madisonville Project in Madison County, Texas, as quotedin Gas Daily as of December 31, 2005, was $7.80 versus $5.82 as of December 31,2004. Availability of capital, particularly equity capital for junior oil andnatural gas companies, continued to show improvement in 2005, and in 2005, weraised $4,727,824 net of issuance costs through equity financing transactions.As a result, and through the sale of one of our Indonesian property interests,we were able to repay our indebtedness of $1.7 million to various creditors andimprove our capital position during 2005.

 

During 2005, we receiveda weighted average net price of $4.01 per mcf of gas sold. As further discussedunder “Properties—Texas—Madisonville Project”, we receive revenue for our gassales net of certain costs to treat and transport the gas. The weighted averagegross price during 2005, prior to the deduction of the treating andtransportation costs, was $6.81. This compares to $7.80 which was the priceprevailing on the last day of 2005.

 

**Company Overview in 2005**

 

Our net income for theyear ended December 31, 2005 was $2,640,471. From our inception to 2003,we only received nominal revenues from our oil and natural gas activities,while incurring substantial acquisition and exploration costs and overheadexpenses which resulted in our sustaining an accumulated deficit through December 31,2005 of $9,382,179. We placed our Madisonville Project into production in May 2003.Substantially all of our oil and natural gas sales for the year ended December 31,2005 were derived from our Madisonville Project, from one producing well, theMagness #1 well.

 

**Comparison of Results of Operations for the twelve monthsended December 31, 2005 and 2004**

 

During the year ended December 31,2005, we had oil and natural gas revenues of $7,975,990. Our net production was1,991,105 thousand cubic feet (Mcf) of natural gas at an average price of $4.01per Mcf. During the year ended December 31, 2004, we had oil and naturalgas revenues of $5,825,072. Our net production for the year ended December 31,2004 was 2,316,895 Mcf at an average price of $2.51 per Mcf. Revenuesincreased in the year ended December 31, 2005 as compared to the priorperiod due to higher gas prices. Average prices in 2005 were 60% higher than2004, more than offsetting the 14% drop in production from 2004 to 2005.Production was lower due to normal declines associated with the production ofreserves****from the Magness #1 well.

 

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During the year ended December 31,2005, we incurred lease operating expenses of $878,176. Our average liftingcost for this period was $0.44 per Mcf. During the year ended December 31,2004, we incurred lease operating expenses of $780,237. Our average liftingcost for this period was $0.34 per Mcf. The primary reasons for the increase inaverage lifting cost per Mcf were increases in costs and lower net production.The increase in lease operating costs was due primarily to higher insurancepremiums, approximately $40,000, and higher costs of chemical treatments,approximately $60,000 associated with the Magness #1 well.

 

During the year ended December 31,2005, we incurred net profits interest expense of $856,837 associated with theMagness Well compared to $579,590 during the year ended December 31, 2004.The increase resulted from higher revenues associated with the Magness Well in2005 versus 2004.

 

General andadministrative expenses for the year ended December 31, 2005 were$1,551,747 compared to $1,963,649 for the year ended December 31, 2004.This represents a $411,902 decrease over the prior year period due to stockbased compensation incurred in 2004. During 2004 we issued 500,000 sharesof our common stock for cash proceeds of $500,000 in connection with theexercise of stock options by an officer and director. Concurrent with theexercise of stock options, the officer sold 117,647 shares of common stockto us at the estimated fair market value price prevailing at that time of $4.25per share. We recorded compensation expense of $500,000 in connection with thepurchase of stock.

 

Depreciation, depletionand amortization expense for the year ended December 31, 2005 was$1,832,693 compared to $2,077,004 in the year ended December 31, 2004,which amounts represent amortization of the U.S. full cost pool for theyear ended December 31, 2005 and 2004, respectively. The decrease was dueto lower net production in 2005 as well as an upward revision in net provedreserve estimates during the year.

 

For the year ended December 31,2005, no impairment expense was incurred as compared to $2,038,422 for the yearended December 31, 2004. The 2004 impairment write-downs were associatedwith the Canadian and Australian cost pools. We expensed the costs of drillingdry holes in those areas during 2004 while no such costs associated withunsuccessful wells were incurred in 2005.

 

Earnings from operationstotaled $2,856,537 for the year ended December 31, 2005 compared to a lossof $1,613,830 for the year ended December 31, 2004. The increase in theearnings from operations was due primarily to higher revenues associated withthe Magness Well.

 

Other income for the yearended December 31, 2005 and 2004 consisted of interest income in theamount of $18,969 and $6,548, respectively. The reason for the increase washigher average cash and cash equivalents balances for the 2005 period ascompared to 2004.

 

During the year ended December 31,2005 and 2004, we incurred interest expense of $217,768 and $402,958,respectively. The lower interest expense in the current year period was due tolower average debt levels. In March 2004, we incurred a cash finders feeof $67,375 to a director associated with the negotiation of a reduction in debtthrough the conversion of $1,347,500 of long-term debt to equity.

 

Net income after taxesfor the year ended December 31, 2005 was $2,640,471 compared to net lossof $2,077,615 for the year ended December 31, 2004. The increase in netincome was primarily due to higher revenues associated with theMagness Well and the impairments expense recorded in the previous period.

 

**Recent Developments**

 

In December 2007,officers, directors, and an employee exercised cashless options to purchase249,963 shares of our common stock.  Acashless exercise is the security holder’s election to receive that number ofshares of our common stock that is equal to the quotient of (i) the fairmarket value of such shares, less the exercise price then in effect, multipliedby the number of shares that the security holder would otherwise have beenentitled to purchase (or such lesser number of shares as the security holdermay designate in the case of a partial exercise; over (ii) the Fair MarketValue. The requisite tax withholdings for those persons employed by us at thetime of exercise were taken in shares of common stock and the Company paid tothe taxing authorities the amounts required to be withheld in cash equal to thevalue of the withheld shares.

 

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On August 13, 2007,we sold, pursuant to a private placement, 2,002,599 units of our securities ata price of $3.85 per unit for gross proceeds of $7,710,006. The Placement Agentalso received a warrant to purchase 60,078 shares expiring August 13, 2010for additional gross proceeds of $231,300.30. Each unit consists of one share of common stock and a warrant topurchase three-tenths of a common share. Each one whole warrant shall entitlethe holder to acquire one share of common stock at a price of $4.50 per sharefor a period of five years from the closing date. The units were purchased by asmall number of accredited investors. We agreed to file a resale registrationstatement covering the common shares sold in the placement. The gross proceedsof the sale of common shares used to fund the Company’s exploration anddevelopment program and for general working capital purposes.

 

In October 2007, aresale registration statement covering the common shares sold in the placementwas declared effective by the SEC. Under the terms of a registration rightsagreement in connection with the private placement, we must pay the holders ofthe registrable securities issued in the private placement liquidated damagesif the registration statement does not remain in effect until all such sharescease to be restricted securities (subject to certain exceptions).  We must pay as liquidated damages a number ofshares of common stock equal to 1.0%, up to a maximum of 10%, of the number ofshares of our common stock that were issued to the holder for each 30 dayperiod (pro-rated on a daily pro-rata basis for periods shorter than 30 days)that the above condition is not met.

 

In February 2007, weborrowed $900,000 pursuant to three promissory notes bearing interest at 8% perannum. The notes matured on October 31, 2007. In connection with thesenotes, we paid loan origination fees totaling $27,000 and issued warrants tothe noteholders to purchase 45,000 shares of our common stock at $3.50 pershare through February 2009. On October 31, 2007, the notes plusaccrued interest were paid in full.

 

In February 2007, wereceived an extension of the maturity date of our promissory note for$1,000,000 payable to Pine Hill Capital, LLC to October 31, 2007. Inconnection with the extension, we paid a loan extension fee of $30,000 andissued a warrant to purchase 50,000 shares of our common stock at $3.50 pershare which expires in February 2009. If we did not repay the note by October 31,2007, we would have been required to dedicate 5% of our net cash flow from theMadisonville Project located in Madison County, Texas, toward the unpaidprincipal and all accrued and unpaid interest on the note, until all suchamounts were paid in full. Net cash flow for this purpose meant gross revenues,less royalties, production taxes and net profits interest expense.  On October 31, 2007, the principalbalance of the note plus accrued interest were paid in full.

 

In February 2007,Stuart J. Doshi, President and CEO, loaned $100,000 to us pursuant to apromissory note bearing interest at 8% per annum, payable upon demand. Werepaid the note plus accrued interest on March 28, 2007.

 

On June 7, 2006, weloaned $1,000,000 to G. Carter Sednaoui, a 5% shareholder at the time of theloan, evidenced by a full-recourse short-term promissory note with a maturitydate of March 31, 2007. On March 30, 2007, we extended the maturitydate of the note to June 30, 2007. On June 29, 2007, we received fullpayment of the note plus accrued interest.

 

On March 28, 2007,all 1,890,710 of our outstanding shares of our Series AA Stockautomatically converted into 1,890,710 shares of our common stock. Under ourAmended and Restated Articles of Incorporation, the Series AA stockautomatically converts into common shares on a one-for-one share basiseffective the first trading day after the reported high selling price for ourcommon shares is at least $5.25 per share for any consecutive ten trading days,which condition was met on March 27, 2007. As a result of the conversionof our Series AA stock to common stock on March 28, 2007, dividendson the Series AA Stock ceased accruing on December 31, 2006. In 2006,dividends paid on the Series AA Stock totaled $529,400.

 

On April 25, 2007, May 9,2007, June 13, 2007, and November 1, 2007, an officer and directorexercised warrants and options to purchase 80,000, 70,000, 33,333, and 50,000shares of common stock at an exercise price of $2.00, $2.00,$4.00 and $2.00 pershare, respectively. The warrants were granted on June 18, 2000 and hadexpiration dates of between June 18 and June 30, 2007 and the optionswere granted on December 29, 2000 and had an  expiration date of December 29, 2007.

 

During  2007, we issued 150,607 shares of commonstock to persons other than directors, officers and employees, at exerciseprices ranging from $1.50 to  $3.50 pershare in connection with exercises of outstanding warrants and options.

 

On June 20, 2007, weagreed to sell and transfer all of our remaining property interests inAustralia to an unrelated party for cash consideration and a Petroleum SalesRoyalty Payment equal to 25% of the future annual earnings before interest,taxes, depreciation and amortization from the property interests.

 

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Specifically, theagreement provides that we will be paid consideration for the sale and transferof our property interests as follows:

 

1.               initial cash consideration of $175,000subject to certain closing conditions;

 

2.               a  second cash payment of $175,000upon a successful 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.

 

Thefirst cash payment of $175,000 was received on November 19, 2007.

 

During 2007, weparticipated, for a 50% non-operated working interest, in the drilling of threewells in Alberta, two of which were determined to be non-commercial and one ofwhich is currently under evaluation.

 

On October 17, 2007,we acquired a 33 1/3% non-operated working interest in the Swan Hills Prospect,Central Alberta, Canada. We paid $273,581 to purchase 4,480 gross (1,493 net)acres in this prospect.

 

.

 

**Liquidity and Capital Resources**

 

We had a working capital surplus of $3,361,853 versus aworking capital deficit of $1,238,261 at December 31, 2007 and December 31,2006, respectively. Our working capital increased during year ended December 31,2007 due primarily to a private placement which is discussed below.

 

We have historically financed our business activitiesthrough December 31, 2007 principally through issuances of common shares,promissory notes and common share purchase warrants in private placements andan initial public offering. These financings are summarized as follows:

 
| ** **                                                      | ** ** | **Years Ended**            | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                      | ** ** | **December 31, 2007** | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
| Proceeds from sale of common shares and warrant  exercises, net |       | $                               | 8,036,266  |   | $ | 16,717,604 |   | $ | 4,727,824 |   |
| Payment on preferred dividends                                  |       | —                          |       | (529,400 | ) | (529,397 | ) |
| Repayments of promissory notes                                  |       | (1,900,000                      | )          | (900,000 | ) | (4,781,807 | ) |
| Proceeds from promissory notes                                  |       | 1,000,000                       |       | 1,900,000 |   | — |   |
| Payment of loan fee                                             |       | (57,000                         | )          | (30,000 | ) | — |   |
| Repayment of related party note                                 |       | (100,000                        | )          | — |   | — |   |
| Deferred offering costs                                         |       | —                          |       | (1,213,789 | ) | (730,906 | ) |
| Purchase of treasury stocks                                     |       | —                          |       | — |   | (592,435 | ) |
| Net option exercise                                             |       | (386,600                        | )          | — |   | — |   |
|                                                            |       |                            |       |   |   |   |   |
| Net cash provided by financing activities                       |       | $                               | 6,592,666  |   | $ | 15,944,415 |   | $ | (1,906,721 | ) |

 

The net proceeds of our equity financings have been primarily investedin oil and natural gas properties totaling $5,214,421, $16,721,944, and$5,602,741 for the years ended December 31, 2007, 2006 and 2005,respectively.

 

On October 31, 2007,we repaid $1.9 million plus accrued but unpaid interest of $12,910 on theshort-term notes we borrowed during 2007 and 2006.

** **

**43**

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In October 2005, wesold our 40% interest in C-G Yapen for cash proceeds of $2.4 million. Our costbasis in C-G Yapen was $698,000. The sale of the interest was recorded as areduction of the capitalized cost pool for the Indonesian properties. Weutilized the cash proceeds to repay indebtedness during the fourth quarter of2005. On October 27, 2005, we repaid the remaining principal balance of$1,260,292 plus accrued but unpaid interest of $8,287 on the Rolling HillPromissory Note dated October 18, 2002, as well as the unsecuredpromissory note dated September 30, 2004 with a remaining principalbalance of $475,000 and accrued but unpaid interest of $9,058 toPatricia S. Cayce. See “Certain Relationships and Related PartyTransactions.”

 

On May 31, 2005, wepaid the remaining balance of $962,780 plus accrued but unpaid interest of$4,431 on a note to G. Carter Sednaoui dated July 19, 2004. See “CertainRelationships and Related Party Transactions.”

 

Our cash balance at December 31, 2007 was $4,294,565 compared to acash balance of $734,561 at December 31, 2006. The change in our cashbalance is summarized as follows:

 
| Cash balance at December 31, 2006           |   | $          | 734,561   |   |
|--------------------------------------------------|--------|------------|-----------|--------|
| Sources of cash:                                 |   |       |      |
| Cash provided by  operating activities           |   | 1,012,640  |      |
| Cash provided by  financing activities           |   | 6,592,666  |      |
| Cash provided by  related party note             |   | 1,000,000  |      |
| Cash provided by  selling interests in Australia |   | 175,000    |      |
|                                             |   |       |      |
| Total sources of  cash including cash on hand    |   | 9,514,867  |      |
|                                             |   |       |      |
| Uses of cash:                                    |   |       |      |
| Cash used in  investing activities:              |   |       |      |
| Oil and natural  gas property expenditures       |   | (5,214,421 | )         |
| Furniture,  fixtures and equipment               |   | (5,881     | )         |
| Total uses of  cash                              |   | (5,220,302 | )         |
|                                             |   |       |      |
| Cash balance at December 31, 2007           |   | $          | 4,294,565 |   |

 

During January and February 2006,we conducted a private placement of common shares to accredited investors. Weissued 927,314 common shares at $3.50 per share for gross cash proceeds of$3,245,600 (net of $3,123,408).

 

On January 31, 2006,we borrowed $1,000,000 from Pinehill Capital Inc. pursuant to an 8% promissorynote with a maturity date of January 31, 2007. We issued 150,000 shares at$3.50 per share of no par voting common stock warrants, immediately exercisablewith an expiration date on January 31, 2009 to Pinehill Capital Inc., aswell as a $30,000 loan origination fee. The fair market value of the warrantson the date of issuance, $182,390, as well as the $30,000 loan origination fee,was recorded as a debt discount and is being amortized over the life of thepromissory note. On February 1, 2007, the maturity date was extended to October 31,2007. We paid $80,000 accrued interest thru January 31, 2007. Inconnection with the extension, we paid a loan extension fee of $30,000 andgranted a three-year warrant exercisable to purchase 50,000 Common Shares at $3.50per share. The fair value of the warrants on the date of issuance, $57,242,together with the $30,000 loan extension fee, were recorded as a debt discountand are being amortized over the life of the promissory note. As of June 30,2007, the unamortized debt discount was $38,774. In the event this note is notrepaid by the maturity date, and unless an extension thereof is mutually agreedto, then we have agreed that we shall dedicate 5% of our net cash flow from theMadisonville Field toward the unpaid principal amount and all accrued andunpaid interest thereon, until such amounts are paid in full. Net cash flow forpurposes of this provision means gross revenues received by us less royalties,production taxes and net profits interest expense. The note plus the accruedinterest were paid in full on October 31, 2007.

 

On March 30, 2006,we completed an initial public offering pursuant to a final prospectus underthe securities laws of each of the provinces of Canada, which consisted of3,730,021 common shares from our treasury at an issue price of $3.50 per commonshare and 519,500 common shares issued on a “flow-through” basis under the *Income Tax Act* of Canada at an issue priceof $3.85 per common share for aggregate gross proceeds of $15,055,149. We usedthe net proceeds of the offering

 

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to fund developmentdrilling of proven and probable natural gas reserves associated with theMadisonville Project and to conduct exploration and appraisal activities on ourother projects in the United States, Canada and Indonesia.

 

It was required that weexpend $2,000,075 of the proceeds realized from the Canadian offering from theissuance of 519,500 “flow-through” shares toward Canadian exploration expensepursuant to Canadian tax law. Canadian exploration expense generally means, butis not limited to, the drilling of exploratory wells in Canada. Pursuant to theterms of our agreement with the subscribers of the “flow-through” shares, wemust renounce the tax deductions which would result from these expenditures andpass the deductions through to the holders of these shares. We incurred theseexpenditures by the end of our fiscal year ended December 31, 2007.

 

On August 13, 2007 we completed a private placementconsisting of 2,002,599 units of the Company at a subscription price of $3.85per Unit for total proceeds of $7,710,006. Each unit consisted of one share ofcommon stock of the Company and three-tenths common share purchase warrant ofthe Company. Each one whole warrant entitles the holder to acquire one share ofcommon stock at a price of $4.50 per share for a period of five years from theclosing date. The units were purchased by a group of private investors. Theproceeds of the sale of common shares will be used to fund the Company’sexploration and development program and for general working capital purposes.

 

Our current cash and cashequivalents and anticipated cash flow from operations may not be sufficient tomeet our working capital, capital expenditures and growth strategy requirementsfor the foreseeable future. See “Outlook for 2008” for a description of ourexpected capital expenditures for 2008. If we are unable to generate revenuesnecessary to finance our operations over the long-term, we may have to seekadditional capital through the sale of our equity or borrowing. As noted in “RecentDevelopments,” we periodically borrow funds pursuant to short term promissorynotes to finance our activities.

 

Asdiscussed in the “Outlook for 2008”, we are forecasting capital expenditures of$26.2 million during 2008. We will need to obtain adequate sources of cash tofund our anticipated capital expenditures through the end of 2008 and to followthrough with plans for continued investments in oil and gas properties. Oursuccess, in part, depends on our ability to generate additional financing andfarm-out certain of our projects.

 

Sinceour inception, we have participated as a working interest owner in theacquisition of undeveloped leases, seismic options, lease options and foreignconcessions and have participated in seismic surveys and the drilling of testwells on our undeveloped properties. Further leasehold acquisitions, drillingand seismic operations are planned for 2008 and future periods. In addition,exploratory and development drilling is scheduled during 2008 and futureperiods on our undeveloped properties. It is anticipated that these explorationactivities together with others that may be entered into will impose financialrequirements which will exceed our existing working capital. We may raiseadditional equity and/or debt capital, and we may farm-out certain of ourprojects to finance our continued participation in planned activities. However,if additional financing is not available, we may be compelled to reduce thescope of our business activities. If we are unable to fund plannedexpenditures, it may be necessary to:

 

1.                  forfeit our interest in wells that areproposed to be drilled;

 

2.                  farm-out our interest in proposed wells;

 

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

 

4.                  reduce general and administrativeexpenses.

 

**Contractual Obligations**

 

A summary of ourcontractual obligations as of December 31, 2007 is provided in thefollowing table:

 

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| ** **                                 | ** ** | **Payments due by period (4)** | ** ** |
|--------------------------------------------|------------|--------------------------------|------------|
| ** **                                 | ** ** | ** **                     | ** ** | **Less than** | ** ** | ** ** | ** ** | ** ** | ** ** | **More than** | ** ** |
| ** **                                 | ** ** | **Total**                      | ** ** | **1 year** | ** ** | **1-3 years** | ** ** | **3-5 years** | ** ** | **5 years** | ** ** |
| Operating lease obligations (1)            |       | 91,390                         |       | 78,334 |   | 13,056 |   | — |   | — |   |
| Madisonville Field drilling obligation (2) |       | 12,000,000                     |       | 12,000,000 |   | — |   | — |   | — |   |
| Cook Inlet Alaska work program (3)         |       | 3,568,063                      |       | 3,568,063 |   | — |   | — |   | — |   |
|                                       |       |                           |       |   |   |   |   |   |   |   |   |
| Total                                      |       | $                              | 15,659,453 |   | $ | 15,646,397 |   | $ | 13,056 |   | $ | — |   | $ | — |   |
|                                            |            |                                |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)             Effective March 1,2004, GeoPetro is committed under an office sublease which provides for a sixtymonth term. The sublease is cancelable by either party after thirty-six months.Minimum annual rentals due under this agreement are $78,334 in 2008 and $13,056in 2009.

 

(2)             Inorder to facilitate the expansion of the gas treatment plant in ourMadisonville Project, we are subject to a drilling commitment. The commitment,subject to events of force majeure, including, but not limited to rigavailability, requires us to drill a well sufficient to test the SmackoverFormation (estimated to be encountered at approximately 18,000 feet) on orbefore September 30, 2008. The commitment is not discretionary. We havegranted MGP a security interest in the Madisonville Field properties to securethe commitment. The security interest shall be subordinated to any third partylender in the event we secure future debt against the property. MGP granted usa security interest in the Madisonville Field Gas Treatment Plant to securetheir obligation to expand the capacity of the facilities.

 

(3)             On orbefore November 1, 2008, we have the option to conduct a $2.5 millionwork program on the leases over a three-year period, and, after completion ofthe work program and an evaluation of the results, to remit the finaladditional acreage consideration of $10 per acre for the leases estimated atapproximately $1,068,000. The Cook Inlet Option provides that if we fail to paythe lease consideration when due, fail to perform the work program or otherwisedefault under the Cook Inlet Option, we shall forfeit our interest and reassignthe leases to Pioneer with no further liability to us.

 

(4)             This table does notinclude the liability for dismantlement, abandonment and restoration costs ofoil and gas properties. Effective with the adoption of SFAS No. 143, “Accountingfor Asset Retirement Obligations,” we recorded a separate liability for thefair value of this asset retirement obligation. See Note 2 of the Notes toConsolidated Financial Statements for further discussion.

 

Other than the abovecommitments, the timing of most of our capital expenditures is discretionary.We have no other material long-term commitments associated with our capitalexpenditure plans or operating agreements. Consequently, we have a significantdegree of flexibility to adjust the level of such expenditures as circumstanceswarrant. The level of capital expenditures will vary in future periodsdepending on the success we experience on planned exploratory and appraisaldrilling activities, natural gas and oil price conditions and other relatedeconomic and political factors. Accordingly, we have not yet prepared anestimate of capital expenditures for periods beyond 2008.

 

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**Income Taxes**

 

As of December 31,2007, GeoPetro had net operating loss (NOL) carryforwards of approximately $24,771,000for federal income tax purposes which begin to expire in 2010. However, inaccordance with SFAS 123(R), a deferred tax asset has not been recognized forthe portion of the net operating loss carryforwards that is attributable toexcess tax deductions associated with the exercise of stock options in 2007which do not reduce income taxes payable. Accordingly, $2,128,000 of theGeoPetro’s federal NOL has not been benefited for financial statement purposesas it relates to excess tax deductions that have not reduced income taxespayable. The benefit of these excess tax deductions will not be recognized forfinancial statement purposes until the related deductions reduce income taxespayable.

 

The Company also has $11,112,000of California and Alaska net operating losses which begin to expire in 2008. Inaccordance with SFAS 123(R), a portion of the state NOLs has similarly not beenbenefited for financial statement purposes as it relates to excess taxdeductions which have not resulted in the reduction of income taxes payable. Thebenefit of such excess tax deductions will not be recognized for financialstatement purposes until the related deductions reduce state income taxespayable.

 

Inaddition, the Company has $341,000 of carryforward credits in Texas, a portionof which may be utilized each year against Texas Margin Tax liability through2027.

 

A significant change in our ownership may limit our ability to use theseNOL carryforwards. Statement of Financial Accounting Standards No. 109,*Accounting for Income Taxes*,requires that the tax benefit of such net operating loss be recorded as anasset. At December 31, 2007, we had net deferred tax assets ofapproximately $4.4 million related to the NOL and other temporary differences.We have recorded a full valuation allowance of $4.4 million at December 31,2007 due to uncertainties surrounding the realizability of the deferred taxasset.

 

Effective January 1,2007, we adopted the provisions of FASB interpretation No. 48, Accountingfor Uncertainty in Income Taxes, the detail of which is included in Note 5 tothe Financial Statements.

 

**Off Balance Sheet Arrangements**

 

As of March 31, 2008, we have no off balance sheet arrangements.

 

**Financial Instruments**

 

We currently have nonatural gas price financial instruments or hedges in place. Similarly, we haveno financial derivatives. Our natural gas marketing contracts use “spot” marketprices. Given the uncertainty of the timing and volumes of our natural gasproduction this year, we do not currently plan to enter into any long termfixed-price natural gas contracts, swap or hedge positions, other gas financialinstruments or financial derivatives in 2008.

 

**Outlook for 2008**

 

Depending on capitalavailability, we are forecasting capital spending of up to approximately$26.2 million during the year 2008, allocated as follows:

 

1.                       Madisonville Project, Madison County,Texas. Approximately $13.5 million may be expended in the MadisonvilleField area as follows: $1.5 million toward the fracture stimulation and hook upcosts of the Wilson Well and $12.0 million toward the drilling of a deep well.

 

2.                       Central Alberta Project. Up toapproximately $2.7 million may be expended to drill an exploratory well inthe Swan Hills Prospect.

 

3.                       Cook Inlet, Alaska. Up to $5.0 millionmay be expended toward the drilling and completion of one exploratory well andan additional $2.0 million to be utilized for land acquisition and geologic andgeophysical costs.

 

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4.                       Indonesia. Up to $3.0 million may beexpended toward the drilling, completion and testing of wells as well as theacquisition of seismic data in the Bengara II PSC as well as acquisition costsassociated with new ventures.

 

We may, in ourdiscretion, decide to allocate resources towards other projects in addition toor in lieu of, those listed above should other opportunities arise and ascircumstances warrant. We currently do not have sufficient working capital tofund all of the capital expenditure listed above. See “Liquidity and CapitalResources.”

 

We expect commodityprices to be volatile, reflecting the current tight supply and demandfundamentals for North American natural gas and world crude oil. Politicalevents around the world, which are difficult to predict, will continue toinfluence both oil and gas prices. Higher prices for oil and gas often lead tohigher levels of drilling activity which in turn lead to higher costs to explore,develop and acquire oil and gas reserves due to greater competition forresources and supplies. These higher costs could affect the returns on ourcapital expenditures. Higher crude prices could also help keep natural gasprices high by keeping alternative fuels, such as heating oil and residualfuel, expensive.

 

**Impact of Inflation & Changing Prices**

 

As the following table illustrates, averagesales prices of natural gas have changed in the past three years. This has ledto changes in revenues and earnings from operations:

 
| ** **                     | ** ** | **For the Year Ended December 31,** | ** ** |
|--------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                     | ** ** | **2007 (1)**                                            | ** ** | **2006 (2)** | ** ** | **2005** | ** ** |
| Average Sales Prices per Mcf   |       | $                                                            | 3.44       |   | $ | 3.01 |   | $ | 4.01 |   |
| Net Production Volume Mcf      |       | 2,005,359                                                    |       | 2,229,059 |   | 1,991,105 |   |
| Revenues                       |       | $                                                            | 6,890,777  |   | $ | 6,716,360 |   | $ | 7,975,990 |   |
| Earnings (loss) from Operation |       | $                                                            | (1,535,697 | ) | $ | (312,188 | ) | $ | 2,856,537 |   |

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(1) Includes$1,111,151 impairment expense

 

(2) Includes $38,849impairment expense

 

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

 

GeoPetro anticipates anincrease in gas price in 2008 from 2007. This would have a materially positiveimpact on our cash flow and revenues.

 

Changing prices have hada significant impact on costs of drilling and completing wells, particularly inthe Madisonville Field area where we are currently the most active. Theestimated cost of drilling and completing a Rodessa formation well atapproximately 12,300 feet of depth has increased from $3.0 million in 2001 to$7.5 million in 2007 due to higher costs associated with tubular goods, wellequipment, and day rates for drilling contracts, among other factors. Thesehigher costs have impacted and will continue to impact our income fromoperations in the form of higher depletion expense.

 

**Critical Accounting Estimates**

 

Our consolidatedfinancial statements have been prepared by management in accordance withU.S. GAAP.

 

The preparation ofconsolidated financial statements in conformity with U.S. GAAP requiresmanagement to make estimates and assumptions that affect the amounts reportedin the consolidated financial statements and accompanying notes. Actual resultscould differ from those estimates.

 

Management believes themost critical accounting policies that may have an impact on our financialresults relate to the accounting for oil and gas properties. Amortization,abandonment costs and full cost ceiling limitation write-downs are all

 

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based on numerousestimates, many of which are beyond management’s control. Reserves valuation iscentral to much of the accounting for an oil and gas company as describedbelow.

 

Significant accountingpolicies are contained in Note 2 to the consolidated financialstatements. A summary of unaudited supplementary oil and gas reserveinformation is contained in Note 12 to the consolidated financialstatements.

 

The following discussesthe accounting estimates that are critical in determining the reportedfinancial results:

 

*Oiland 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 evaluated oiland gas properties is computed on the units of production method based on allproved reserves on a country by country basis. Unevaluated oil and gasproperties are assessed for impairment either individually or on an aggregatebasis. The net capitalized costs of evaluated 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.

 

*Reserves—*We**engageindependent petroleum engineering consultants to evaluate our reserves.Reserves, future production profiles, and net revenues are estimated byindependent professional reservoir engineering firms. While we engage qualifiedreservoir engineering firms, their estimates are inherently uncertain, involvenumerous assumptions that may not be realized, and predict asset values thatmay not be indicative of the true market value of the assets evaluated. As a resultof the inherent uncertainties and changing technical and economic assumptions,reserve estimates are subject to revisions that can materially impact ourresults.

 

*AssetRetirement Obligation—*We**provide for theestimated site restoration and abandonment costs of tangible long-lived assetsusing a fair value method, which approximates the cost a third party wouldincur in performing the tasks necessary to retire such assets. The reportedliability is a discounted amount. The amount of the liability is affected byfactors such as the number of wells, the timing of the expected expendituresand the discount factor. These estimates will change and the revisions couldimpact the amortization rates.

 

*StockBased 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 after five years and expire five to ten years after the grantdate. Under U.S. GAAP, prior to 2006, the Company elected not to expensecompensation cost for stock-based employee compensation at fair value but diddisclose the impact of the fair value accounting of employee stock options inNote 2 to the annual audited consolidated financial statements.GeoPetro adopted Statement of Financial Accounting Standards No. 123(R) (“Statement123R”) on January 1, 2006, which is the beginning of its first interimperiod following the effective date of Statement 123R. GeoPetro hasapplied the modified prospective method of adoption, and accordingly, thefinancial statements for GeoPetro’s prior interim periods and fiscal years willnot reflect any restated amounts. GeoPetro has recorded $121,421 and $201,335of stock-based employee compensation for the twelve months ended December 31,2007 and 2006, respectively, in connection with the portion of previouslygranted employee stock options that vest on or after January 1, 2006. Theimpact of the fair value accounting of employee stock options is estimated onthe date of grant using the Black-Scholes option pricing model with assumptionsfor: risk free interest rates, expected dividend yields, expected life of theoptions from the date of grant, and expected volatility.

 

**RecentlyIssued Accounting Pronouncements**

 

In September 2006,the FASB issued SFAS No. 157, “Fair Value Measurements,” which iseffective for the Company beginning January 1, 2008 and provides adefinition of fair value, establishes a framework for measuring fair value, andexpands disclosures about fair value measurements for future transactions. Wedo not expect the adoption of this pronouncement to have a material impact onour financial position or results of operations.

 

In February 2007,the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assetsand Financial Liabilities,” which permits an entity to measure certainfinancial assets and financial liabilities at fair value. The objective of SFASNo. 159 is to improve financial reporting by allowing entities to mitigatevolatility in reported earnings caused by the measurement of related assets andliabilities using different attributes, without having to apply complex hedgeaccounting

 

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provisions. Under SFAS No. 159,entities that elect the fair value option (by instrument) will reportunrealized gains and losses in earnings at each subsequent reporting date. Thefair value option election is irrevocable, unless a new election date occurs.SFAS No. 159 establishes presentation and disclosure requirements to helpfinancial statement users understand the effect of the entity’s election on itsearnings, but does not eliminate disclosure requirements of other accountingstandards. Assets and liabilities that are measured at fair value must bedisplayed on the face of the balance sheet. We do not expect the adoption ofthis pronouncement to have a material impact on our financial position orresults of operations.

 

**Risks and Uncertainties**

 

There are a number ofrisks that face participants in the U.S., Canadian and international oil andnatural gas industry, including a number of risks that face us in particular. Accordingly,there are risks involved in an ownership of our securities. See “Risk Factors”for a description of the principal risks faced by us.

 

**Item 7A. *Quantitativeand Qualitative DisclosuresAbout Market Risk***

 

We areexposed to market risks arising from fluctuating prices of crude oil, naturalgas and interest rates as discussed below.

 

*CommodityRisk.*  Ourmajor commodity price risk exposure is to the prices received for our naturalgas production. Realized commodity prices received for our production are thespot prices applicable to natural gas in the East Texas region. Prices receivedfor natural gas are volatile and unpredictable and are beyond our control. Forthe year ended December 31, 2007, a 10% change in the prices received fornatural gas production would have had an approximate $700,000 impact on ourrevenues.

 

*CurrencyTranslation Risk.  *Because our revenues and expenses are primarily inU.S. dollars, we have little exposure to currency translation risk, and,therefore, we have no plans in the foreseeable future to implement hedges orfinancial instruments to manage international currency changes.

 

*Hedging.* We didnot enter into any hedging transactions during the years ended December 312007, 2006 and 2005.

 

**Item 8. *FinancialStatements and Supplementary Data***

 

Thereports of our independent registered public accounting firms and ourconsolidated financial statements and supplemental information required to befiled under Item 8 of Form 10-K are presented beginning on Page F-1of this Form 10-K.

 

**Item 9. *Changes in and Disagreements With Accountants on Accounting andFinancial Disclosure***

 

None.

 

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

 

**Evaluationof Disclosure Controls and Procedures**

 

Basedon their evaluation as of the end of the fiscal year ended December 31,2007, our Chief Executive Officer and Chief Financial Officer have concludedthat our disclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) under the Exchange Act) are effective to ensure that informationrequired to be disclosed in reports that we file or submit under the ExchangeAct are recorded, processed, summarized and reported within the time periodsspecified in the SEC’s rules and forms and in providing reasonableassurance that information required to be disclosed by the Company in suchreports is accumulated and communicated to the Company’s management, includingits Chief Executive Officer and Chief Financial Officer, as appropriate toallow timely decisions regarding required disclosures.

 

Duringthe most recent fiscal quarter, there have been no changes in our internalcontrol over financial reporting that have materially affected, or arereasonably likely to materially affect, our internal control over financialreporting.

 

**Management’sReport on Internal Control Over Financial Reporting**

 

Asmanagement, we are responsible for establishing and maintaining adequateinternal control over our financial reporting. In order to evaluate theeffectiveness of internal control over financial reporting, as required by Section 404of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, includingtesting using the criteria in *InternalControl—Integrated Framework* issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). GeoPetro’s system of internalcontrol over financial reporting is designed to provide reasonable assuranceregarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with accounting principlesgenerally accepted in the United States of America. Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements.

 

Based on our assessment,we have concluded that we maintained effective internal control over financialreporting as of December 31, 2007, based on criteria in *Internal Control—Integrated Framework*issued by the COSO. This annual report does not include an attestation reportof the company’s registered public accounting firm regarding internal controlover financial reporting. Management’s report was not subject to attestation bythe Company’s registered public accounting firm pursuant to temporary rules ofthe Securities 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.

 

**Item 9B. *OtherInformation***

 

None.

 

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**PART III**

 

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

 

The information requiredby this item is incorporated by reference from our definitive proxy statementrelating to our 2008 Annual Meeting of Shareholders, to be filed pursuant to RegulationA, on or before April 29, 2008, or the 2008 proxy statement.

 

**Item 11. *Executive Compensation***

 

The information requiredby this item is incorporated by reference from our 2008 proxy statement.

 

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

 

The information requiredby this item is incorporated by reference from our 2008 proxy statement.

 

**Item 13. *CertainRelationships and RelatedTransactions and Director Independence***

 

The information requiredby this item is incorporated by reference from our 2008 proxy statement.

 

**Item 14. *PrincipalAccountant Fees and Services***

 

The information requiredby this item is incorporated by reference from 2008 proxy statement.

 

**PART IV**

 

**Item 15. *Exhibits andFinancial Statement Schedules***

 

***(a)  Thefollowing documents are filed as part of this report***

 

1.                              Report of Independent Registered PublicAccounting Firm

 

Consolidated BalanceSheets as of December 31, 2007 and 2006

 

Consolidated Statementsof Operations for the years ended December 31, 2007, 2006 and 2005

 

Consolidated Statementsof Shareholders’ Equity for the years ended December 31, 2007, 2006 and 2005

 

Consolidated Statementsof Cash Flows for the years ended December 31, 2007, 2006 and 2005

 

Notes to ConsolidatedFinancial Statements

 

2.                              All other schedules are omitted becausethey are not applicable, not required or the required information is includedin the consolidated financial statements or related notes.

 

3.                              A list of exhibits filed or furnished withthis report on Form 10-K (or-incorporated by reference to exhibitspreviously filed or furnished by GeoPetro) is provided in the Exhibit Indeximmediately following the financial statements in this report.

 

**GLOSSARYOF OIL AND NATURAL GAS TERMS**

 

In this report, unlessthe context otherwise requires, the following terms shall have the indicatedmeanings. A reference to an agreement means the agreement as it may be amended,supplemented or restated from time to time.

 

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

 

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

 

“**Bengara Block**” means thecontract area in the Indonesian province of East Kalimantan designated as theBengara (II) PSC Block.

 

“**BP Migas**” means BadanPelaksana Minyak Dan Gas Muni, a new executive board established by thegovernment of Indonesia in 2002 for oil and gas upstream operations and animplementing body created to assume the role of Pertamina’s regulatoryfunctions and responsibilities in managing oil and gas contractors.

 

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“**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.

 

“**C-G Yapen**” means Continental-GeoPetro(Yapen) Ltd., a British Virgin Islands corporation formerly owned 40% byGeoPetro.

 

“**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.

 

“**Cook Inlet Option**” means the option grantedto GeoPetro by Pioneer to acquire a 100% working interest (81% net revenueinterest) in approximately 122,000 acres in Cook Inlet, near Anchorage,Alaska.

 

“**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 theBengara II 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.

 

“**Evaluated 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.

 

“**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.

 

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“**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 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.

 

“**Pioneer**” means Pioneer Oil Company, Inc.

 

**“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.

 

**“Provedoil and gas reserves”** means estimated quantities of crude oil, natural gas, and natural gasliquids which geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs underexisting economic and operating conditions, i.e., prices and costs as of thedate the estimate is made. Prices include consideration of changes in existingprices provided only by contractual arrangements, but not on escalations basedupon future conditions.

 

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(i)               Reservoirs are considered proved if economicproducibility 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 of informationon fluid contacts, the lowest known structural occurrence of hydrocarbonscontrols the lower proved limit of the reservoir.

 

(ii)            Reserves which can be produced economically throughapplication of improved recovery techniques (such as fluid injection) areincluded in the “proved” classification when successful testing by a pilotproject, or the operation of an installed program in the reservoir, providessupport for the engineering analysis on which the project or program was based.

 

(iii)         Estimates of proved reserves do not include thefollowing:

 

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

 

(B)          crude oil, natural gas, and natural gas liquids, therecovery of which is subject to reasonable doubt because of uncertainty as togeology, reservoir characteristics, or economic factors;

 

(C)          crude oil, natural gas, and natural gas liquids, thatmay occur in undrilled prospects; and

 

(D)          crude oil, natural gas, and natural gas liquids, thatmay be recovered from oil shales, coal, gilsonite and other such sources.

 

**“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”.

 

“**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.

 

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

 

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

 

“**Unevaluated Properties**” means propertiesnot yet evaluated through exploration and drilling as to whether or not theyhave proved reserves.

 

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

 

“**Wilson Well**”means the Wilson No. 1 well 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.

 

**ABBREVIATIONSAND CONVERSIONS**

** **

In this report, thefollowing 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                                                                                                                                                                                                                                                                                                                                                                                                                                                   |

 

56

----

 

**SIGNATURES**

 

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the registrant has duly caused this report to be signed on its behalfby the undersigned, thereunto duly authorized, on March 31, 2008.

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

Chief Executive Officer |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the registrant and inthe capacities indicated on March 31, 2008.

 
| **Signature**             |   | **Title**                           |   | **Date**            |
|---------------------------|--------|-------------------------------------|--------|---------------------|
|                      |   |                                |   |                |
| /s/ Stuart J. Doshi       |   | Chairman of the Board,  President   |   | March 31, 2008 |
| Stuart J. Doshi           |   | and Chief Executive  Officer        |   |                |
|                      |   |                                |   |                |
| /s/ David V. Creel        |   | Vice President of  Exploration and  |   | March 31, 2008 |
| David V. Creel            |   | Director                            |   |                |
|                      |   |                                |   |                |
| /s/ J. Chris  Steinhauser |   | Vice President of  Finance and      |   | March 31, 2008 |
| J. Chris Steinhauser      |   | Chief Financial  Officer, Principal |   |                |
|                      |   | Accounting Officer and  Director    |   |                |
|                      |   |                                |   |                |
| /s/ Kevin M. Delehanty    |   | Director                            |   | March 31, 2008 |
| Kevin M. Delehanty        |   |                                |   |                |
|                      |   |                                |   |                |
| /s/ Thomas D.  Cunningham |   | Director                            |   | March 31, 2008 |
| Thomas D. Cunningham      |   |                                |   |                |
|                      |   |                                |   |                |
| /s/ David G. Anderson     |   | Director                            |   | March 31, 2008 |
| David G. Anderson         |   |                                |   |                |
|                      |   |                                |   |                |
| /s/ Nick DeMare           |   | Director                            |   | March 31, 2008 |
| Nick DeMare               |   |                                |   |                |

** **

**57**

----

**GEOPETRO RESOURCES COMPANY**

 

**INDEX TO FINANCIAL STATEMENTS**

 
| ** **                                                                                                       | ** ** | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|------------|------------|
| CONSOLIDATED  FINANCIAL STATEMENTS FOR THE FISCAL YEARS ENDED DECEMBER 31, 2007, 2006  AND 2005             |       |       |       |
|                                                                                                             |       |       |       |
| Report of Independent Registered  Public Accounting Firm                                                         |       |       |       |
|                                                                                                             |       |       |       |
| Consolidated Balance  Sheets as of December 31, 2007 and 2006                                               |       |       |       |
|                                                                                                             |       |       |       |
| Consolidated  Statements of Operations for the years ended December 31, 2007, 2006 and  2005                |       |       |       |
|                                                                                                             |       |       |       |
| Consolidated  Statements of Shareholders’ Equity for the years ended December 31, 2007,  2006 and 2005 |       |       |       |
|                                                                                                             |       |       |       |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2007, 2006 and  2005                |       |       |       |
|                                                                                                             |       |       |       |
| Notes to  Consolidated Financial Statements                                                                      |       |       |       |

 

F-1

----

 

**REPORT OF INDEPENDENT REGISTEREDPUBLIC ACCOUNTING FIRM**

 

March 26, 2008,

 

To the Shareholders andBoard of Directors

GeoPetro ResourcesCompany

San Francisco, California

 

Wehave audited the accompanying consolidated balance sheets of GeoPetro ResourcesCompany and subsidiaries as of December 31, 2007 and 2006, and the relatedconsolidated statements of operations, shareholders’ equity, and cash flows foreach of the three years in the period ended December 31, 2007.  Theseconsolidated financial statements are the responsibility of the Company’smanagement.  Our responsibility is to express an opinion on theseconsolidated financial statements based on our audits.

 

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation.  We believe thatour audits provide a reasonable basis for our opinion.

 

Inour opinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of GeoPetro ResourcesCompany and subsidiaries as of December 31, 2007 and 2006, and the resultsof their operations and their cash flows for each of the three years in theperiod ended December 31, 2007, in conformity with accounting principlesgenerally accepted in the United States of America.

 

***We were notengaged to examine management’s assertion about the effectiveness of GeoPetroResources Company’s internal control over financial reporting as of December 31,2007 included in the accompanying Form 10K and, accordingly, we do notexpress an opinion thereon.***

*** ***

As discussed in Note 5 to the accompanyingfinancial statements, effective January 1, 2007, the Company adopted FASBInterpretation No. 48, Accounting for Uncertainty in Income Taxes.

 

(signed) HEIN &ASSOCIATES

 

Irvine, California

 

F-2

----

**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED BALANCE SHEETS**

 

| ** **                                                           | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                                           | ** ** | ** **            | ** ** | ** ** | ** ** |
| **ASSETS**                                                           |       |                  |       |   |   |
| **Current assets:**                                                  |       |                  |       |   |   |
| Cash and cash equivalents                                            |       | $                     | 4,294,565  |   | $ | 734,561 |   |
| Trade accounts receivable—oil and gas sales                     |       | 965,188               |       | 394,337 |   |
| Accounts receivable—other                                       |       | 345,862               |       | 115,770 |   |
| Related party note receivable                                        |       | —                |       | 1,000,000 |   |
| Prepaid expenses                                                     |       | 118,065               |       | 121,413 |   |
| Total current assets                                                 |       | 5,723,680             |       | 2,366,081 |   |
|                                                                 |       |                  |       |   |   |
| **Oil and gas properties, at cost  (full cost method):**             |       |                  |       |   |   |
| Unevaluated properties                                               |       | 5,848,195             |       | 4,503,481 |   |
| Evaluated properties                                                 |       | 47,428,750            |       | 43,701,510 |   |
| Less—accumulated depletion  and impairment                      |       | (14,917,700           | )          | (11,557,257 | ) |
| Net oil and gas properties                                           |       | 38,359,245            |       | 36,647,734 |   |
| ** **                                                           | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Furniture, fixtures and  equipment, at cost, net of depreciation** |       | 26,727                |       | 41,547 |   |
| **Other assets—deposits and other  noncurrent assets**          |       | 6,954                 |       | 6,116 |   |
| **Total Assets**                                                     |       | $                     | 44,116,606 |   | $ | 39,061,478 |   |
| ** **                                                           | ** ** | ** **            | ** ** | ** ** | ** ** |
| **LIABILITIES AND SHAREHOLDERS’ EQUITY**                        |       |                  |       |   |   |
| ** **                                                           | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Current Liabilities:**                                             |       |                  |       |   |   |
| Trade payables                                                       |       | $                     | 666,293    |   | $ | 654,427 |   |
| Short term notes payable                                             |       | —                |       | 982,301 |   |
| Interest payable                                                     |       | —                |       | 73,205 |   |
| Dividends payable                                                    |       | —                |       | 133,438 |   |
| Production taxes payable                                             |       | 407,246               |       | 662,905 |   |
| Other taxes payable                                                  |       | 161,032               |       | 9,206 |   |
| Royalty owners payable                                               |       | 979,743               |       | 951,271 |   |
| Net profits interest payable                                         |       | 147,513               |       | 137,589 |   |
| Total current liabilities                                            |       | 2,361,827             |       | 3,604,342 |   |

 

 

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

 

F-3

----

 

**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED BALANCE SHEETS**

**(Continued)**

 

| ** **                                                                                                                                                                                                                                                                      | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                                                                                                                      | ** ** | **2007**              | ** ** | **2006** | ** ** |
| ** **                                                                                                                                                                                                                                                                      | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Asset Retirement Obligations**                                                                                                                                                                                                                                                |       | 53,726                |       | 48,842 |   |
| ** **                                                                                                                                                                                                                                                                      | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Commitments and Contingencies  (Notes 1, 4, and 10)**                                                                                                                                                                                                                         |       |                  |       |   |   |
| ** **                                                                                                                                                                                                                                                                      | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Shareholders’ Equity:**                                                                                                                                                                                                                                                  |       |                  |       |   |   |
| Series A  preferred stock, no par value; 1,000,000 shares authorized 0 shares  outstanding at after the conversion on March 30, 2006                                                                                                                                  |       | —                |       | — |   |
| Series AA  preferred stock, no par value; 5,000,000 shares authorized; 0 shares after  conversion on March 28, 2007 and 1,890,710 shares issued and outstanding  at December 31, 2006, respectively. Liquidation value was $6,750,923 at  December 31, 2006 |       | —                |       | 5,924,068 |   |
| Common  stock, no par value; 100,000,000 shares authorized; 31,950,970 and 27,423,758  shares issued and outstanding at December 31, 2007 and  December 31, 2006, respectively                                                                                   |       | 52,645,168            |       | 40,112,265 |   |
| Additional paid-in capital                                                                                                                                                                                                                                                      |       | 2,219,109             |       | 918,381 |   |
| Treasury  stock, at cost, 1,257,043 shares held at December 31, 2007 and  December 31, 2006, respectively                                                                                                                                                             |       | (1,152,435            | )          | (1,152,435 | ) |
| Accumulated deficit                                                                                                                                                                                                                                                             |       | (12,010,789           | )          | (10,393,985 | ) |
| Total shareholders’ equity                                                                                                                                                                                                                                                 |       | 41,701,053            |       | 35,408,294 |   |
|                                                                                                                                                                                                                                                                            |       |                  |       |   |   |
| **Total Liabilities and  Shareholders’ Equity**                                                                                                                                                                                                                            |       | $                     | 44,116,606 |   | $ | 39,061,478 |   |
|                                                                                                                                                                                                                                                                                 |            |                       |            |  |  |  |  |

 

 

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

 

F-4

----

 

**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OF OPERATIONS**

 
| ** **                                                 | ** ** | **For the Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2007**                                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                       |       |                                                          |       |   |   |   |   |
| **Revenues**                                               |       |                                                          |       |   |   |   |   |
| Oil and gas sales                                          |       | $                                                             | 6,890,777  |   | $ | 6,716,360 |   | $ | 7,975,990 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Costs and expenses:**                                    |       |                                                          |       |   |   |   |   |
| Lease operating expense                                    |       | 1,558,900                                                     |       | 1,602,932 |   | 878,176 |   |
| General and administrative                                 |       | 2,807,091                                                     |       | 2,347,447 |   | 1,551,747 |   |
| Net profits interest                                       |       | 679,337                                                       |       | 632,708 |   | 856,837 |   |
| Impairment expense                                         |       | 1,111,151                                                     |       | 38,849 |   | — |   |
| Depreciation and depletion expense                         |       | 2,269,995                                                     |       | 2,406,612 |   | 1,832,693 |   |
| Total costs and expenses                                   |       | 8,426,474                                                     |       | 7,028,548 |   | 5,119,453 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Income (loss) from operations**                          |       | (1,535,697                                                    | )          | (312,188 | ) | 2,856,537 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Other Income and (Expense):**                            |       |                                                          |       |   |   |   |   |
|                                                       |       |                                                          |       |   |   |   |   |
| Interest expense                                           |       | (306,340                                                      | )          | (306,682 | ) | (217,768 | ) |
| Interest income                                            |       | 174,560                                                       |       | 198,050 |   | 18,969 |   |
| Total other expense                                        |       | (131,780                                                      | )          | (108,632 | ) | (198,799 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) Before Taxes**                         |       | (1,667,477                                                    | )          | (420,820 | ) | 2,657,738 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| Income tax (expense) benefit                               |       | 50,673                                                        |       | (61,586 | ) | (17,267 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) After Taxes**                          |       | (1,616,804                                                    | )          | (482,406 | ) | 2,640,471 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| Preferred stock dividend                                   |       | —                                                        |       | (529,400 | ) | (529,397 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) Available to Common  Shareholders**    |       | $                                                             | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Earnings (Loss) per Share:**                             |       |                                                          |       |   |   |   |   |
| Basic                                                      |       | $                                                             | (0.05      | ) | $ | (0.04 | ) | $ | 0.10 |   |
| Diluted                                                    |       | $                                                             | (0.05      | ) | $ | (0.04 | ) | $ | 0.09 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Weighted Average Number of Common Shares  Outstanding:** | ** ** | ** **                                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic                                                      |       | 29,830,447                                                    |       | 25,990,868 |   | 20,890,841 |   |
| Diluted                                                    |       | 29,830,447                                                    |       | 25,990,868 |   | 24,001,888 |   |

 

 

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

 

F-5

----

**GEOPETRORESOURCES COMPANY**

**CONSOLIDATEDSTATEMENTS OF SHAREHOLDERS’ EQUITY**

**FOR THEYEARS ENDED DECEMBER 31, 2007, 2006 AND 2005**

 
| ** **                                           | ** ** | **Preferred Stock  Series A** | ** ** | **Preferred Stock  Series AA** | ** ** | **Common stock** | ** ** | **Additional  Paid-in** | ** ** | **Treasury** | ** ** | **Accumulated** | ** ** | **Total  Shareholders’** | ** ** |
|------------------------------------------------------|------------|-----------------------------------------|------------|------------------------------------------|------------|-----------------------|------------|-------------------------|------------|--------------|------------|-----------------|------------|-------------------------------|------------|
| ** **                                           | ** ** | **Shares**                              | ** ** | **Amount**                               | ** ** | **Shares**            | ** ** | **Amount**              | ** ** | **Shares**   | ** ** | **Amount**      | ** ** | **Capital**                   | ** ** | **Stock** | ** ** | **Deficit** | ** ** | **Equity** | ** ** |
| Balances, December 31, 2004                          |       | 1,000,000                               |       | 674,425                                  |       | 1,890,710             |       | 5,924,068               |       | 19,868,272   |       | 20,087,360      |       | 531,729                       |       | (560,000 | ) | (11,493,253 | ) | 15,164,329 |   |
| Issuance of common stock for cash                    |       | —                                  |       | —                                   |       | —                |       | —                  |       | 1,443,047    |       | 4,727,824       |       | —                        |       | — |   | — |   | 4,727,824 |   |
| Treasury shares purchased                            |       | —                                  |       | —                                   |       | —                |       | —                  |       | (139,396     | )          | —          |       | —                        |       | (592,435 | ) | — |   | (592,435 | ) |
| Fair value of warrants issued with notes payable     |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | 2,927                         |       | — |   | — |   | 2,927 |   |
| Net Income                                           |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | —                        |       | — |   | 2,640,471 |   | 2,640,471 |   |
| Dividends on Series AA Preferred                     |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | —                        |       | — |   | (529,397 | ) | (529,397 | ) |
| Balances, December 31, 2005                          |       | 1,000,000                               |       | 674,425                                  |       | 1,890,710             |       | 5,924,068               |       | 21,171,923   |       | 24,815,184      |       | 534,656                       |       | (1,152,435 | ) | (9,382,179 | ) | 21,413,719 |   |
| Issuance of common stock for cash                    |       | —                                  |       | —                                   |       | —                |       | —                  |       | 5,251,835    |       | 14,622,656      |       | —                        |       | — |   | — |   | 14,622,656 |   |
| Series A preferred stock conversion                  |       | (1,000,000                              | )          | (674,425                                 | )          | —                |       | —                  |       | 1,000,000    |       | 674,425         |       | —                        |       | — |   | — |   | — |   |
| Fair value of warrants issued with notes payable     |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | 182,390                       |       | — |   | — |   | 182,390 |   |
| Stock Option Compensation                            |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | 201,335                       |       | — |   | — |   | 201,335 |   |
| Net income                                           |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | —                        |       | — |   | (482,406 | ) | (482,406 | ) |
| Dividends on Series AA Preferred                     |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | —                        |       | — |   | (529,400 | ) | (529,400 | ) |
| Balances, December 31, 2006                          |       | —                                  |       | —                                   |       | 1,890,710             |       | 5,924,068               |       | 27,423,758   |       | 40,112,265      |       | 918,381                       |       | (1,152,435 | ) | (10,393,985 | ) | 35,408,294 |   |
| Issuance of common stock from private placement      |       | —                                  |       | —                                   |       | —                |       | —                  |       | 2,002,599    |       | 7,152,622       |       | —                        |       | — |   | — |   | 7,152,622 |   |
| Issuance of common stock from options/warrants       |       | —                                  |       | —                                   |       | —                |       | —                  |       | 383,940      |       | 883,644         |       | —                        |       | — |   | — |   | 883,644 |   |
| Net option exercise                                  |       | —                                  |       | —                                   |       | —                |       | —                  |       | 249,963      |       | (386,600        | )          |                          |       |   |   |   |   | (386,600 | ) |
| Series AA preferred stock conversion                 |       | —                                  |       | —                                   |       | (1,890,710            | )          | (5,924,068              | )          | 1,890,710    |       | 5,924,068       |       | —                        |       | — |   | — |   | — |   |
| Fair value of warrants issued with notes payable     |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | 138,476                       |       | — |   | — |   | 138,476 |   |
| Fair value of warrants issued with private placement |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | (1,040,831      | )          | 1,040,831                     |       | — |   | — |   | — |   |
| Stock option compensation                            |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | 121,421                       |       | — |   | — |   | 121,421 |   |
| Net loss                                             |       | —                                  |       | —                                   |       | —                |       | —                  |       | —       |       | —          |       | —                        |       | — |   | (1,616,804 | ) | (1,616,804 | ) |
| Balances, December 31, 2007                          |       | —                                  |       | $                                        | —     |                  | —     |                    | $          | —       |       | 31,950,970      |       | $                             | 52,645,168 |   | $ | 2,219,109 |   | $ | (1,152,435 | ) | $ | (12,010,789 | ) | $ | 41,701,053 |   |
|                                                      |            |                                         |            |                                          |            |                       |            |                         |            |              |            |                 |            |                               |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

***See accompanying notes to these consolidated financialstatements.***

 

F-6

----

 

**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

 

 
| ** **                                                                                          | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                                                          | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Cash Flows From Operating  Activities:**                                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net income (loss)                                                                                   |       | $                                         | (1,616,804 | ) | $ | (482,406 | ) | $ | 2,640,471 |   |
| Adjustments to reconcile net income (loss) to net cash provided by  (used in) operating activities: |       |                                      |       |   |   |   |   |
| Depreciation and depletion                                                                          |       | 2,269,995                                 |       | 2,406,612 |   | 1,832,693 |   |
| Stock compensation expense                                                                          |       | 121,421                                   |       | 201,335 |   | — |   |
| Non-cash interest expense                                                                           |       | 180,641                                   |       | 194,691 |   | 2,927 |   |
| Impairment expense                                                                                  |       | 1,111,151                                 |       | 38,849 |   |   |   |
| Accretion of asset retirement obligations                                                           |       | 3,430                                     |       | 2,664 |   | 1,936 |   |
| Changes in operating assets and liabilities:                                                        |       |                                      |       |   |   |   |   |
| (Increase) decrease in accounts receivable                                                          |       | (570,851                                  | )          | 297,226 |   | (239,195 | ) |
| (Increase) decrease in other receivables                                                            |       | (230,092                                  | )          | (107,378 | ) | 81,608 |   |
| (Increase) decrease in prepaid expenses                                                             |       | 3,348                                     |       | (17,302 | ) | (77,752 | ) |
| Deposits and other noncurrent assets                                                                |       | (835                                      | )          | 466 |   | (794 | ) |
| Increase (decrease) in trade payables                                                               |       | 11,860                                    |       | (1,273,742 | ) | 662,791 |   |
| Increase (decrease) in interest payable                                                             |       | (73,205                                   | )          | 73,205 |   | (88,388 | ) |
| Increase (decrease) in dividends payable                                                            |       | (133,438                                  | )          | — |   | 361 |   |
| Increase (decrease) in production taxes payable                                                     |       | (255,659                                  | )          | 352,720 |   | (27,794 | ) |
| Increase (decrease) in other payable                                                                |       | 151,826                                   |       | (15,561 | ) | (21,522 | ) |
| Increase in royalty owners payable                                                                  |       | 28,472                                    |       | 86,027 |   | 157,251 |   |
| Increase in net profit interest payable                                                             |       | 9,926                                     |       | (175,074 | ) | 91,197 |   |
| Increase in asset retirement obligations                                                            |       | 1,454                                     |       | 19,537 |   | — |   |
| Net cash provided by operating activities                                                           |       | 1,012,640                                 |       | 1,601,869 |   | 5,015,790 |   |
|                                                                                                |       |                                      |       |   |   |   |   |
| **Cash Flows from Investing  Activities:**                                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil and gas property expenditures                                                                   |       | (5,214,421                                | )          | (16,721,944 | ) | (5,602,741 | ) |
| Proceeds from sale of oil and gas interest                                                          |       | 175,000                                   |       | — |   | 2,400,000 |   |
| Acquisition of furniture, fixtures & equipment                                             |       | (5,881                                    | )          | (4,605 | ) | (2,162 | ) |
| (Increase) decrease in related party notes receivable                                               |       | 1,000,000                                 |       | (1,000,000 | ) | — |   |
| Net cash used in investing activities                                                               |       | (4,045,302                                | )          | (17,726,549 | ) | (3,204,903 | ) |
|                                                                                                     |            |                                           |            |  |  |  |  |  |  |  |

 

F-7

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**GEOPETRO RESOURCES COMPANY**

 

**CONSOLIDATED STATEMENTS OF CASH FLOWS**

**Continued**

 
| ** **                                                              | ** ** | **For the Years Ended December 31,** | ** ** |
|-------------------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                              | ** ** | **2007**                                  | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                                                    |       |                                      |       |   |   |   |   |
| **Cash Flows from Financing  Activities:**                              | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
|                                                                    |       |                                      |       |   |   |   |   |
| Proceeds from sale of common shares, option and warrant exercises,  net |       | 8,036,266                                 |       | 16,717,604 |   | 4,727,824 |   |
| Payments of preferred dividends                                         |       | —                                    |       | (529,400 | ) | (529,397 | ) |
| Proceeds from promissory notes, net                                     |       | 1,000,000                                 |       | 1,900,000 |   | — |   |
| Payments of loan fee                                                    |       | (57,000                                   | )          | (30,000 | ) | — |   |
| Repayments of promissory notes                                          |       | (1,900,000                                | )          | (900,000 | ) | (4,781,807 | ) |
| Repayments of related party notes                                       |       | (100,000                                  | )          |   |   |   |   |
| Deferred offering costs                                                 |       | —                                    |       | (1,213,789 | ) | (730,906 | ) |
| Purchase of treasury stock                                              |       | —                                    |       | — |   | (592,435 | ) |
| Net option exercise                                                     |       | (386,600                                  | )          | — |   | — |   |
| Net cash provided by (used in) financing activities                     |       | 6,592,666                                 |       | 15,944,415 |   | (1,906,721 | ) |
|                                                                    |       |                                      |       |   |   |   |   |
| **Net Increase in Cash and Cash  Equivalents:**                         |       | 3,560,004                                 |       | (180,265 | ) | (95,834 | ) |
| ** **                                                              |       |                                      |       |   |   |   |   |
| **Cash and Cash Equivalents:**                                          | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Beginning of period                                                     |       | 734,561                                   |       | 914,826 |   | 1,010,660 |   |
| End of period                                                           |       | $                                         | 4,294,565  |   | $ | 734,561 |   | $ | 914,826 |   |
| ** **                                                              | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Supplemental Disclosure of Cash  Flow Information:**                  | ** ** | ** **                                | ** ** | ** ** | ** ** | ** ** | ** ** |
| Cash paid for interest                                                  |       | $                                         | 125,699    |   | $ | 38,682 |   | $ | 291,731 |   |
|                                                                    |       |                                      |       |   |   |   |   |
| Cash (refund) paid for income taxes                                     |       | $                                         | (50,673    | ) | $ | 61,586 |   | $ | — |   |

 

***The accompanying notesare an integral part of these consolidated financial statements.***

 

F-8

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**GEOPETRO RESOURCES COMPANY**

 

**NOTES TO CONSOLIDATED FINANCIALSTATEMENTS**

 

**(Information subsequent to December 31,2007 is unaudited)**

 

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

 

*GeoPetro*—GeoPetro Resources Company (“GeoPetro”or the “Company”) was originally incorporated as GeoPetro Company under thelaws of the State of Wyoming in 1994 to participate in the oil and gasacquisition, 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.

 

*Operations*—Although GeoPetro is not a developmentstage enterprise, the company has a limited operating history upon which anevaluation of its business prospects can be based. The risks, expense, anddifficulties encountered by early stage companies must be considered whenevaluating GeoPetro’s business prospects. GeoPetro recorded net income of$2,111,074 in 2005 but incurred net losses of $1,616,804, and $1,011,806 in2007 and 2006 respectively, and had an accumulated deficit at December 31,2007 of $12,010,789. GeoPetro expects to make significant capital expendituresin the foreseeable future. Management believes that GeoPetro will be successfulin obtaining adequate sources of cash to fund its anticipated capitalexpenditures through the end of 2008 and to follow through with plans forcontinued investments in oil and gas properties. GeoPetro’s success, in part,depends on its ability to generate additional financing, farm-out certain ofits 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 proven reserves. Additionally,GeoPetro’s operations are subject to all of the environmental and operationalrisks normally associated with the oil and gas industry. GeoPetro maintainsinsurance that is customary in the industry.

 

Since its inception, GeoPetro has participated as aworking interest owner in the acquisition of undeveloped leases, seismicoptions, lease options and foreign concessions and has participated in seismicsurveys and the drilling of test wells on its undeveloped properties. Furtherleasehold acquisitions and seismic operations are planned for 2008 and future periods.In addition, exploratory and development drilling is scheduled during 2008 andfuture periods on GeoPetro’s undeveloped properties. It is anticipated thatthese exploration activities together with others that may be entered into mayimpose financial requirements which may exceed the existing working capital ofGeoPetro. Management may raise additional equity and/or debt capital, and hasfarmed-out certain of its projects to finance its continued participation inplanned activities. However, if additional financing is not available, GeoPetromay be compelled to reduce the scope of its business activities. If GeoPetro isunable to fund planned expenditures, it may be necessary to:

 

1.                 forfeit its interest in wells that areproposed to be drilled;

 

2.                 farm-out its interest in proposed wells;

 

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

 

4.                 reduce general and administrativeexpenses.

 

F-9

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**2.****                ****SUMMARY OF SIGNIFICANT ACCOUNTINGPOLICIES:**

 

*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. Actual results couldmaterially differ from those estimates.

 

*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, salesor other dispositions of oil and gas properties are accounted for asadjustments to capitalized costs, with no gain or loss recorded. Amortizationof evaluated oil and gas properties is computed on the units of productionmethod based on all proved reserves on a country by country basis. Unevaluatedoil and gas properties are assessed for impairment either individually or on anaggregate basis. The net capitalized costs of evaluated oil and gas properties(full cost ceiling limitation) are not to 

 

F-10

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exceedtheir related estimated future net revenues discounted at 10%, and the lower ofcost or estimated fair value of unproved properties, net of tax considerations.

 

 Asset Impairment—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 carryingvalue is greater than the undiscounted future cash flows.  In the event of impairment, the amount bywhich the carrying value exceeds the estimated fair value of the long-livedasset is charged to earnings. The present value of estimated future netrevenues is computed by applying current oil and gas prices to estimated futureproduction of proved oil and gas reserves as of period-end, less estimatedfuture expenditures to be incurred in developing and producing the provedreserves assuming the continuation of existing economic conditions. As oftwelve months ended December 31, 2007, the impairment test was met for theUnited States.

 

For the unprovedproperties, the Company evaluates the possibility of potential impairment on aquarterly basis. During the twelve months ended December 31, 2007,approximately $1,111,151 of unproved property costs related to Goodwin andWildwood projects were reclassified to proved property and a ceiling testimpairment was recorded in the Canadian full cost pool due to dry holes drilled.

 

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

 

*RevenueRecognition*—Revenueis recognized upon delivery of oil and gas production and is shown net ofapplicable royalty payments, processing and transportation fees. In addition,the Company recognizes revenue from the Madisonville Field net of applicablefees to gather, treat and transport the Company’s natural gas production. Theapplicable fees are paid to unrelated third parties. Revenue from theMadisonville Field is recognized when the price for gas delivered becomes fixedand determinable. The price for gas delivered to the purchaser, MadisonvilleGas Processing LP (“MGP”), becomes fixed and determinable after the gas hasbeen gathered, treated, and transported to a common carrier pipeline where itis then resold by MGP to the common carrier pipeline on a spot market basis.The proceeds from the sale of the gas are deposited directly into an escrowaccount under the joint signature control of the Company and MGP. The fees togather, treat and transport the gas are distributed to MGP in accordance withagreements between them and the Company. The remaining net proceeds aredistributed to the Company. See Note 10 for a more detailed discussion of thefees under the “MGP Agreement.”

 

*AssetRetirement Obligation*—In accordance with Statement of Financial Accounting Standards No. 143,*Accounting for Asset Retirement Obligations*(“SFAS 143”), the fair value of an asset retirement cost, andcorresponding liability, should be recorded as part of the cost of the relatedlong-lived asset and subsequently allocated to expense using a systematic andrational method. GeoPetro recorded an asset retirement obligation to reflectGeoPetro’s legal obligations related to future plugging and abandonment of itsoil and gas wells. GeoPetro estimated the expected cash flow associated withthe obligation and discounted the amount using a credit-adjusted, risk-freeinterest rate. At least annually, GeoPetro reassesses the obligation todetermine whether a change in the estimated obligation is necessary. GeoPetroevaluates whether there are indicators that suggest the estimated cash flowsunderlying the obligation have materially changed. Should those indicatorssuggest the estimated obligation has materially changed, GeoPetro willaccordingly update its assessment.

 

F-11

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| ** **                                         | ** ** | **December 31,** | ** ** |
|----------------------------------------------------|------------|-----------------------|------------|
| ** **                                         | ** ** | **2007**              | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                         | ** ** | ** **            | ** ** | ** ** | ** ** | ** ** | ** ** |
| Asset retirement  obligations, beginning of period |       | $                     | 48,842     |   | $ | 26,641 |   | $ | 24,705 |   |
| Liabilities incurred                               |       | 1,454                 |       | 19,537 |   | — |   |
| Accretion expense                                  |       | 3,430                 |       | 2,664 |   | 1,936 |   |
| Asset retirement  obligations, end of period       |       | $                     | 53,726     |   | $ | 48,842 |   | $ | 26,641 |   |

 

*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 orother conditions described below. The credit risk amounts for cash and accountsreceivable do not take into account the value of any collateral or security.

 

GeoPetro maintains several cash accounts with threefinancial institutions. Accounts at each institution are insured by the FederalDeposit Insurance Corporation up to $100,000. As of December 31, 2007,the uninsured bank balance was $4,494,138. GeoPetro has not experienced anylosses in such accounts and believes it is not exposed to any significantcredit risk.

 

During the years ended December 31, 2007, 2006and 2005, the Company had sales to customers exceeding 10% of total sales asfollows:

 
| ** **                    | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Luminant Energy Company,  LLC |       | 89       | %          | 79       | %          | 99.7     | %          |
| ETC Katy Pipeline, Ltd.       |       | 11       | %          | 21       | %          | —   |       |

 

At December 31, 2007, 2006 and 2005, the Companyhad accounts receivable balances from Luminant Energy Company, LLC of $965,188 or 74%, $394,337 or77%  $691,564, or 100%, and $449,947, or 99.5% of total accountsreceivable respectively.

 

*Allowancefor Doubtful Accounts*—Trade accounts receivable are recorded at net realizable value. If thefinancial condition of GeoPetro’s customers were to deteriorate, resulting inan impairment of their ability to make payments, additional allowances may berequired. Delinquent trade accounts receivable are charged against theallowance for doubtful accounts once uncollectibility has been determined. Theallowance is determined through an analysis of 

 

F-12

----

 

the past-due status of accounts receivable andassessments of risk that are based on historical trends and an evaluation ofthe impact of current and projected economic conditions. There was no activityin the allowance for doubtful accounts as of December 31, 2007, December 31,2006 and 2005.

 

*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.

 

*Stock-BasedCompensation*—Statementof Financial Accounting Standards No. 123, *Accounting for Stock-Based Compensation* (“SFAS 123”),encourages, but does not require, companies to record compensation cost forstock-based employee compensation at fair value. Prior to January 1, 2006,GeoPetro elected to account for stock-based compensation using the intrinsicvalue method prescribed in Accounting Principles Board Opinion No. 25 (“APB 25”),*Accounting for Stock Issued to Employees,*and related interpretations.

 

In accordance with SFAS 123, GeoPetro disclosesthe impact of the fair value accounting of employee stock options. Transactionsin equity instruments with non-employees for goods or services have beenaccounted for using the fair value method as prescribed by SFAS 123.

 

The following table illustrates the effect on GeoPetro’snet loss and loss per share as if GeoPetro had applied the fair valuerecognition provisions of SFAS 123 to its stock-based employeecompensation awards granted in 2005, and recognized expense over the applicableaward vesting period.

 
| ** **                                                           | ** ** | **December 31,  2005** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------------|------------|
| Net income (loss)  available to common shareholders—as reported |       | $                           | 2,111,074  |   |
| Compensation—FAS 123                                            |       | (98,870                     | )          |
| Pro forma income (loss)                                              |       | $                           | 2,012,204  |   |
| Income (loss) per share—as  reported                            |       | $                           | 0.09       |   |
| Pro forma income (loss)  per share                                   |       | $                           | 0.08       |   |

 

The assumptions made for purposes of estimating thefair value of the stock options are included in Note 8.

 

Effective January 1, 2006, the Company adoptedthe fair value recognition provisions of Statement of Financial AccountingStandard 123(R) “*Share-Based Payment”*(“SFAS 123(R)”) using the modified prospective transition method. In addition,the Securities and Exchange Commission issued Staff Accounting Bulletin No. 107“*Share-Based Payment*” (“SAB 107”)in March, 2005, which provides supplemental SFAS 123(R) applicationguidance based on the views of the SEC. Under the modified prospectivetransition method, compensation cost recognized in the twelve month period endedDecember 31, 2007 includes: (a) compensation cost for all share-basedpayments granted prior to, but not yet vested as of January 1, 2006, basedon the grant date fair value estimated in accordance with the originalprovisions of SFAS No. 123, and (b) compensation cost for allshare-based payments granted beginning January 1, 2006, based on the grantdate fair value estimated in accordance with the provisions of SFAS 123(R). Inaccordance with the modified prospective transition method, results for prior periodshave not been restated.

 

F-13

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The adoption of SFAS 123(R) resulted in stockcompensation expense for the twelve months period ended December 31, 2007and 2006 of $121,421 and $201,335, respectively,  to income from continuing operations andincome before income taxes, of which the entire amount was recorded to generaland administrative expenses. The Company did not recognize a tax benefit fromthe stock compensation expense because the Company considers it is more likelythan not that the related deferred tax assets, which have been reduced by afull valuation allowance, will not be realized.

 

The fair value of each option grant was estimated onthe date of grant using the Black-Scholes option pricing model with thefollowing weighted-average assumptions used for grants in 2003 and 2005 for allperiods presented: risk-free, weighted-average interest rates ranging from 2.52to 3.75% based on the U.S. Treasury yield curve in effect at the time of grant,expected dividend yield of 0%, expected life of 5 years from the dateof grant, and expected volatility of 10 and 25%. After the initial publicoffering on March 30, 2006, an expected volatility factor of 58% was usedfor the newly issued common stock options and the extension of common stockwarrants and options. A newly issued stock option is an option that was grantedon or after March 30, 2006 or a previously granted stock option that ismodified on or after March 30, 2006. The fair value of all newly issuedstock options grants is estimated using the Black-Scholes option pricing modelwith the following weighted average assumptions used for grants andmodifications of prior grants made on or after March 30, 2006 for the sixmonths ended June 30, 2007: risk-free, weighted average interest rate of4.9% based on the U.S. Treasury yield curve in effect at the time of grant,expected dividend yield of 0%, expected life of 5 years from the date of grant(the remaining term of the option in the case of option extensions), andexpected volatility of 58%. GeoPetro has selected 10 publicly traded “small cap”companies whose primary business is oil and gas exploration and production.Small cap, for purposes of this analysis, is defined as companies with a marketcapitalization under $1 billion. From this peer group of similar companies,GeoPetro randomly selected 10 companies and derived expected volatility factorsfor the most recent completed fiscal years for each entity as reported in theirrecently filed 10K or 10KSB Annual Reports with the Securities and ExchangeCommission. Where the expected volatilities were expressed as a range, a simpleaverage of the range is used as an expected volatility for that entity.

 

The options outstanding as of December 31, 2007have the following contractual lives:

 
| **Number of  Options  Outstanding** | ** ** | **Number of  Exercisable** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Remaining  Contractual Life** | ** ** |
|------------------------------------------|------------|---------------------------------|------------|----------------------|------------|-------------------------------------------------------------|------------|
| 750,000                                  |       | 750,000                         |       | 0.50                 |       | 0.33                                                        |       |
| 1,750,000                                |       | 1,400,000                       |       | 2.10                 |       | 5.43                                                        |       |
| 150,000                                  |       | 30,000                          |       | 3.85                 |       | 3.29                                                        |       |
| 10,000                                   |       | 4,000                           |       | 4.25                 |       | 2.01                                                        |       |
| 10,000                                   |       | 4,000                           |       | 6.25                 |       | 2.44                                                        |       |
| 2,670,000                                |       | 2,188,000                       |       |                 |       |                                                        |       |

 

The total intrinsic value ofoptions outstanding was approximately $4,725,000 and $3,285,088 at December 31,2007 and 2006, respectively. The intrinsic value for exercisable options was$4,717,950 and $2,935,088 at December 31, 2007 and 2006,respectively. The total intrinsic value for stock options exercised wasapproximately $1,448,388 and $0 for the years ended December 31, 2007and 2006, respectively.

 

As of December 31, 2007, there are 2,188,000options which are exercisable. The remaining 482,000 options will becomeexercisable ratably over the next four years. The stock compensation expenserelated to the unvested awards is $291,910.

 

*Earnings(Loss) Per Common Share**—*Basic earnings per share excludes dilution and iscalculated by dividing net income or loss by the weighted average number ofcommon shares outstanding for the period. Diluted earnings per share reflectsthe potential dilution that could occur if securities or other contracts toissue common stock were exercised or converted into common stock or resulted inthe issuance of common stock that then shared from the earnings of the entity. 1,684,817and 3,231,542 Potential common shares for the periods ended December 31,2007 and 

 

F-14

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December 31, 2006, respectively, were excludedfrom the earnings per share computation because the Company incurred a net lossand were anti-dilutive. There were 1,506,064 outstanding common stock warrantsat December 31, 2005 as well as 20,000 outstanding common stock options onDecember 31, 2005, that were not included in the diluted EPS calculationbecause the warrants’ and options’ exercise prices were greater than theaverage market price of the common shares. 1,890,710 shares of Series AAStock were not included in the diluted EPS calculation at December 31,2005 because they were anti-dilutive.

 
| ** **                                          | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                          | ** ** | **2007**                                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| Net Income (Loss) and  Adjustments:                 |       |                                                          |       |   |   |   |   |
| Net Income (Loss)  Available to Common Shareholders |       | $                                                             | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   |
| Adjustments                                         |       | Anti-dilutive                                                 |       | Anti-dilutive |   | Anti-dilutive |   |
| Net Earnings (Loss) for  Diluted                    |       |                                                          |       |   |   |   |   |
| Calculation                                         |       | $                                                             | (1,616,804 | ) | $ | (1,011,806 | ) | $ | 2,111,074 |   |
| Shares:                                             |       |                                                          |       |   |   |   |   |
| Weighted Average Shares  Outstanding                |       | 29,830,447                                                    |       | 25,990,868 |   | 20,890,841 |   |
| Outstanding Options                                 |       | Anti-dilutive                                                 |       | Anti-dilutive |   | 1,927,660 |   |
| Series A Preferred  Stock—Conversion      |       | —                                                        |       | — |   | 1,000,000 |   |
| Outstanding Warrants                                |       | Anti-dilutive                                                 |       | Anti-dilutive |   | 183,387 |   |
| Average Number of Shares  for Diluted Calculation   |       | 29,830,447                                                    |       | 25,990,868 |   | 24,001,888 |   |
| Diluted EPS                                         |       | $                                                             | (0.05      | ) | $ | (0.04 | ) | $ | 0.09 |   |

 

*SegmentReporting*—GeoPetrohas oil and gas exploration, development and production operations in the United States,Canada, Australia and Indonesia. All revenues and related costs are associatedwith operations in the United States. A summary of assets and capitalexpenditures by geographical segment is included in Note 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.

 

*RecentlyIssued Accounting Pronouncements**—*In September 2006, the FASB issued SFAS No. 157,“Fair Value Measurements,” which is effective for the Company beginning January 1,2008 and provides a definition of fair value, establishes a framework formeasuring fair value, and expands disclosures about fair value measurements forfuture transactions. The Company does not expect the adoption of thispronouncement to have a material impact on its financial position or results ofoperations.

 

On January 1, 2007, theCompany adopted Financial Accounting Standards Board (“FASB”) FinancialInterpretation No. (“FIN”) 48, *Accounting for Uncertaintyin Income Taxes - an interpretation of FASB Statement No. 109.* FIN48 clarifies the accounting for the uncertainty in recognizing income taxes inan organization in accordance with FASB Statement No. 109 by providing detailedguidance for financial statement recognition, measurement and disclosureinvolving uncertain tax positions. FIN 48 requires an uncertain tax position tomeet a more-likely-than-not recognition threshold at the effective date to berecognized both upon the adoption of FIN 48 and in subsequent periods. Theimplementation of FIN 48 did not have a material effect on the Company’sfinancial statements. See Note 5.

 

In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities,” whichpermits an entity to measure certain financial assets and financial liabilitiesat fair value. The objective of SFAS No. 159 is to improve financialreporting by allowing entities to mitigate volatility in reported earnings causedby the measurement of related assets and liabilities using differentattributes, without having to apply complex hedge accounting provisions. UnderSFAS No. 159, entities that elect the fair value option (byinstrument) will report unrealized gains and losses in earnings at eachsubsequent 

 

F-15

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reporting date. The fair value option election isirrevocable, unless a new election date occurs. SFAS No. 159 establishespresentation and disclosure requirements to help financial statement usersunderstand the effect of the entity’s election on its earnings, but does noteliminate disclosure requirements of other accounting standards. Assets andliabilities that are measured at fair value must be displayed on the face ofthe balance sheet. The Company does not expect the adoption of thispronouncement to have a material impact on its financial position or results ofoperations.

 

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

 

Capitalized costs at year end and costs incurredrelating to GeoPetro’s oil and gas activities are summarized as follows:

 

Capitalized costs as of December 31, 2007 are asfollows:

 
| ** **                                     | ** ** | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals**  | ** ** |
|------------------------------------------------|------------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|-------------|------------|
| Evaluated properties                           |       | $                      | 43,451,522 |          | $          | 2,388,050     |       | $          | —     |        | $          | 1,589,178 |   | $ | 47,428,750 |   |
| Unevaluated properties                         |       | 2,357,072              |       | 1,522,718     |       | 1,023,841     |       | 944,564    |       | 5,848,195   |       |
| Less—accumulated depletion and impairment |       | (10,940,471            | )          | (2,388,051    | )          | —        |       | (1,589,178 | )          | (14,917,700 | )          |
| Net capitalized costs                          |       | $                      | 34,868,123 |          | $          | 1,522,717     |       | $          | 1,023,841  |        | $          | 944,564 |   | $ | 38,359,245 |   |

 

Costs incurred for the year ended December 31,2007 are as follows:

 
| Property acquisition |   | $         | —    |     | $      | —    |   | $         | —  |      | $      | 296,189   |   | $ | 296,189   |   |
|----------------------|--------|-----------|-----------|----------|--------|-----------|--------|-----------|---------|-----------|--------|-----------|--------|---|-----------|--------|
| Exploration          |   | 401,821   |      | (175,000 | )      | 263,  956 |   | 1,668,899 |    | 2,159,676 |   |
| Development          |   | 2,616,090 |      | —   |   | —    |   | —    |    | 2,616,090 |   |
| Total costs incurred |   | $         | 3,017,911 |     | $      | (175,000  | )      | $         | 263,956 |      | $      | 1,965,087 |   | $ | 5,071,955 |   |

 

Capitalized costs as of December 31, 2006 are asfollows:

 
|                                           |   | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals**  |   |
|------------------------------------------------|--------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|-------------|--------|
| Evaluated properties                           |   | $                      | 40,835,432 |          | $          | 2,388,051     |       | $          | —     |        | $      | 478,027 |   | $ | 43,701,510 |   |
| Unevaluated properties                         |   | 1,955,252              |       | 1,697,718     |       | 759,885       |       | 90,626     |       | 4,503,481   |   |
| Less—accumulated depletion and impairment |   | (8,691,179             | )          | (2,388,051    | )          | —        |       | (478,027   | )          | (11,557,257 | )      |
| Net capitalized costs                          |   | $                      | 34,099,505 |          | $          | 1,697,718     |       | $          | 759,885    |        | $      | 90,626 |   | $ | 36,647,734 |   |

 

Costs incurred for the year ended December 31,2006 are as follows:

 

 
| Property acquisition |   | $          | 351,803    |   | $      | —  |   | $      | —  |       | $      | — |   | $ | 351,803    |   |
|----------------------|--------|------------|------------|--------|--------|---------|--------|--------|---------|------------|--------|--------|--------|---|------------|--------|
| Exploration          |   | (42,834    | )          | — |   | 576,296 |   | 20,561 |    | 554,023    |   |
| Development          |   | 15,816,118 |       | — |   | —  |   | — |    | 15,816,118 |   |
| Total costs incurred |   | $          | 16,125,087 |   | $      | —  |   | $      | 576,296 |       | $      | 20,561 |   | $ | 16,721,944 |   |

 

Capitalized costs as of December 31, 2005 are asfollows:

 
|                                           |   | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals** |   |
|------------------------------------------------|--------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|------------|--------|
| Evaluated properties                           |   | $                      | 25,019,314 |          | $          | 2,388,051     |       | $          | —     |       | $      | 439,178 |   | $ | 27,846,543 |   |
| Unevaluated properties                         |   | 1,646,282              |       | 1,697,718     |       | 183,589       |       | 108,915    |       | 3,636,504  |   |
| Less—accumulated depletion and impairment |   | (6,303,640             | )          | (2,388,051    | )          | —        |       | (439,178   | )          | (9,130,869 | )      |
| Net capitalized costs                          |   | $                      | 20,361,956 |          | $          | 1,697,718     |       | $          | 183,589    |       | $      | 108,915 |   | $ | 22,352,178 |   |

 

F-16

----

 

Costs incurred for the year ended December 31,2005 are as follows:

 
|                 |   | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals** |   |
|----------------------|--------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|------------|--------|
| Property acquisition |   | $                      | 1,220,150  |          | $          | —        |       | $          | —     |       | $      | — |   | $ | 1,220,150 |   |
| Exploration          |   | 1,246,550              |       | —        |       | (2,090,089    | )          | 26,564     |       | (816,975   | )      |
| Development          |   | 2,799,567              |       | —        |       | —        |       | —     |       | 2,799,567  |   |
| Total costs incurred |   | $                      | 5,266,267  |          | $          | —        |       | $          | (2,090,089 | )          | $      | 26,564 |   | $ | 3,202,742 |   |

 

Generally, sales or dispositions of oil and gasproperties, including sales of partial interests in prospects, are treated asadjustments to capitalized costs, with no gain or loss recorded.

 

*EvaluatedOil and Gas Properties**—*In periods prior to 2005 it was determined that thetotal net costs in the U.S. and Australian evaluated cost pool exceeded theirnet realizable value. Accordingly, impairment write-downs of $4,464,948 wererecorded in the prior periods. During 2007 and 2006, impairment write-downsassociated with the Canadian evaluated cost pool due to dry holes of $1,111,151,and $38,849 were recorded.

 

*UnevaluatedOil and Gas Properties—United States**—*As GeoPetro’s properties are evaluated throughexploration, they will be included in the amortization base. Costs ofunevaluated properties in the United States at December 31, 2007,2006 and 2005 represent exploration costs in connection with GeoPetro’sCalifornia and Alaska prospects. The prospects and their related costs inunevaluated properties have been assessed individually and no impairmentcharges were considered necessary for the United States properties for anyof the periods presented. The current status of these prospects is that seismicdata is being interpreted on an on-going basis on the subject lands within theprospects.

 

Drilling in the California and Alaska prospects isexpected to commence as early as 2008 and will continue in future periods. Asthe prospects are evaluated through drilling in future periods, the propertyacquisition and exploration costsassociated with the wells drilled will be transferred to evaluated propertieswhere they will be subject to amortization.

 

*UnevaluatedOil and Gas Properties—Australia**—*Unevaluated costs incurred in Australia representcosts in connection with the exploration of two exploration permit areas inAustralia. The prospects and their related costs in unevaluated 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, See Note 10.

 

*UnevaluatedOil and Gas Properties—Indonesia**—*Unevaluated costs incurred in Indonesia representcosts in connection with one production sharing contract area and additionalexploration efforts in Indonesia. The prospect and its related costs inunevaluated properties have been assessed individually and no impairmentcharges were considered 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. In October 2005, the Company sold its interestin another Indonesian production sharing contract for cash consideration of$2,400,000. The proceeds realized were credited to the Indonesian unevaluatedcost pool.

 

F-17

----

 

Drilling was commenced on the prospect early 2007 andis expected to continue in future periods. As the prospect is evaluated throughdrilling in future periods, the property acquisition and exploration costsassociated with the wells drilled will be transferred to evaluated propertieswhere they will be subject to amortization.

 

The Company retains a carried 12% stake in the Bengara(II) Block PSC through its subsidiary, Continental-GeoPetro (Bengara-II)Ltd. (“CGB2”), the operator company of the project with offices in Jakarta,Indonesia. GeoPetro’s partner, Continental Energy Corporation likewise retainsan 18% interest in the Bengara (II) Block. CNPCHK (Indonesia) Limited ownsthe remaining 70% in the Bengara (II) Block and has paid 100% of the costof drilling certain exploratory and appraisal wells.

 

In the event that the Company does not establishcommerciality and provided that no extensions are granted for establishingcommerciality, the Company must forfeit its interest in the production sharingcontract. If the Company forfeits its interest, it will be necessary to recordan impairment write-down equal to the capitalized costs recorded for the areaforfeited.

 

*Breakdownof Unevaluated Oil and Gas Properties**—*The following table sets forth a summary of oil andgas property costs not being amortized at December 31, 2007, by the periodin which the costs were incurred:

 
| ** **                     | ** ** | **Totals** | ** ** | **Year Ended  December 31,  2007** | ** ** | **Year Ended  December 31,  2006** | ** ** | **Year Ended  December 31,  2005** | ** ** | **2004 and Prior  Years** | ** ** |
|--------------------------------|------------|------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|-------------------------------------|------------|
| Unproved property  acquisition |       | $          | 2,150,134  |                                         | $          | 296,189                                      |       | $                                            | 351,803    |                                | $          | — |   | $ | 1,502,142 |   |
| Exploration                    |       | 3,698,061  |       | 1,048,525                                    |       | 515,173                                      |       | (816,974                                     | )          | 2,951,337                           |       |
| Total                          |       | $          | 5,848,195  |                                         | $          | 1,344,714                                    |       | $                                            | 866,976    |                                | $          | (816,974 | ) | $ | 4,453,479 |   |

 

Management expects that planned activities for theyear 2008 will enable the evaluation of approximately 5% of the costs as of December 31,2007. Evaluation of 30% of the remaining costs is expected to occur in 2008with the remaining 65% in 2009 and beyond.

 

**4.****                ****SHORT — TERM DEBT*:***

 

Short -term non-convertible debt at December 31,2007 and December 31, 2006 consisted of the following:

 
| ** **                                                                                                                                                                                                                           | ** ** | **December 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                                                                                                                                                                                           | ** ** | ** **                  | ** ** | ** **                  | ** ** |
| **Amounts Due Unrelated Parties:**                                                                                                                                                                                                   |       |                        |       |                        |       |
| Promissory note dated January 31, 2006, payable to Pinehill  Capital; collateralized with an undivided 5% of the net cash flow in  GeoPetro’s Madisonville Project; payable on or before October 31, 2007  (a) . |       | $                           | —     |                        | $          | 1,000,000 |   |
| Promissory note dated  February 1, 2007 payable on or before October 31, 2007 (b)                                                                                                                                          |       | —                      |       | —                      |       |
| Promissory note dated  February 6, 2007 payable on or before October 31, 2007 (c)                                                                                                                                          |       | —                      |       | —                      |       |
| Promissory note dated  February 1, 2007 payable on or before October 31, 2007 (d)                                                                                                                                          |       | —                      |       | —                      |       |
|                                                                                                                                                                                                                                 |       | —                      |       | 1,000,000                   |       |
| Less discount on  promissory notes                                                                                                                                                                                                   |       | —                      |       | (17,699                     | )          |
|                                                                                                                                                                                                                                 |       | $                           | —     |                        | $          | 982,301 |   |

 

F-18

----

 

----

(a)         The Company issued a $1,000,000 shortterm promissory note on January 31, 2006 with a maturity date of January 31,2007. The note may be repaid at any time without penalty. In the event the noteis not repaid by the maturity date, the Company has agreed to dedicate 5% ofthe net cash flow from the Madisonville Project in Texas toward the repaymentof the note and any accrued interest thereon. In connection with the note, theCompany paid a loan origination fee of $30,000 and granted a three-year warrantexercisable to purchase 150,000 Common Shares at $3.50 per share. The fairvalue of the warrants on the date of issuance, $182,390, as well as the $30,000loan origination fee,was recorded as a debt discount and is being amortized over the life ofthe promissory note. On February 1, 2007, the maturity date was extendedto October 31, 2007. The Company has paid $80,000 accrued interest thru January 31,2007. In connection with the extension, the Company paid a loan extension feeof $30,000 and granted a three-year warrant exercisable to purchase 50,000Common Shares at $3.50 per share. The fair value of the warrants on the date ofissuance, $57,242, together with the $30,000 loan extension fee, were recordedas a debt discount and are being amortized over the life of the promissorynote. As of December 31, 2007, the unamortized debt discount was $0. Thenote plus accrued interest were paid in full on October 31, 2007.

 

(b)         The Company issued a $500,000 short termpromissory note payable on February 1, 2007 with a maturity date of October 31,2007. The note may be repaid at any time without penalty. The principal plusaccrued interest on the note are due on the maturity date. In connection withthe note, the Company paid a loan origination fee of $15,000 and granted athree-year exercisable warrant to purchase 25,000 Common Shares at $3.50 pershare. The fair value of the warrants on the date of issuance, $27,072, as wellas the $15,000 loan origination fee, was recorded as a debt discount and isbeing amortized over the life of the promissory note. As of December 31,2007, the unamortized debt discount was $0. The note plus accrued interest werepaid in full on October 31, 2007.

 

(c)          The Company issued a $300,000 short termpromissory note payable on February 6, 2007 with a maturity date of October 31,2007. The note may be repaid at any time without penalty. The principal plusaccrued interest on the note are due on the maturity date. In connection withthe note, the Company paid a loan origination fee of $9,000 and granted a three-yearexercisable warrant to purchase 15,000 Common Shares at $3.50 per share. Thefair value of the warrants on the date of issuance, $16,214, as well as the$9,000 loan origination fee, was recorded as a debt discount and is beingamortized over the life of the promissory note. As of December 31, 2007,the unamortized debt discount was $0. The note plus accrued interest were paidin full on October 31, 2007.

 

(d)         The Company issued a $100,000 short termpromissory note payable on February 1, 2007 with a maturity date of October 31,2007. The note may be repaid at any time without penalty. The principal plusaccrued interest on the note are due on the maturity date. In connection withthe note, the Company paid a loan origination fee of $3,000 and granted athree-year exercisable warrant to purchase 5,000 Common Shares at $3.50 pershare. The fair value of the warrants on the date of issuance, $5,414, as wellas the $3,000 loan origination fee, was recorded as a debt discount and isbeing amortized over the life of the promissory note. As of December 31,2007, the unamortized debt discount was $0. The note plus accrued interest werepaid in full on October 31, 2007.

 

F-19

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

 

The Company files income tax returns in the U.S.federal jurisdiction and various states. The Internal Revenue Service recently completed an examination of theCompany’s U.S. income tax return for 2004. As a result of this examination, the Company’s federal net operatingloss was adjusted downward by $401,235. There are currently no federal or state income tax examinationsunderway.  Furthermore, the Company is nolonger subject to U.S. federal income tax examinations by the Internal RevenueService for tax years before 2005 and for state and local tax authorities fortax years before 2002.  The Company does,however, have net operating losses generated in tax years 1997 and after, whichremain open for examination.

 

The Company adopted the provisions of FASBInterpretation No. 48, Accounting for Uncertainty in Income Taxes, on January 1,2007. As a result of the adoption of FIN 48, the Company had unrecognized taxbenefits of $86,000 as of the date of adoption. This unrecognized tax benefit has been reduced to zero as of December31, 2007 because the uncertain tax position was ultimately not deducted in the2006 tax returns.  There have been no otherchanges during the year with respect to unrecognized tax benefits.  The Company does not foresee the totalamounts of unrecognized tax benefits significantly increasing within the next12 months.  Furthermore, no correspondinginterest and penalties have been accrued as the Company is in a net operatingloss position.

 

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

 

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

 

The effective tax rate for the year ended December 31,2007 is 3.1 percent (benefit) and is due largely to a refund of prior yearalternative minimum tax (“AMT”) which is partially offset by a liability forTexas Margin Tax.

 

The provision for income taxes consist of thefollowing:

 
| ** **                 | ** ** | **2007** | ** ** | **2006** | ** ** |
|----------------------------|------------|----------|------------|----------|------------|
| Current                    |       |     |       |     |       |
| Federal                    |       | $        | (70,000    | )        | $          | 59,500 |   |
| State                      |       | 19,000   |       | 2,500    |       |
| Total                      |       | (51,000  | )          | 62,000   |       |
|                       |       |     |       |     |       |
| Deferred                   |       |     |       |     |       |
| Federal                    |       | —   |       | —   |       |
| State                      |       | —   |       | —   |       |
| Total                      |       | —   |       | —   |       |
| Total Income Tax Provision |       | $        | (51,000    | )        | $          | 62,000 |   |

 

The actual income tax (benefit) expense differs fromthe expected tax (benefit) expense as computed by applying the U.S. Federalcorporate income tax rate of 35% for each period as follows:

 

F-20

----

 
| ** **                                | ** ** | **2007** | ** ** | **2006** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
| Amount of expected tax (benefit)  expense |       | $        | (584,000   | )        | $          | (169,000 | ) |
| Non-deductible expenses                   |       | 99,000   |       | 5,000    |       |
| Alternative minimum tax                   |       | (70,000  | )          | —   |       |
| Expiration of net  operating loss         |       | 3,000    |       | —   |       |
| Utilization of NOL                        |       | (254,000 | )          | 630,000  |       |
| Other                                     |       | (6,000   | )          | (10,000  | )          |
| Valuation allowance adjustments           |       | 761,000  |       | (394,000 | )          |
|                                      |       | $        | (51,000    | )        | $          | 62,000 |   |

 

Deferred income taxes reflect the net tax effects oftemporary differences between carrying amounts of assets and liabilities forfinancial reporting purposes and the amounts used for income tax purposes.Significant components of the Company’s deferred tax assets (liabilities) areas follows:

 
| ** **                             | ** ** | **2007**   | ** ** | **2006**   | ** ** |
|----------------------------------------|------------|------------|------------|------------|------------|
| Deferred tax assets  (liabilities):    |       |       |       |       |       |
| Net operating loss carry forwards      |       | $          | 8,843,000  |       | $          | 8,654,000 |   |
| Oil and gas property basis differences |       | (4,311,000 | )          | (5,069,000 | )          |
| Credit carryforwards                   |       | —     |       | —     |       |
| Stock compensation                     |       | 123,000    |       | 74,000     |       |
| Other                                  |       | (223,000   | )          | 13,000     |       |
| Total deferred tax assets              |       | 4,432,000  |       | 3,672,000  |       |
| Valuation allowance                    |       | (4,432,000 | )          | (3,672,000 | )          |
| Total net deferred taxes               |       | $          | —     |       | $          | — |   |

 

As of December 31, 2007,GeoPetro had net operating loss (NOL) carryforwards of approximately$24,771,000 for federal income tax purposes which begin to expire in 2010.However, in accordance with 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 in 2007 which do not reduce income taxes payable. Accordingly,$2,128,000 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 has $11,112,000of California and Alaska net operating losses which begin to expire in 2008. Inaccordance with SFAS 123(R), a portion of the state NOLs has similarly not beenbenefited for financial statement purposes as it relates to excess taxdeductions which have not resulted in the reduction of income taxes payable.The benefit of such excess tax deductions will not be recognized for financialsstatement purposes until the related deductions reduce state income taxespayable.

 

In addition, the Company has $341,000 of carryforwardcredits in Texas, a portion of which may be utilized each year against TexasMargin Tax liability through 2027.

 

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

 

During December 2007, theBoard of Directors approved the cashless exercise provision of options forofficers, directors and employee such that “Fair Market Value” shall equal thelesser of “Market Price” or $2.92., Cashless exercise is the security holder’selection to receive that number of shares of the Corporation’s Common Stockthat is equal to the quotient of: i) the Fair Market Value of such Shares, lessthe Exercise Price then in effect, multiplied by the number of Shares that thesecurity holder would otherwise have been entitled to purchase; over ii) theFair Market Value 

 

F-21

----

 

of $2.92.   The total common stock issued upon cashlessexercise was 249,963 shares. The Company paid totaled $386,600 in taxes inconnection with the cashless options exercise.

 

On April 25, 2007, May 9, 2007, and June 13,2007, an officer and director, exercised warrants to purchase 80,000, 70,000and 33,333 shares of common stock at an exercise price of $2.00, $2.00 and$4.00 per share, respectively. The warrants were granted on June 18, 2000and had expiration dates of between June 18 and June 30, 2007. On November 1, 2007, the same officerand director, exercised options to purchase 50,000 shares of common stock at anexercise price of $2.00 per share. The options were granted on December 29,2000 and had expiration date of December 29, 2007.

 

On February 12, 2007, Stuart J. Doshi, Presidentand CEO, loaned $100,000 to the Company. The note bore interest at 8% annuallyand was payable on demand. The note plus accrued interest was repaid on March 28,2007.

 

On June 7, 2006, the Company loaned $1,000,000 toG. Carter Sedanoui (“Borrower”), a shareholder, evidenced by a short termpromissory note payable to the Company with a maturity date on March 31,2007. On March 30, 2007, the Company extended the maturity date of thenote to June 30, 2007. The note plus the accrued interest was paid in fullon June 29, 2007.

 

The Company appointed David G. Anderson as a Directoron March 30, 2006. Mr. Anderson is the Senior Vice President and adirector of Dundee Securities Corporation, the lead underwriter in connectionwith a sale of common shares the Company completed on March 30, 2006. Thedecision to distribute the common shares and the determination of the terms of thedistribution were made through arm’s length negotiations primarily between theCompany and Dundee Securities Corporation as lead underwriter. Mr. Andersonhad some involvement in such negotiations solely in his capacity as a directorand officer of Dundee Securities Corporation. Dundee Securities Corporationreceived an underwriters’ fee totaling $632,000 in connection with theoffering.

 

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

 

GeoPetro’s articles of incorporation allow for theissuance of 100,000,000 shares of common stock, 1,000,000 shares of Series Apreferred stock (“Series A Stock”), 5,000,000 shares of

 

F-22

----

 

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 the event of a liquidation, the holders of common stock and Series Apreferred stock are entitled to share ratably in all assets remaining afterpayment of liabilities, subject to prior distribution rights of preferredstock.

 

*Conversionof Series A Stock**—*Upon completion of the Company’s initial publicoffering on March 30, 2006, all of the 1,000,000 shares of Series AStock automatically converted into a like number of common shares.

 

*Conversionof Series AA Preferred Stock**—*On March 28, 2007, all 1,890,710 of the Company’soutstanding shares of Series AA Stock automatically converted into1,890,710 shares of our common stock, no par value per share.  Under theCompany’s Amended and Restated Articles of Incorporation, the Series AAstock automatically converts into common shares on a one-for-one share basiseffective the first trading day after the reported high selling price for ourcommon shares is at least $5.25 per share for any consecutive ten trading days,which condition was met on March 27, 2007.  Dividends accrued on the Series AAStock at a rate of $0.28 per annum, per share, while the Series AA Stockwas outstanding.  In 2006, dividends paid on the Series AA Stocktotaled $529,400. Pursuant to the terms of the Series AA Stock, nodividends are payable for the first quarter of 2007.

 

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

 

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

 

The maximum number of Common Shares which may beawarded, optioned and sold under the plan is 5,000,000 (subject to adjustmentfor stock splits, stock dividends and certain other adjustments to GeoPetro’scommon stock); and the per share exercise price for Common Shares to be issuedpursuant to the exercise of an option shall be no less than the fair marketvalue of GeoPetro’s Common Shares as of the date of grant.

 

The Stock Incentive Plan provides for the granting toemployees of incentive stock options within the meaning of Section 422 ofthe United States Internal Revenue Code of 1986, as amended, and for thegranting of non-statutory stock options to directors who are not employees andconsultants. In the case of employees who receive incentive stock options whichare first exercisable in a particular calendar year and the aggregate fairmarket value of which exceeds $100,000, the excess of the $100,000 limitationshall be treated as a nonstatutory stock option under the Stock Incentive Plan.

 

The Stock Incentive Plan is being administered by theBoard of Directors. The Board of Directors determines the terms of the optionsgranted, including the number of Common Shares subject to each option, theexercisability and vesting requirements of each option, 

 

F-23

----

 

and the form of consideration payable upon theexercise of such option (i.e., whether cash or exchange of existing CommonShares in a cashless transaction or a combination thereof).

 

The Stock Incentive Plan will continue in effect for10 years from September 10, 2001 (i.e., the date first adoptedby the Board), unless sooner terminated by the board of directors. The Companyhas implemented a new 2004 Stock Option and Appreciation Rights Plan (the “StockOption Plan”) for the issuance of options to purchase Common Shares and/orstock appreciation rights in 2004 or thereafter to directors, officers,employees and consultants of the Company and its subsidiaries. The Stock OptionPlan has replaced the Stock Incentive Plan. Outstanding options 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 amount of Common Shares available to be issued under theStock Option Plan.

 

During 2007, no options were issued to employees ordirectors. No stock-based compensation was recognized for the year ended December 31,2005. Effective January 1, 2006, the Company adopted SFAS 123 (R) resultingin stock compensation expense for the twelve months period ended December 31,2006 of $201,335. During 2006, 150,000 stock options were issued to directorsand during 2005, 20,000 stock options were issued to employees pursuant to theStock Option Plan.

 

A summary of the status of GeoPetro’s stock optionplan is as follows:

 
| ** **                                  | ** ** | **Options** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|---------------------------------------------|------------|-------------|------------|----------------------|------------|------------------------------------------------|------------|
| Outstanding at  December 31, 2004      |       | 4,155,250   |       | $0.50  to $3.00      |       | $                                              | 1.77       |   |
| Granted                                     |       | 20,000      |       | $4.25  to $6.25      |       | 5.25                                           |       |
| Exercised                                   |       | (300,000    | )          | $2.00                |       | 2.00                                           |       |
|  Outstanding at December 31, 2005 |       | 3,875,250   |       | $0.50  to $6.25      |       | 1.77                                           |       |
| Granted                                     |       | 150,000     |       | $3.85                |       | 3.85                                           |       |
| Exercised                                   |       | —      |       | —               |       | —                                         |       |
| Expired                                     |       | (20,000     | )          | $3.00                |       | 3.00                                           |       |
| Outstanding at  December 31, 2006      |       | 4,005,250   |       | $0.50  to $6.25      |       | $                                              | 1.84       |   |
| Granted                                     |       | —      |       | —               |       | —                                         |       |
| Exercised                                   |       | (1,335,250  | )          | $1.25  to $2.00      |       | $                                              | 1.97       |   |
| Expired                                     |       | —      |       | —               |       | —                                         |       |
| Outstanding at  December 31, 2007      |       | 2,670,000   |       | $0.50  to $6.25      |       | $                                              | 1.77       |   |

 

The weighted average fair value of options grantedduring the year ended December 31, 2005, as calculated under theBlack-Scholes pricing model is $0.70 and for the weighted average fair value ofoptions granted in 2006, as calculated under the same method was $1.83 pershare.

 

The fair value of each option grant is estimated onthe date of grant using the Black-Scholes option pricing model with thefollowing weighted-average assumptions used for grants in 2005 and 2006:risk-free, weighted-average interest rates ranging from 3.75 to4.9 percent based on the U.S. Treasury yield curve in effect at the timeof grant, expected dividend yield of 

 

F-24

----

 

0 percent, expected life of 5 years from thedate of grant, and expected volatility of 10 and 58 percent.

 

The options outstanding as of December 31, 2007have the following contractual lives:

 
| **Number of  Options  Outstanding** | ** ** | **Number of  Options  Exercisable** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Remaining  Contractual Life** | ** ** |
|------------------------------------------|------------|------------------------------------------|------------|----------------------|------------|-------------------------------------------------------------|------------|
| 750,000                                  |       | 750,000                                  |       | 0.50                 |       | 0.33                                                        |       |
| 1,750,000                                |       | 1,400,000                                |       | 2.10                 |       | 5.43                                                        |       |
| 150,000                                  |       | 30,000                                   |       | 3.85                 |       | 3.29                                                        |       |
| 10,000                                   |       | 4,000                                    |       | 4.25                 |       | 2.01                                                        |       |
| 10,000                                   |       | 4,000                                    |       | 6.25                 |       | 2.44                                                        |       |
| 2,670,000                                |       | 2,188,000                                |       |                 |       |                                                        |       |

 

The total intrinsic value ofoptions outstanding was approximately $4,725,000 and $3,285,088 at December 31,2007 and 2006, respectively. The intrinsic value for exercisable options was$4,717,950 and $2,935,088 at December 31, 2007 and 2006,respectively. The total intrinsic value for stock options exercised wasapproximately $1,448,388 and $0 for the years ended December 31, 2007and 2006, respectively.

 

As of December 31, 2007, there are 2,188,000options which are exercisable. The remaining 482,000 options will becomeexercisable over the next four years. The stock compensation expense related tothe unvested awards is $291,910.

 

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

 

During 2007, the Company issued atwo-year exercisable common stock warrant to purchase 25,000 Common Shares at$3.50 and $4.51 per share to an unaffiliated third party for geophysicalservices. The purchase right under the warrant has an expiration date of February 12,2009 and February 28, 2009 unless terminated earlier in accordance withthe stock warrant purchase agreement. The fair value of the warrants totaled $32,533 and wascapitalized in oil and gas properties as part of the U.S. cost pool.

 

In conjunction with the issuance of a short term notepayable during 2007, GeoPetro issued warrants to purchase 95,000 shares ofGeoPetro’s common stock at exercise prices of $3.50 per share. The purchaserights under the warrants have expiration date of January 31, 2010 unlessterminated earlier in accordance with the stock warrant purchase agreement. Thefair value of the warrants issued on the date of the grant, $105,945 andorigination fees of $57,000 were recorded as discount to notes payable and werebeing amortized as interest expense over the term of the note. As of December 31,2007, the unamortized amount was $0.

 

In conjunction with the private placement on August 13,2007, the Company issued warrants to purchase 660,857 shares of GeoPetro’scommon stock at exercise price of $4.50 and $3.50 per share. These warrantissuances are discussed in Note 4.

 

The following table summarizes the number of sharesreserved for the exercise of common stock purchase warrants as of December 31,2007:

 

F-25

----

 
| ** **         | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **12/31/2006** | ** ** | **Warrants**  | ** ** | **Warrants** | ** ** | **Warrants**  | ** ** | **12/31/2007** | ** ** |
|--------------------|------------|----------------|------------|--------------|------------|----------------|------------|---------------|------------|--------------|------------|---------------|------------|----------------|------------|
| ** **         | ** ** | **Date**       | ** ** | **Price**    | ** ** | **Shares**     | ** ** | **Exercised** | ** ** | **Granted**  | ** ** | **(Expired)** | ** ** | **SHARES**     | ** ** |
|               |       |           |       |         |       |           |       |          |       |         |       |          |       |           |       |
| Common Stock       |       | 05/01/07       |       | $            | 5.25       |           | 5,000      |          | —     |         | —     |          | (5,000     | )              | —     |   |
| Common Stock       |       | 02/28/08       |       | $            | 5.00       |           | 27,000     |          | —     |         | —     |          | —     |           | 27,000     |   |
| Common Stock       |       | 03/31/08       |       | $            | 3.50       |           | 25,000     |          | (25,000    | )            | —     |          | —     |           | —     |   |
| 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       |           | 1,131,355  |          | (30,357    | )            | —     |          | —     |           | 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       |       | 01/31/10       |       | $            | 3.50       |           | —     |          | —     |         | 95,000     |          | —     |           | 95,000     |   |
| Common Stock       |       | 08/13/10       |       | $            | 3.85       |           | —     |          | —     |         | 60,078     |          | —     |           | 60,078     |   |
| Common Stock       |       | 08/13/12       |       | $            | 4.50       |           | —     |          | —     |         | 600,779    |          | —     |           | 600,779    |   |
|               |       |           |       |         |       |           |       |          |       |         |       |          |       |           |       |
| **Related party:** | ** ** | ** **     | ** ** | ** **   | ** ** | ** **     | ** ** | ** **    | ** ** | ** **   | ** ** | ** **    | ** ** | ** **     | ** ** |
| Common Stock       |       | 06/18/07       |       | $            | 2.00       |           | 150,000    |          | (150,000   | )            | —     |          | —     |           | —     |   |
| Common Stock       |       | 06/18/07       |       | $            | 4.00       |           | 33,333     |          | (33,333    | )            | —     |          | —     |           | —     |   |
| Common Stock       |       | 06/18/07       |       | $            | 5.00       |           | 33,334     |          | —     |         | —     |          | (33,334    | )              | —     |   |
| Common Stock       |       | 04/30/08       |       | $            | 3.00       |           | 33,333     |          | —     |         | —     |          | —     |           | 33,333     |   |
| Common Stock       |       | 12/31/08       |       | $            | 2.00       |           | 185,125    |          | —     |         | —     |          | —     |           | 185,125    |   |
|               |       |           |       |         |       |           |       |          |       |         |       |          |       |           |       |
|               |       |           |       |         |       | 1,937,855      |       | (238,690      | )          | 780,857      |       | (38,334       | )          | 2,441,688      |       |

 

In conjunction with the issuance of a short term notepayable during 2006, GeoPetro issued warrants to purchase 150,000 shares ofGeoPetro’s common stock at exercise prices of $3.50 per share. The purchaserights under the warrants have expiration date of January 31, 2009 unlessterminated earlier in accordance with the stock warrant purchase agreement. Thefair value of the warrants issued on the date of the grant, $182,390, was recordedas a discount to notes payable and is being amortized as interest expense overthe term of the note. As of December 31, 2006, the unamortized amount is$17,966.

 

The following table summarizes the number of sharesreserved for the exercise of common stock purchase warrants as of December 31,2006:

 
| ** **   | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **12/31/2005** | ** ** | **Warrants**  | ** ** | **Warrants** | ** ** | **Warrants**  | ** ** | **12/31/2006** | ** ** |
|--------------|------------|----------------|------------|--------------|------------|----------------|------------|---------------|------------|--------------|------------|---------------|------------|----------------|------------|
| ** **   | ** ** | **Date**       | ** ** | **Price**    | ** ** | **Shares**     | ** ** | **Exercised** | ** ** | **Granted**  | ** ** | **(Expired)** | ** ** | **SHARES**     | ** ** |
|         |       |           |       |         |       |           |       |          |       |         |       |          |       |           |       |
| Common Stock |       | 06/30/06       |       | $            | 5.00       |           | 10,000     |          | —     |         | —     |          | (10,000    | )              | —     |   |
| Common Stock |       | 11/01/06       |       | $            | 3.00       |           | 20,000     |          | —     |         | —     |          | (20,000    | )              | —     |   |
| Common Stock |       | 12/31/06       |       | $            | 4.00       |           | 10,000     |          | —     |         | —     |          | (10,000    | )              | —     |   |
| Common Stock |       | 12/31/06       |       | $            | 2.00       |           | 75,000     |          | (75,000    | )            | —     |          | —     |           | —     |   |
| Common Stock |       | 05/01/07       |       | $            | 5.25       |           | 5,000      |          | —     |         | —     |          | —     |           | 5,000      |   |
| Common Stock |       | 02/28/08       |       | $            | 5.00       |           | 27,000     |          | —     |         | —     |          | —     |           | 27,000     |   |
| Common Stock |       | 03/31/08       |       | $            | 3.50       |           | 25,000     |          | —     |         | —     |          | —     |           | 25,000     |   |

 

F-26

----

 
| 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   |      | 1,131,355 |    | — |    | —  |     | —  |      | 1,131,355 |   |
| Common Stock       |   | 03/31/09 |   | $      | 5.25   |      | 100,000   |    | — |    | —  |     | —  |      | 100,000   |   |
| Common Stock       |   | 01/31/09 |   | $      | 3.50   |      | —    |    | — |    | 150,000 |     | —  |      | 150,000   |   |
|               |   |     |   |   |   |      |      |    |   |    |    |     |    |      |      |
| **Related party:** |   |     |   |   |   |      |      |    |   |    |    |     |    |      |      |
| Common Stock       |   | 06/18/07 |   | $      | 2.00   |      | 150,000   |    | — |    | —  |     | —  |      | 150,000   |   |
| Common Stock       |   | 04/30/08 |   | $      | 3.00   |      | 33,333    |    | — |    | —  |     | —  |      | 33,333    |   |
| Common Stock       |   | 12/31/06 |   | $      | 4.00   |      | 66,667    |    | — |    | —  |     | (66,667 | )         | —    |   |
| Common Stock       |   | 06/18/07 |   | $      | 4.00   |      | 33,333    |    | — |    | —  |     | —  |      | 33,333    |   |
| Common Stock       |   | 06/18/07 |   | $      | 5.00   |      | 33,334    |    | — |    | —  |     | —  |      | 33,334    |   |
| Common Stock       |   | 12/31/08 |   | $      | 2.00   |      | 185,125   |    | — |    | —  |     | —  |      | 185,125   |   |
|               |   |     |   |   |   |      |      |    |   |    |    |     |    |      |      |
|               |   |     |   |   |   | 1,969,522 |      | (75,000 | )      | 150,000 |    | (106,667 | )       | 1,937,855 |      |

 

In conjunction with the issuance of units of equitysecurities during 2005, GeoPetro issued warrants to purchase 37,000 shares ofGeoPetro’s common stock at exercise prices of $5.00 per share. The purchaserights under the warrants have expiration dates from June 30, 2006 to February 28,2008 unless terminated earlier in accordance with the stock warrant purchaseagreement. The Company agreed to extend the warrants by a period of one yearfor a total of 143,334 shares. The fair value of the warrants on the date ofextension, $32,404, was disclosed and combined with compensation expense, FAS123 in Note 2 and $2,927 was recorded as consulting expense.

 

The following table summarizes the number of sharesreserved for the exercise of common stock purchase warrants as of December 31,2005:

 
| ** **     | ** ** | ** **     | ** ** | ** **   | ** ** | ** **   | ** ** | ** **    | ** ** | ** **   | ** ** | **Warrants**  | ** ** | ** **   | ** ** |
|----------------|------------|----------------|------------|--------------|------------|--------------|------------|---------------|------------|--------------|------------|---------------|------------|--------------|------------|
| ** **     | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **12/31/04** | ** ** | **Warrants**  | ** ** | **Warrants** | ** ** | **Extended**  | ** ** | **12/31/05** | ** ** |
| ** **     | ** ** | **Date**       | ** ** | **Price**    | ** ** | **Shares**   | ** ** | **Exercised** | ** ** | **Granted**  | ** ** | **(expired)** | ** ** | **Shares**   | ** ** |
| Common Stock   |       | 03/31/05       |       | $            | 2.00       |         | 37,500     |          | (37,500    | )            | —     |          | —     |         | —     |   |
| Common Stock   |       | 03/31/05       |       | $            | 3.00       |         | 10,000     |          | (10,000    | )            | —     |          | —     |         | —     |   |
| Common Stock   |       | 04/30/05       |       | $            | 2.50       |         | 10,000     |          | (10,000    | )            | —     |          | —     |         | —     |   |
| Common Stock   |       | 07/31/05       |       | $            | 2.00       |         | 37,500     |          | (37,500    | )            | —     |          | —     |         | —     |   |
| Common Stock   |       | 07/31/05       |       | $            | 3.00       |         | 10,000     |          | —     |         | —     |          | (10,000    | )            | —     |   |
| Common Stock   |       | 12/31/05       |       | $            | 5.00       |         | 50,000     |          | —     |         | —     |          | (50,000    | )            | —     |   |
| Common Stock   |       | 06/30/06       |       | $            | 5.00       |         | —     |          | —     |         | 10,000     |          | —     |         | 10,000     |   |
| Common Stock   |       | 11/01/06       |       | $            | 3.00       |         | 20,000     |          | —     |         | —     |          | —     |         | 20,000     |   |
| Common Stock   |       | 12/31/06       |       | $            | 4.00       |         | 10,000     |          | —     |         | —     |          | —     |         | 10,000     |   |
| Common Stock   |       | 12/31/06       |       | $            | 2.00       |         | 75,000     |          | —     |         | —     |          | —     |         | 75,000     |   |
| Common Stock   |       | 05/01/07       |       | $            | 5.25       |         | 5,000      |          | —     |         | —     |          | —     |         | 5,000      |   |
| Common Stock   |       | 02/28/06       |       | $            | 5.00       |         | —     |          | —     |         | 27,000     |          | —     |         | 27,000     |   |
| Common Stock   |       | 03/31/08       |       | $            | 3.50       |         | 25,000     |          | —     |         | —     |          | —     |         | 25,000     |   |
| 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       |         | 1,161,356  |          | (30,000    | )            | —     |          | (1         | )            | 1,131,355  |   |
| Common Stock   |       | 03/31/09       |       | $            | 5.25       |         | 100,000    |          | —     |         | —     |          | —     |         | 100,000    |   |
|           |       |           |       |         |       |         |       |          |       |         |       |          |       |         |       |
| Related Party: |       |           |       |         |       |         |       |          |       |         |       |          |       |         |       |
| Common Stock   |       | 06/18/06       |       | $            | 2.00       |         | 150,000    |          | —     |         | —     |          | —     |         | 150,000    |   |
| Common Stock   |       | 06/18/06       |       | $            | 3.00       |         | 33,333     |          | —     |         | —     |          | —     |         | 33,333     |   |
| Common Stock   |       | 12/31/06       |       | $            | 4.00       |         | 66,667     |          | —     |         | —     |          | —     |         | 66,667     |   |
| Common Stock   |       | 06/18/07       |       | $            | 4.00       |         | 33,333     |          | —     |         | —     |          | —     |         | 33,333     |   |
| Common Stock   |       | 06/18/07       |       | $            | 5.00       |         | 33,334     |          | —     |         | —     |          | —     |         | 33,334     |   |
| Common Stock   |       | 12/31/08       |       | $            | 2.00       |         | 185,125    |          | —     |         | —     |          | —     |         | 185,125    |   |
|           |       |           |       |         |       | 2,117,523    |       | (125,000      | )          | 37,000       |       | (60,001       | )          | 1,969,522    |       |

 

F-27

----

 

**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,dated July 28, 1997 (effective July 1, 1997) and amended on January 11,2001, July 1, 2003, April 20, 2004, May 9, 2005, July 28,2005 and January 30, 2006. The contract as amended provides for afive-year term commencing May 1, 2005 which term is automatically extendedfor successive two-year renewal terms unless: (a) the board of directorselects not to renew thecontract and the Company provides notice to Mr. Doshi of suchnon-renewal at least six months prior to the expiry of his employment term orany renewal term, or (b) Mr. Doshi attains age 75, in which casethe term ends upon the completion of the calendar year in which he becomes75 years old unless the Company and Mr. Doshi mutually agree toone-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 an employment contract dated April 28,1998 and amended on June 15, 2000, May 12, 2003 and January 1,2005 with its Vice President of Exploration, David V. Creel. The contractprovides an annual salary of $150,000 and may be terminated by GeoPetro withoutcause upon the payment to Mr. Creel of cash payments equal to the lesserof three months’ base salary or base salary during the remainder of theemployment term, and, in the event of termination without cause, all unvestedoptions issued by GeoPetro to Mr. Creel will vest. On December18, 2006,the independent members of the board of directors, acting on therecommendations of Stuart J. Doshi, the President and CEO, voted to increasethe salary of Mr. Creel, to $163,200 annually effective January 1,2007.

 

GeoPetro has executed an employment contract dated June 19,2000 and amended on December 12, 2002, January 1, 2005, and December 18,2007 with its Vice President of Finance and Chief Financial Officer, J. ChrisSteinhauser. The contract provides for an annual salary of $163,200 and may beterminated by GeoPetro without cause upon the making of cash payments equal tothe lesser of three months’ base salary or base salary during the remainder 

 

F-28

----

 

of the employment term, and, in the event oftermination without cause, all unvested warrants issued by GeoPetro to Mr. Steinhauserwill vest.

 

*OfficeLease**—*EffectiveMarch 1, 2004, GeoPetro is committed under an office sublease whichprovides for a sixty month term. The sublease is cancelable by either partyafter thirty-six months. The sublease provides for minimum monthly leasepayments of $5,788 during the first thirty-six months of the lease term and$6,527 per month from the thirty-seventh month to the sixtieth month. Minimumannual rentals due under this agreement are as follows:

 
| **Year** | ** ** | **Amount** | ** ** |
|----------|------------|------------|------------|
| 2008     |       | 78,334     |       |
| 2009     |       | 13,056     |       |

 

Rent expense for the years ended December 31,2007, 2006, and 2005, was approximately $76,856, $69,466, and $69,466respectively, and is included in general and administrative expenses in theaccompanying statements of operations.

 

*MadisonvilleMGP Agreement**—*GeoPetroowns a 100% working interest in leases located in Madisonville (Rodessa) Fieldin Madison County, Texas. GeoPetro’s working interest covers the Rodessaformation interval at approximately 11,800 feet of depth. The Rodessa reservesare being developed through the re-entry and recompletion of the Ruby Magness No. 1well (originally drilled in 1994) and the drilling of additional welllocations. The natural gas in the Rodessa formation contains 28% impuritieswhich must be removed in order to meet pipeline quality specifications.

 

In this connection, GeoPetro entered into agreementswith a subsidiary of a NYSE listed company, Hanover Compressor Company (“Hanover”),that funded, constructed, installed and operated a dedicated gas treatmentplant to process the Rodessa gas. The gas treatment plant is presently capableof treating and bringing up to pipeline specifications approximately18 million cubic feet of inlet gas per day. Gateway Processing Company (“Gateway”)has installed field gathering pipelines and a sales pipeline with an estimatedcapacity of at least 70 million cubic feet of gas per day to transport thetreated natural gas to a major pipeline in the area.

 

Effective July 25, 2005, Madisonville GasProcessing, LP (“**MGP**”)purchased the natural gas treatment plant from Hanover. Concurrent with MGP’spurchase of the gas treatment plant, the Company, Gateway and MGP terminatedthe Hanover/Gateway agreements and entered into a new agreement, (the “**MGP Agreement**”), to treat and transport theCompany’s gas production from the Madisonville Project. As a result of the MGPAgreement, MGP has committed to install and make operational additionaltreating facilities capable of treating 50 MMcf/d, which combined with thecapacity of the current in-service treating facilities will represent a totaltreating capacity of 68 MMcf/d for the Madisonville treatment plant.

 

The term of the MGP Agreement commenced August 1,2005 and continues so long as the Company owns any oil and gas leases in theMadisonville Field, provided that it shall terminate 30 years from theeffective date unless extended. Under the terms of the MGP Agreement, theCompany has committed all natural gas production from its interest in theMadisonville Projectto MGP. MGP purchases the untreated natural gas from the Company at thewell site point of delivery for a net price equal to the weighted average priceper MMBTU that MGP receives for the natural gas delivered to the sales pipelineless certain gathering, treatment and transportation charges. The gathering,treatment and transportation price adjustments are described below. Allproceeds from MGP’s sale of Rodessa Formation gas are deposited in an escrowaccount and then disbursed in accordance with the joint direction of theCompany and MGP.

 

F-29

----

 

The MGP Agreement provides that certain gathering,treating and transportation fees shall be paid to MGP from the escrow account.The MGP Agreement provides that MGP will receive a gathering and marketing feeof $0.07 and $0.01 per Mcf, respectively, of gas measured and delivered to thenatural gas treatment plant. In addition, for the first 18,000 Mcf/d ofgas measured and delivered to the inlet flange of the gas treatment plant, MGPwill receive a treating fee of $1.50 per Mcf. This treating fee will remain ineffect until September 30, 2010. For any gas volumes in excess of18,000 Mcf/d of gas delivered to the inlet flange of the gas treatmentplant, MGP will receive a treating fee of $1.10 per Mcf. Beginning October 1,2010, this fee of $1.10 per Mcf shall be charged for all gasmeasured and delivered to the plant. One-quarter (1⁄4) of the foregoing treatingfees will be adjusted using the Producer Price Index for Industrial Commodities(“PPI”) and one-quarter (1⁄4) using the Consumer Price Index (“CPI”) commencing January 1,2006. One-half (1⁄2) of the foregoing gathering and marketing fees will beadjusted using the Consumer Price Index (“CPI”) commencing January 1, 2006.The Company has the right, upon giving 60 days’ notice, to terminate themarketing fee whereupon it shall assume the sole responsibility of marketingthe natural gas sold.

 

For the first 18,000 Mcf/d of gas measured anddelivered to the inlet flange of the gas treatment plant, Gatewaywill receive a transportation fee of $0.10 per Mcf. This fee will remain ineffect for 36 months from the effective date of the MGP Agreement.Beginning in the 37th monthand terminating at the end of the 60th monthfrom the effective date of the MGP Agreement, the fee shall be reduced to $0.08per Mcf for the first 18,000 Mcf/d of gas measured and delivered tothe inlet flange of the gas treatment plant. For any gas volumes inexcess of 18,000 Mcf/d of gas measured and delivered to the inletflange of the gas treatment plant, Gateway will receive a transportation fee of$0.12 per Mcf measured and delivered from the outlet flange of theplant. This fee will remain in effect 36 months from the effective date ofthe MGP Agreement and shall be reduced to $0.10 per Mcf thereafter. After60 months, this transportation fee shall be $0.10 per Mcf for all volumesdelivered from the outlet flange of the plant.

 

The foregoing gathering, treatment and transportationprice adjustments are inclusive of all costs and expenses to gather, separate,treat, dehydrate and transport natural gas produced and delivered from theCompany’s well(s).

 

The Company has committed to a three-well drillingprogram to facilitate the expansion of the gas treatment plant. The Company hasdrilled two of the three required wells to the Rodessa formation. Thecommitment requires the Company to drill the third well sufficient to test theSmackover Formation (estimated to be encountered at approximately 18,000 feet)on or before September 30, 2008. It is estimated that the 18,000 foot wellwill cost $12 million to drill and complete. The Company has granted MGP asecurity interest in the Madisonville Field properties to secure the three wellcommitment. The security interest shall be subordinated to any third partylender in the event the Company secures future debt against the property. MGPhas granted the Company a similar security interest in the gas treatment plantto secure its obligation to expand the treatment plant on a timely basis.

 

*MadisonvilleNet Profits Interest**—*Redwood LP’s 100% working interest is subject to a netprofits interest in favor of an unrelated third party. 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.

 

F-30

----

 

*TheCook Inlet Alaska CBM Project*—The Company entered into an agreement with PioneerOil Company, Inc. (“Pioneer”) dated April 20, 2005, wherein itacquired a 100% working interest (81% net revenue interest) in approximately117,000 acres onshore in Cook Inlet, Alaska. The Company has subsequentlyacquired an additional 5,000 acres in this project. The terms provide for theCompany to pay total consideration of $20 per acre, or approximately$2.3 million, for the leases. The Option provides that the Company willpay the total lease consideration in two installments. The Company paid thefirst installment totaling $1,068,063 on August 17, 2005 and has receivedassignment of the 100% working interest in the leases. Within three years fromthe date of receipt of legally sufficient assignment of the 100% workinginterest in the leases, the Company has the option to conduct a $2.5 millionwork program on the leases over a three-year period, and, after completion ofthe work program and an evaluation of the results, to remit the finaladditional acreage consideration of $10 per acre for the leases. The agreementprovides that if the Company fails to pay the lease consideration when due,fails to perform the work program or otherwise defaults under the agreement, itshall forfeit its interest and reassign the leases to Pioneer with no furtherliability to GeoPetro.

 

*Sale ofAustralian Interests, EP 381 & EP 408***—**On June 20, 2007, the Company agreedto sell and transfer all of its remaining property interests in Australia to anunrelated party for cash consideration and a Petroleum Sales Royalty Paymentequal to 25% of the future annual earnings before interest, taxes, depreciationand amortization  from the property interests. Specifically, the agreementprovides that the Company will be paid consideration for the sale and transferof its property 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.

 

*GoodwinProspect, Central Alberta, Canada*—On June 21, 2007, the Company entered into aparticipation agreement wherein it acquired a 50% non-operated working interestin the Goodwin Prospect, which is located in the Central Alberta Basin,Canada.  A total of 12,000 acres can be earned by the Company by thedrilling of wells.  During 2007, the Nexstar Goodwin 16-1958-12 Well wasdrilled.  The Company has production tested this well and determined thatit is non-commercial. The Company has plugged and abandoned this well. As aresult, the Company recorded a ceiling test writedown of $543,042 in the yearof 2007.

 

F-31

----

 

*Swan Hills Project. Central Alberta, Canada—*On October 17, 2007, The Company acquired a 33%non-operated working interest in 4,400 acres in the Central Alberta Basin, Alberta,Canada. The Company paid a total of $274,000 to acquire these leases.

* *

*WildwoodProspect, Central Alberta, Canada*—On October 1, 2007, the Company entered into aparticipation agreement wherein it acquired a 50% non-operated working interestin the Wildwood Prospect, which is located in the Wildwood Alberta Basin,Canada.  On December 17, 2007, TheWildwood 11-22-55-09 well was spudded , with Ironhand Drilling Rig #1. TheCompany has production tested this well and determined that it isnon-commercial. The Company has plugged and abandoned this well. As a result,the Company recorded a ceiling test writedown of $551,065 in the year of 2007.

 

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

 

*SouthDry Hollow Prospect, Lavaca County, Texas*—On February 26, 2008, the Company’s subsidiary,South Texas GeoPetro LLC, entered into a participation agreement wherein itacquired a 15% non-operated working interest in the South Dry Hollow Prospect,which is located in Lavaca County, Texas. On February 25, 2008, theCompany paid a $150,000 prospect fee and advanced $1.1 million to drill theEichhorn #1 Well. The Eichorn #1 Well shall be drilled to a total depthsufficient to test the Rochelle Sand, the top of which is at a stratigraphicequivalent depth of approximately 16,000 feet.

 

**12.****         ****UNAUDITED SUPPLEMENTARY OIL AND GASRESERVE INFORMATION:**

 

The following supplementary information is presentedin compliance with United States Securities and Exchange Commission regulationsand is not covered by the report of GeoPetro’s independent registered publicaccountants. The information required to be disclosed for the years ended 2007,2006 and 2005 in accordance with FASB Statement No. 69, “Disclosures aboutOil and Gas Producing Activities,” is discussed below and is further detailedin the following tables.

 

The reserve quantities and valuations for fiscal 2007and 2006 are based upon estimates by MHA Petroleum Consultants. The reservequantities and valuations for fiscal 2005 is based upon estimates by SprouleAssociates Inc. The proved reserves presented herein are located entirelywithin the United States. Proved reserves are the estimated quantities ofcrude oil, natural gas and natural gas liquids which geological and engineeringdata demonstrate with reasonable certainty to be recoverable in future yearsfrom known reservoirs under existing economic and operating conditions, i.e.prices and costs as of the date the estimate is made. Prices includeconsideration of changes in existing prices provided only by contractualarrangements, but not on escalations based upon future conditions. Reservoirsare considered proved if economic productivity is supported by either actualproduction or a conclusive formation test. The area of a reservoir consideredproved includes

 

F-32

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(A) that portion delineated by drilling anddefined by gas-oil and/or oil-water contacts, if any, and (B) theimmediately adjoining portions not yet drilled, but which can reasonably bejudged as economically productive on the basis of available geological andengineering data. In the absence of information on fluid contacts the lowestknown structural occurrence of hydrocarbons controls the lower proved limit ofthe reservoir.

 

Proved developed reserves are reserves that can beexpected to be recovered through existing wells with existing equipment andoperating methods. Additional oil and gas reserves expected to be obtainedthrough the application of fluid injection or other improved recoverytechniques for supplementing the natural forces and mechanisms of primaryrecovery should be included as “proved developed reserves” only after testingby a pilot project or after the operation of an installed program has confirmedthrough production response that increased recovery will be achieved.

 

The estimates included in the following tables are bytheir nature inexact and are subject to changing economic, operating andcontractual conditions. At December 31, 2007, all of GeoPetro’s reservesare attributable to three producing wells, one shut-in wells and an undevelopedlocation. Other than the one producing well which has been on production since May 2003,one shut-in well which was placed on production in March 2006, and anothershut-in well which was placed on production in June 2007.  There is no other production history as of orsubsequent to that date. Reserve estimates for these wells are subject tosubstantial upward or downward revisions after production commences and aproduction history is obtained. Accordingly, reserve estimates of future netrevenues from production may be subject to substantial revision from year toyear. Reserve information presented herein is based on reports prepared byindependent petroleum engineers.

 

The assumptions used to compute the standardizedmeasure are those prescribed by the Financial Accounting Standards Board and,as such, do not necessarily reflect GeoPetro’s expectations for actual revenuesto be derived from those reserves nor their present worth. The limitationsinherent in the reserve quantity estimation process, as discussed previously,are equally applicable to the standardized measure computations since these arethe basis for the valuation process.

 
| ** **                       | ** ** | **December 31,** | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
|----------------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|
| **FACTORS**                      | ** ** | **2007**              | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| ** **                       | ** ** | **(MMcf)**            | ** ** | **(MMcf)**            | ** ** | **(MMcf)**            | ** ** |
| **Beginning of period**          |       | 24,600                |       | 21,428                |       | 18,408                |       |
| Extensions                       |       | —                |       | —                |       | —                |       |
| Improved Recovery                |       | —                |       | —                |       | —                |       |
| Technical Revisions              |       | 293                   |       | 5,122                 |       | 4,762                 |       |
| Discoveries                      |       | —                |       | —                |       | —                |       |
| Acquisitions                     |       | —                |       | —                |       | —                |       |
| Dispositions                     |       | —                |       | —                |       | —                |       |
| Economic Factors                 |       | —                |       | —                |       | —                |       |
| Production                       |       | (1,755                | )          | (1,950                | )          | (1,742                | )          |
| **Year ended December 31,** |       | 23,139                |       | 24,600                |       | 21,428                |       |

 

F-33

----

 

**PROVED RESERVES PRESENTED HEREIN ARELOCATED ENTIRELY WITHIN THE UNITED STATES**

 
| ** **                      | ** ** | **AS OF DECEMBER 31,** | ** ** |
|---------------------------------|------------|---------------------------------------|------------|
| ** **                      | ** ** | **2007**                              | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                      | ** ** | **(MMcf)**                            | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
| Proved developed                |       | 10,495                                |       | 12,235 |   | 4,645 |   |
| Proved developed  non-producing |       | 12,644                                |       | 12,365 |   | 8,903 |   |
| Proved undeveloped              |       | —                                |       | — |   | 7,880 |   |
|                            |       |                                  |       |   |   |   |   |
| Total                           |       | 23,139                                |       | 24,600 |   | 21,428 |   |

 

For purposes of the following disclosures, estimateswere made of quantities of proved reserves and the periods during which theyare expected to be produced. Future cash flows were computed by applyingyear-end prices to estimated annual future production from proved gas reserves.The average year-end prices for gas were as indicated below. Future developmentand production costs were computed by applying year-end costs to be incurred inproducing and further developing the proved reserves. Future income taxexpenses 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.

 

**STANDARDIZED MEASURE OF DISCOUNTEDFUTURE NET CASH FLOWSRELATING TO PROVED PETROLEUM AND NATURAL GAS RESERVES(UNAUDITED)**

 
| ** **                                                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2007**                                   | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                | ** ** | **(in thousands)**                    | ** ** |
| Future cash inflows                                       |       | $                                          | 135,264    |   | $ | 101,867 |   | $ | 162,459 |   |
| Future production costs                                   |       | (45,649                                    | )          | (37,783 | ) | (60,176 | ) |
| Future development costs                                  |       | (1,075                                     | )          | (1,074 | ) | (6,560 | ) |
| Future income taxes                                       |       | (13,762                                    | )          | (8,128 | ) | (18,941 | ) |
| Future net cash flows                                     |       | 74,778                                     |       | 54,882 |   | 76,782 |   |
| 10% annual discount                                       |       | (14,570                                    | )          | (8,341 | ) | (13,293 | ) |
| Standardized measure of  discounted future net cash flows |       | $                                          | 60,208     |   | $ | 46,541 |   | $ | 63,489 |   |

 

**AVERAGE YEAR-END PRICE**

 

| **2007 REPORT**   | ** ** | **2006 REPORT**   | ** ** | **2005 REPORT**   | ** ** |
|------------------------|------------|------------------------|------------|------------------------|------------|
| **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** |
| $                      |  6.81 |                   | $          | 5.40                   |       | $ | 7.80 |   |
|                        |            |                        |            |                        |            |  |  |  |

 

F-34

----

 

The following are the principal sources of changes inthe standardized measure of discounted future net cash flows:

 

**CHANGES IN THE STANDARDIZED MEASUREOF DISCOUNTED FUTURE NET CASHFLOWS FROM PROVED PETROLEUM AND NATURAL GAS RESERVEQUANTITIES (Unaudited)PROVED RESERVES ARE LOCATED ENTIRELY WITHIN THE UNITED STATES**

 
| ** **                                                                                    | ** ** | **2007**                       | ** ** | **2006** | ** ** | **2005** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|--------------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                    | ** ** | **(in $ thousands)** | ** ** |
| Standardized measure of discounted future net cash flows, beginning  of period                |       | $                              | 46,541     |     | $          | 63,489   |       | $ | 37,651 |   |
| Sales of Oil and Natural Gas and NGLs Produced, Net of Production  Costs, Taxes and Royalties |       | (4,653                         | )          | (4,480   | )          | (6,228   | )          |
| Net Change in Prices, Production Costs and Royalties Related to  Future Production            |       | 23,322                         |       | (39,067  | )          | 20,399   |       |
| Changes in Previously Estimated Development Costs Incurred During the  Period                 |       | —                         |       | 6,545    |       | 2,800    |       |
| Changes in Estimated Future Development Costs                                                 |       | (1                             | )          | (1,075   | )          | (4,410   | )          |
| Net Change Resulting from Revisions in Quantity Estimates                                     |       | 1                              |       | 1,074    |       | 18,524   |       |
| Extensions                                                                                    |       | —                         |       | 6,740    |       | —   |       |
| Accretion of discount                                                                         |       | 5,291                          |       | 8,019    |       | 3,765    |       |
| Other                                                                                         |       | (4,659                         | )          | (4,656   | )          | (1,296   | )          |
| Net Change in Income Taxes                                                                    |       | (5,634                         | )          | 9,952    |       | (7,716   | )          |
| Standardized measure of discounted future net cash flows, end of  period                      |       | $                              | 60,208     |     | $          | 46,541   |       | $ | 63,489 |   |

 

**13.****         ****UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA:**

 
| **2007**                                    | ** ** | **First** | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** |
|---------------------------------------------|------------|-----------|------------|------------|------------|-----------|------------|------------|------------|
|                                        |       |      |       |       |       |      |       |       |       |
| Revenues                                    |       | $         | 1,823,342  |       | $          | 2,388,850 |       | $          | 1,231,370  |   | $ | 1,447,215 |   |
| Income (loss) from  operations              |       | $         | (124,437   | )          | $          | 305,145   |       | $          | (691,226   | ) | $ | (1,025,179 | ) |
| Earnings (loss) per share  from operations: |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | (0.00      | )          | $          | 0.01      |       | $          | (0.02      | ) | $ | (0.03 | ) |
| Diluted                                     |       | $         | (0.00      | )          | $          | 0.01      |       | $          | (0.02      | ) | $ | (0.03 | ) |
| Net income (loss)                           |       | $         | (182,614   | )          | $          | 238,778   |       | $          | (745,691   | ) | $ | (927,277 | ) |
| Earnings (loss) per common  share:          |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | (0.01      | )          | $          | 0.01      |       | $          | (0.02      | ) | $ | (0.03 | ) |
| Diluted                                     |       | $         | (0.01      | )          | $          | 0.01      |       | $          | (0.02      | ) | $ | (0.03 | ) |

 
| **2006**                                    | ** ** | **First** | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** |
|---------------------------------------------|------------|-----------|------------|------------|------------|-----------|------------|------------|------------|
|                                        |       |      |       |       |       |      |       |       |       |
| Revenues                                    |       | $         | 1,498,453  |       | $          | 1,969,064 |       | $          | 1,705,140  |   | $ | 1,543,703 |   |
| Income (loss) from  operations              |       | $         | 119,566    |       | $          | (124,231  | )          | $          | (267,975   | ) | $ | (39,548 | ) |
| Earnings (loss) per share  from operations: |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | 0.01       |       | $          | (0.00     | )          | $          | (0.01      | ) | $ | (0.00 | ) |
| Diluted                                     |       | $         | 0.00       |       | $          | (0.00     | )          | $          | (0.01      | ) | $ | (0.00 | ) |
| Net income (loss)                           |       | $         | (73,077    | )          | $          | (249,540  | )          | $          | (489,224   | ) | $ | (199,965 | ) |
| Earnings (loss) per common  share:          |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | (0.00      | )          | $          | (0.01     | )          | $          | (0.02      | ) | $ | (0.01 | ) |
| Diluted                                     |       | $         | (0.00      | )          | $          | (0.01     | )          | $          | (0.02      | ) | $ | (0.01 | ) |

 

F-35

----

 
| **2005**                                    | ** ** | **First** | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** |
|---------------------------------------------|------------|-----------|------------|------------|------------|-----------|------------|------------|------------|
|                                        |       |      |       |       |       |      |       |       |       |
| Revenues                                    |       | $         | 1,588,204  |       | $          | 1,621,750 |       | $          | 2,824,093  |   | $ | 1,941,943 |   |
| Income (loss) from  operations              |       | $         | 240,023    |       | $          | 371,942   |       | $          | 1,357,935  |   | $ | 886,637 |   |
| Earnings (loss) per share  from operations: |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | 0.01       |       | $          | 0.02      |       | $          | 0.06       |   | $ | 0.04 |   |
| Diluted                                     |       | $         | 0.01       |       | $          | 0.02      |       | $          | 0.05       |   | $ | 0.04 |   |
| Net income (loss)                           |       | $         | 12,543     |       | $          | 177,035   |       | $          | 1,189,929  |   | $ | 731,567 |   |
| Earnings (loss) per common  share:          |       |      |       |       |       |      |       |       |       |
| Basic                                       |       | $         | 0.00       |       | $          | 0.01      |       | $          | 0.06       |   | $ | 0.03 |   |
| Diluted                                     |       | $         | 0.00       |       | $          | 0.01      |       | $          | 0.05       |   | $ | 0.03 |   |

 

The sum of the individual quarterly net income percommon share amounts may not agree with year-to-date net income per commonshare because each period’s computation is based on the weighted average numberof shares outstanding during that period.

 

F-36

----

 

**EXHIBITINDEX**

 
| **Exhibit   Number­**                      | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                                                                               |
|------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|      3.1  (2)               |       | Amended and Restated  Articles of Incorporation of GeoPetro Resources Company                                                                                                                                                                                                                                                                                                                                 |
|      3.2  (4)               |       | 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                                                                                                                                                                                                                                                                                                                                                           |
|    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                                                                                                                                                                                                                                                             |
|       10.11  (2)† |       | J. Chris Steinhauser  Employment Agreement, Dated June 19, 2000 and amendments dated  December 12, 2002 and January 1, 2005                                                                                                                                                                                                                                                                    |
|     10.12  (2)                   |       | Office Lease Agreement,  Dated effective March 1, 2004                                                                                                                                                                                                                                                                                                                                                   |
|     10.13  (2)                   |       | Promissory Note to  Pinehill Capital Inc., Dated January 31, 2006                                                                                                                                                                                                                                                                                                                                        |
|     10.14  (2)                   |       | Form of  Subscription Agreement for GeoPetro Resources Company stock executed by  various investors on various dates.                                                                                                                                                                                                                                                                                    |
|     10.15  (2)                   |       | Promissory note between  GeoPetro and G. Carter Sednaoui dated June 7, 2006                                                                                                                                                                                                                                                                                                                              |
|     10.16  (2)                   |       | Flow-Through Share  Agreement between GeoPetro Resources Company and GeoPetro Canada Ltd., Dated  March 30, 2006                                                                                                                                                                                                                                                                                         |
|     10.17  (2)                   |       | Form of  Flow-Through Share Agreement between GeoPetro Resources Company and various  investors, Dated March 30, 2006                                                                                                                                                                                                                                                                               |
|     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  (7)                   |       | Third Amendment to J.  Chris Steinhauser Employment Agreement dated December 18, 2007                                                                                                                                                                                                                                                                                                                         |
|     21.1    (1)        |       | List of Subsidiaries of  GeoPetro                                                                                                                                                                                                                                                                                                                                                                             |
|     23.3    (1)        |       | Consent of MHA  Petroleum Consultants                                                                                                                                                                                                                                                                                                                                                                         |
|   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.                                                                                                                                                                                                                                                                       |

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(1)                                 Filed herewith.

 

(2)                                 Filed as the identically numbered exhibitto the Registration Statement on Form S-1, (No. 333-135485), as filedwith the Securities and Exchange Commission on June 30, 2006, andincorporated herein by reference.

 

(3)                                 Filed as the identically numbered exhibitto the Registration Statement on Form S-1, (No. 333-135485), as filedwith the Securities and Exchange Commission on January 31, 2007, andincorporated herein by reference.

 

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(4)                                 Filed as the identically numbered exhibitto the Company’s Annual Report on Form 10-K as filed with the Securitiesand Exchange Commission on April 2, 2007, and incorporated herein byreference.

 

(5)                                 Filed as the identically numbered exhibitto the Registration Statement on Form S-1 (No. 333-135485), as filedwith the Securities and Exchange Commission on January 9, 2007, andincorporated herein by reference.

 

(6)                                 Filed as the identically numbered exhibitto the Registration Statement on Form S-1 (No. 333-146557), as filedwith the Securities and Exchange Commission on October 9, 2007, andincorporated herein by reference.

 

(7)                                 Filed as Exhibit 10.1 to the Company’sReport on Form 8-K, as filed with the Securities and Exchange Commission onDecember 21, 2007. Securities and Exchange Commission on December 21, 2002, andincorporated herein by reference.

 

†                                         Indicates a management or compensatoryplan or arrangement.

 

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