**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**WASHINGTON, D.C. 20549**

----

**Form10-K**

**ANNUALREPORT**

**PURSUANTTO SECTION 13 OR 15(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 endedDecember 31, 2006**

**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**

----

**GeoPetroResources Company**

**(Exact nameof 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)

**Securities registered pursuant toSection 12(b) of the Act:**

 

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

 

**Securities registered pursuant toSection 12(g) of the Act: None**

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

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes o No x

Indicate by check mark whether the registrant(1) has filed all reports required to be filed by Section 13 or 15(d)of the Securities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past 90 days. Yes o  No x

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein andwill not be contained, to the best of registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2 ofthe Exchange Act.

 

|                            |   |                 |   |                     |
|----------------------------|--------|----------------------|--------|--------------------------|
| Large  accelerated filer o |   | Accelerated  filer o |   | Non-accelerated  filer x |

 

Indicate by check mark whether the registrant is ashell company. Yes o No x

The aggregate market value of the registrant’s commonstock held by non-affiliates was approximately $124,733,634 based on theclosing sale price of $4.95 per share as reported by the American StockExchange on March 28, 2007.

The number of shares of the registrant’s common stockoutstanding on March 30, 2007 was 29,359,718.

**DOCUMENTS INCORPORATED BY REFERENCE**

Portions of the registrant’s Proxy Statement relatingto the 2007 Annual Meeting of Shareholders to be filed on or before April 30,2007 are incorporated by reference into Part III of this Form 10-K.

 

 

----

**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  Executive Officers of the Registrant                              |       |       |
| **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 and Executive Officers of the Registrant                                                                     |       |       |
| 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                                                                         |       |       |
| 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-Looking Statements**

*This Annual Report on Form 10-Kcontains forward-looking statements within the meaning of Section 27A ofthe Securities Act and Section 21E of the Exchange Act 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 deemedforward-looking statements, such as those statements that address activities,events or developments that we expect, believe or anticipate will or may occurin the future. These statements are based on certain assumptions and analysesmade by us in light of our experience and perception of historical trends,current conditions, expected future developments and other factors we believeare appropriate in the circumstances. Such forward looking statements aresubject to change based on factors beyond our control. Certain factors that mayaffect our financial condition and results of operations are discussed in Item1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures AboutMarket Risk” of this Annual Report on Form 10-K, and may be discussed from timeto time in our reports filed with the Securities and Exchange Commission subsequentto this report.  We assume no obligation,nor do we intend, to update these forward-looking statements, unless requiredby law. Unless the context requires otherwise, references in this Annual Reporton Form 10-K to “GeoPetro,” “we,” “us” and “our” refer to GeoPetro ResourcesCompany and its consolidated subsidiaries.*

 

----

**PART I**

**Item 1. *Business***

We were incorporated in the State of Wyoming inAugust 1994 under the name GeoPetro Company as an oil and gas exploration,development drilling and production company. In June 1996, we merged withour wholly-owned subsidiary, GeoPetro Resources Subsidiary Company, aCalifornia corporation, and the resulting merged company is incorporated in thestate of California under the California General Corporation Law under the nameGeoPetro Resources Company.

Our principal and registered office is located at OneMaritime Plaza, Suite 700, San Francisco, California, USA 94111.

**IntercorporateRelationships**

We hold 100% of the shares of Redwood Energy Company,a Texas corporation, “**Redwood.**”  Redwood is the general partner of, and holdsa 5% interest in, Redwood Energy Production, L.P., “**Redwood LP**”, a Texas limitedpartnership. We are the sole limited partner of Redwood LP and own theremaining 95% partnership interest in Redwood LP.

In addition, we hold a 12% interest in Continental-GeoPetro(Bengara II) Ltd., “**C-G Bengara**”which is a British Virgin Islands company and a 50% interest inCG Xploration Inc., “**CG Xploration**”,which is a Delaware corporation.

We also hold 100% of the shares of GeoPetroCanada Ltd., “**GeoPetro Canada**”,an Alberta company, and 100% of the shares of GeoPetro Alaska LLC “**GeoPetro Alaska**”, an Alaska limitedliability company.

**GENERALDEVELOPMENT OF THE BUSINESS**

During the past five years, we have conductedleasehold acquisition, exploration and drilling activities on our NorthAmerican, Australian and Indonesian prospects. These projects currentlyencompass approximately 1.56 million gross (396,080 net) acres,consisting of mineral leases, production sharing contract and explorationpermits that give us the right to explore for, develop and produce oil andnatural gas. Most of these properties are in the exploration, appraisal ordevelopment drilling phase and have not begun to produce revenue from the saleof oil and natural gas. Excluding minor interest and dividend income, our onlycash 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, we acquired working interestsin oil and natural gas leases in the Madisonville Field in Madison County,Texas, including interests in the Rodessa Formation. Also included in theacquisition was the Magness Well, an existing well that had been drilled, casedand production tested in the Rodessa Formation. In October 2001, were-completed and tested the Magness Well over a 12-day period. InOctober 2002, we drilled, completed and successfully tested an injectionwell to dispose of waste products resulting from the treating process for gasproduced from the Rodessa Formation. The Madisonville Field gas treatment plantand associated pipelines, which were built specifically for this project, wereplaced into service in May 2003, and the Magness Well began production inlate May 2003. Since 2003, substantially all of our revenue has beengenerated from natural gas sales derived from the Madisonville Field. Gas salesfrom the Madisonville Field accounted for approximately 99% of our consolidatedrevenue during the year ended December 31, 2006.  The Madisonville Project is expected to beour primary source of revenue in 2007. The first development well in theMadisonville Field, the Fannin Well, was drilled 

2

----

in 2004 and was tested atrates of up to 25.7 MMcf/d. In 2006, we drilled the Wilson and Mitchellwells. Presently, the Fannin and Magness wells are producing at a combinedrestricted rate of approximately 16.5 MMcf/d while the Wilson and Mitchellwells are shut-in awaiting a planned expansion of the gas treatment plant. Weown a 100% working interest in the four wells. Historically, our wells have been production constrained by the gastreatment plant at the Madisonville Field, which presently has a designedtreating capacity limit of approximately 18,000 Mcf per day. We have enteredinto an agreement with the plant owner, MGP, an unaffiliated third party, whichprovides, among other things, that MGP will expand the treating capacity of theplant from 18,000 to 68,000 Mcf per day to treat additional volumes from ourproducing wells. We expect the expanded capacity of the treatment plant to beavailable in the second quarter of 2007; however, there is no guaranteethat the expansion will be completed within that time period. We expect themajority of our capital expenditures in 2007 to be the costs of drilling andcompleting wells in the Madisonville Field.

As of March 30, 2007 we have 29,359,718 shares ofcommon stock outstanding as a result of raising approximately $46 millionof equity, net of offering costs, by way of private placements and a publicoffering in Canada. These funds have been used primarily to acquire, exploreand develop our oil and natural gas prospects.

Our common stock commenced trading under the symbolGPR on the American Stock Exchange on February 15, 2007.  Our common stock is also listed on theToronto Stock Exchange under the symbol GEP.S.

On March 30, 2006, we completed an initial publicoffering in Canada, which consisted of 3,730,021 shares of common stock at anissue price of $3.50 per share and 519,500 shares of common stock issued on a “flow-through”basis under the *Income Tax Act*(Canada) at an issue price of $3.85 per share for aggregate gross proceeds of$15,055,149. We have used the net proceeds of the offering primarily to funddevelopment drilling of proven and probable natural gas reserves associatedwith the Madisonville Project.

**Growth Strategy**

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:

·       identify and pursuepotential projects which individually have the potential to be “company makers”which we define as projects which could generate a minimum unrisked net presentvalue of $50 million net to our interest using a 10% discount factor;

·       perform geological,engineering and geophysical evaluations;

·       gain control of keyacreage;

·       generate high qualitydrillable exploration and development drilling prospects;

·       retain a large workinginterest in those projects which involve low risk appraisal or developmentdrilling, exploitation or appraisal of proven, probable and possible reserves;and

·       minimize early investmentand exploration risk in higher risk exploratory prospects through farmouts toother oil and natural gas companies and maintain meaningful interests with a “carry”through the exploration phase.

3

----

**Risks AssociatedWith Foreign Operations**

Our business activities in Indonesia, Australia,Canada and the United States are subject to political and economic risks,including: loss of revenue, property and equipment as a result of unforeseenevents like expropriation, nationalization, war, terrorist attacks andinsurrection; 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,and numerous other factors. While we expect these risks are greater inIndonesia, especially political risk, any one or more of such political oreconomic conditions could change in the United States, Canada or Australiato our detriment. For a related discussion of the risks attendant with foreignoperations, see “Risk Factors.”

**FinancialInformation About Geographic Areas**

Please see the notes to the financial statements forinformation concerning oil and gas properties located in the United States andforeign countries.

**Regulations**

Domesticexploration for, and production and sale of, oil and gas are extensivelyregulated at both the federal and state levels. Our business is and will bedirectly or indirectly affected by numerous governmental laws and regulationsapplicable to the energy industry, including:

·       Federal environmental lawsand regulations

·       State environmental lawsand regulations

·       Local environmental lawsand regulations

·       Conservation laws andregulations

·       Tax and other laws andregulations pertaining to the energy industry

Legislation, rules and regulations affecting theoil and gas industry are under constant review for amendment or expansion,frequently increasing the regulatory burden. Any changes in the existinglegislation, rules or regulations could adversely affect our business. Theregulatory burdens are often costly to comply with and carry substantialpenalties for failure to comply.

As of March 30, 2007, we have re-completed an existingwell and drilled three additional production wells and an injection well in theMadisonville Project as operator. In addition, we may drill oil, gas anddisposal wells in the future as the operator and will be required to obtainlocal government and other permits to drill such wells. There can be noassurance that such permits will be available on a timely basis or at all.Texas and other states have statutes or regulations pertaining to conservationmatters which, among other matters, regulate the unitization or pooling of gasproperties and the spacing, plugging and abandonment of such wells and setlimits on the maximum rates of natural gas 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:

·       Require the acquisition ofpermits

·       Restrict the type,quantities and concentration of various substances that can be discharged intothe environment

4

----

·       Limit or prohibit drillingand other activities on wetlands and other designated, protected areas

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

·       Impose criminal or civilliabilities for pollution resulting from oil and natural gas operations

We expect that with the increase in our exploratoryand development drilling activities, the impact of environmental laws andregulations on our business and operations will also increase. We may berequired in the future to make substantial outlays of money to comply withenvironmental laws and regulations. Additional changes in operating proceduresand expenditures to comply with future environmental laws cannot be predicted.

Other than our U.S. projects, we do not operate oiland gas properties in which we own an interest. In those instances, we are notin the position to exert direct control over compliance with most of therules and regulations discussed above. We are substantially dependent onthe operators of our non-operated oil and gas properties to monitor, administerand oversee such compliance. The failure of the operator to comply with suchrules and regulations could result in substantial liabilities to us.

As the operator of the Madisonville Project, amongother various environmental laws and regulations, we will be subject to theU.S. Comprehensive Environmental 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. Under CERCLA, one owner, lessee or other party,having responsibility for and an interest in a site requiring cleanup may,under certain circumstances, be required to bear a disproportionate share ofliability for the cost of such cleanup if payments cannot be obtained fromother responsible parties. The Resource Conservation and Recovery Act (“RCRA”)and comparable rules adopted by Texas and other states regulate thegeneration, management and disposal of hazardous oil and gas waste.

The Texas Railroad Commission has been delegated theresponsibility and authority to regulate and prevent pollution from oil and gasoperations, including the prevention of pollution of surface or subsurfacewater resulting from the drilling of oil and gas wells and the production ofoil and gas. In addition to regulating the generation, management and disposalof hazardous oil and gas waste, the Texas Railroad Commission has beendelegated authority to regulate underground hydrocarbon storage, saltwaterdisposal pits and injection wells.

The drilling of oil and gas wells in Texas requiresoperators to obtain drilling permits, file an organization report and aperformance bond or other form of financial security, such as a letter ofcredit, and obtain a permit to maintain pits to store and dispose of drillingfluids, saltwater and waste as well as other types of pits for other purposes.The issuance of such permits is conditioned upon the Texas Railroad Commission’sdetermination that these pits will not result in waste or pollution of surfaceor subsurface water.

Other states in which we have an interest in oil andgas properties may impose similar or more stringent regulations than imposedunder CERCLA or RCRA.

In re-completingthe existing well on the Madisonville Project, we were required to drill a wellfor injection or disposal of produced waste gas from wells. Injection wells aresubject to regulation under the Safe Drinking Water Act (“SDWA”) and theregulations and procedures which have been adopted by the EnvironmentalProtection Agency (“EPA”) under that Act. Generally, enforcement proceduresunder the SDWA are administered by the EPA unless such authority has beendelegated by the EPA to a state which has primary enforcement responsibilitybased on the EPA’s determination that the state has adopted drinking waterregulations no less stringent than the 

5

----

nationalprimary 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:

·       permit issued by the EPA ora state having primary enforcement responsibility, or

·       rule pursuant to anunderground injection control program established by a state or the EPA.

The regulatory burden on the natural gas and oilindustry increases our cost of doing business and affects our financialcondition. Future developments, such as stricter requirements of environmentalor health and safety laws and regulations affecting our business or morestringent interpretations of, or enforcement policies with respect to, suchlaws and regulations, could adversely affect us. To meet changing permittingand operational standards, we may be required, over time, to make site oroperational modifications at our facilities, some of which might be significantand could involve substantial expenditures. There can be no assurance thatmaterial costs or liabilities will not arise from these or additionalenvironmental matters that may be discovered or otherwise may arise from futurerequirements of law.

**OverseasRegulations**

We own working interests in oil and gas prospectslocated in Australia and Indonesia. We have farmed out our interest in some ofthese prospects to third parties, and other parties are operators of theseproperties. In exploring for, drilling and developing such properties, theseoperators will be required to comply with the environmental, conservation, taxand other laws and regulations of Australia and Indonesia. The Native Title Actof 1993, an Australian law, may affect our ability to gain access toprospective exploration areas or obtain production title on our Australianproperties. In addition, if Native Title claims are filed in the future, we maybe required to make payments to settle such claims. To date we have farmed outour interest in 20 properties since our inception. This has impacted ourbusiness from a financial point of view. In some instances, we have receivedcash consideration pursuant to the terms of a farmout which we typically recordas a reduction of capitalized oil and gas properties. Often, the terms of thefarmouts we negotiate require the third party farmee to expend a certain amounttoward the exploration and/or development drilling of the property in order toearn an interest in the property. This lessens the demand on our own capitalresources to perform the exploration and/or development drilling of the property.Conversely, when and if the property produces revenue, it also reduces ourshare of such revenue to the extent of the interest farmed out.

**Technology**

We participate in projects utilizing economicallyfeasible exploration technology in our exploration and development drillingactivities to reduce risks, lower costs, and more efficiently produce oil andgas. We believe that the availability of cost effective 2-D and 3-Dseismic data makes its use in exploration and development drilling activitiesattractive from a risk management perspective in certain areas.

Briefly, through the use of a seismograph, a seismicsurvey sends pulses of sound from the surface down into the earth, and recordsthe echoes reflected back to the surface. By calculating the speed at whichsound travels through the various layers of rock, it is possible to estimatethe depth to the reflecting surface. It then becomes possible to infer thestructure of rock deep below the earth’s surface. We evaluate substantially allof our exploratory prospects using 2-D seismic data. In addition, we ownapproximately 12 square miles of 3-D seismic data covering ourleasehold and adjacent lands in the Madisonville Project.

6

----

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 recognizesignificant geological features due to errors in interpretation, processinglimitations, the presence of certain geological environments that are out ofour control or other factors; and

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

·       the use of this technologymay increase our finding cost over that if it is not used.

**Principal Products**

Our principal products are the production of naturalgas and crude oil from properties in which we own an interest. Since ourinception, we have realized only limited production of natural gas and crudeoil from the properties in which we own an interest. We have working interestsin various undeveloped oil and gas properties. See****“Properties”****for a general description of these properties.

During the last three fiscal years, 100% of ourrevenues have been derived from the sale of natural gas.  Substantially all of our natural gas sales,approximately 99%, have been generated by two producing wells, theMagness #1 and Fannin #1 wells, located in the Madisonville Field in EastTexas. Natural gas produced by the Magness #1 well is sold at the wellheadwhere it is delivered to a gathering pipeline and transported to a nearby gastreatment plant where it is treated to remove impurities. The gas is thentransported nine miles to one of two common carrier pipelines from which pointit is delivered to the greater Dallas, Texas area. The price received for thenatural gas is the Houston Ship Channel price index less certain adjustmentsfor the quality of the gas delivered. The adjustments for the quality of gasdelivered at the wellsite as well as the gathering and transportation costspresently amount to approximately $1.70 per Mcf of untreated gas delivered atthe wellsite.

For financial information regarding our businessactivities by segment, please see our Financial Statements beginning onpage F-1 of this report. Substantially all of our revenue isproduced from natural gas sales in the Madisonville Field located in EastTexas.

**Reserves**

The volume of production from oil and natural gasproperties generally declines as reserves are depleted, with the rate of declinedepending on reservoir characteristics. Our proved reserves will decline asreserves are produced from our properties unless we are able to acquire ordevelop new reserves.

**Acquisition ofProducing Properties**

We may supplement our exploration efforts withacquisitions of producing oil and gas properties. We may seek to acquireproducing properties that are underperforming relative to their potential.

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

Permits and licenses are important to our operations,since they allow the search for the extraction of any oil, gas and mineralsdiscovered on the areas covered. See****“Properties”for a general description of the permits and licenses under which we operate.Provided we establish a commercial discovery thereon, the Bengara PSC inIndonesia grants us the right to produce oil and gas from the PSC area until2027. In the event of commercial discovery and resulting production, ourpermits in Australia grant us the right to produce oil and gas from the permitareas until 2032.

7

----

**Renegotiation ofProfits or Termination of Contracts**

Our property inIndosnesia is subject to the terms of a production sharing contract known asthe “Bengara II PSC.” The Bengara II PSC is a “standard terms” productionsharing contract employed by BP Migas, the applicable governing authority,  for all oil and natural gas concessions inIndonesia.  The Bengara II PSC providesfor early termination and relinquishments of the contract area under certainconditions.  These provisions arediscussed in “Properties — *Indonesia - Terms ofParticipation in the Bengara Block.”*See also “Risk Factors.”

**Seasonality ofBusiness**

Our business is not seasonal.

**Working CapitalItems**

The majority of our current assets are in the form ofcash and deposits in trust received from the sale of natural gas from ourMadisonville Project in Texas and from the sale of common stock in privateplacements. We are required to use this cash to pay for the cost of ouroperations and activities. See further, “Management’s Discussion and Analysisof Financial Condition and Results of Operations.”

**Customers**

Substantially all of our revenues to date have beenderived from sales by MGP to two customers, Atmos Pipeline-Texas, and ETC KatyPipeline, Ltd., of natural gas produced from our Madisonville Project in Texas.We have not committed any forward sales ofour natural gas. We contract to sell the gas with spot-market basedcontracts that vary with market forces on a monthly basis. No other customer accounts for in excessof 10% of our revenues.

**Competition**

The natural gas and oil industry is intenselycompetitive and speculative in all of its phases. We encounter competition fromother natural gas and oil companies in all areas of our operations. In seekingsuitable natural gas and oil properties for acquisition, we compete with othercompanies operating in our areas of interest, including large natural gas andoil companies and other independent operators, which have greater financialresources and in many instances, have been engaged in the exploration andproduction business for a much longer time than we have. Many of ourcompetitors also have substantially larger operating staffs than we do. Many ofthese competitors not only explore for and produce natural gas and oil but alsomarket natural gas and oil and other products on a regional, national orworldwide 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 natural gas production arecontrolled by market forces. However, competition in the natural gas and oilexploration industry also exists in the form of competition to acquire leasesand obtain favorable transportation prices. We are relatively small and mayhave difficulty acquiring additional acreage and/or projects and may have difficultyarranging for the 

8

----

transportation of ourproduction. We also face competition in obtaining natural gas and oil drillingrigs and in sourcing the manpower to run them and provide related services.

**Employees**

Currently, we have 10 employees, all of whom are full time. We are not a party to anycollective bargaining agreements and we have not experienced any strikes orwork stoppages. We consider our relations with our employees to be good. We usethe services of independent consultants and contractors to perform variousprofessional services, including reservoir engineering, land, legal,environmental and tax services. On those properties where we are not theoperator, we rely on outside operators to drill, produce and market our naturalgas and oil.

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

In addition to risks and uncertainties in the ordinarycourse of business that are common to all businesses, important factors thatare specific to our industry and our company could materially impact our futureperformance and results of operations. We have provided below a list of theserisk factors that should be reviewed when considering our securities. These arenot all the risks we face and other factors currently considered immaterial orunknown to us may impact our future operations.

**Risks Related toOur Business**

***As ofDecember 31, 2006 we have capitalized costs totaling $48.2 million as evaluatedand unevaluated oil, and gas properties whereas we have generated revenues ofonly $22,970,070 since January 1, 2003.***

Since inception, our activities have been primarilyrelated to acquiring and exploring leasehold interests in oil and natural gasproperties in Texas, California, Alaska, Alberta, Indonesia and Australia. Weincur substantial acquisition and exploration costs and overhead expenses inour operations, and until 2003, excluding minor interest and dividend income,our only significant cash inflows were the recovery of capital invested inprojects through sale or other divestitures of interests in oil and gasprospects to industry partners. As a result, we have sustained an accumulateddeficit through December 31, 2006 of $10,393,985. Our production activitiescommenced in May 2003. Since May 2003, over 90% of our revenue hasbeen generated from natural gas sales derived from the Magness #1 well in theMadisonville Field in Texas. It is possible that in the future we will beunable to continue to generate revenues from our sales of natural gas from theMagness #1 well because our proved reserves decline as reserves are producedfrom the Magness #1 well. The drilling of exploratory oil and natural gas wellsis highly speculative and often unproductive. Our participation in futuredrilling activities to explore, develop and exploit the properties in which wehave an interest, or in which we may acquire interests, may be unsuccessful,may fail to generate positive cash flow, and may not enable us to maintainprofitability in the future.

***Approximately99% of our current revenues are generated by our interest in the Madisonville Project.Delays or interruptions of the Madisonville Project natural gas drilling andproduction operations including, but not limited to, events beyond our controlor the failure of third parties on which we rely to provide key services, couldnegatively impact our revenues.***

Approximately 99% of our oil and natural gas revenuesfor the year ended December 31, 2006 were derived from the MadisonvilleProject. In connection with that project, we have contracted with third partiesto provide key services, including:

9

----

(a)                                  MadisonvilleGas Processing, LP (“**MGP**”), whichowns and operates gathering pipelines and a dedicated natural gas treatmentplant which we utilize to treat impurities in the Madisonville Project naturalgas; and

(b)                                 Gateway,which operates a sales pipeline for such natural gas.

The failure of MGPor Gateway to perform their contractual obligations to us could impose delaysor interruptions 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 forcemajeure, such as an act of God, act of a public enemy, war, blockade, publicriot, lightning, fire, storm, flood, explosion and any other causes whether ofthe kind enumerated or otherwise not reasonably within the control of MGP,Gateway or our company.

·       subsurface conditions orformations encountered during the drilling of wells, whether natural or mechanical,including but not limited to blowout, igneous rock, salt, saltwater flow, lossof circulation, loss of hole, abnormal pressures, or any other impenetrablesubstance or adverse condition, which renders further drilling of a wellimpossible or impractical.

·       the inability to secure rawmaterials or equipment,

·       transportation accidents,and

·       labor disputes andequipment failures.

***In excess of 90% of our revenues to date have beenderived from sales by MGP to two customers. The loss of one or both of thesecustomers could have a material adverse impact on our oil and gas revenues.***

Approximately 99% of our oil and natural gas revenuesfor the year ended December 31, 2006 were derived from the MadisonvilleProject. During 2005, all of these revenues were derived from the sale of gasby MGP and Hanover Compression Limited Partnership (“**Hanover**”)to one customer, Atmos Pipeline-Texas. During 2006 and the current year,approximately 99% of our revenues to date have been derived from sales by MGPto two customers, Atmos Pipeline-Texas, and ETC Katy Pipeline, Ltd. The loss ofone of these customers could impact the price we receive for our gas sold dueto lessened competition. The loss of both customers could result in a totalloss of our revenue.

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

The volume of production from oil and natural gasproperties generally declines as reserves are depleted, with the rate ofdecline depending on reservoir characteristics. Our proved reserves willdecline as reserves are produced from our properties unless we are able toacquire or develop new reserves. The business of exploring for, developing oracquiring reserves is capital intensive. For example, as of December 31, 2006we have capitalized costs totaling $48.2 million as evaluated and unevaluatedoil and gas properties. To the extent cash flow from operations is reduced andexternal sources of capital become limited or unavailable, our ability to makethe necessary capital investment to maintain or expand our asset base of oiland natural gas reserves will be impaired. Even if we are able to raise capitalto develop or acquire additional properties, no assurance can be given that ourfuture exploitation and development drilling activities will result in thediscovery of any reserves.

 

10

----

***Ourexploration and development drilling activities may not be commerciallysuccessful. The drilling of exploratory oil and natural gas wells is expensive,highly speculative and often unproductive.***

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

The cost ofdrilling, completing and operating wells is often uncertain, and drillingoperations may be curtailed, delayed or cancelled as a result of a variety offactors, including:

·       unexpected drillingconditions, pressure or irregularities in formations;

·       equipment failures oraccidents, adverse weather conditions;

·       compliance withgovernmental requirements; and

·       shortages or delays in theavailability of drilling rigs and the delivery of equipment.

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

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

Reservoir engineering, geophysics and geology are notexact sciences and the results of studies and tests used to make suchevaluations are sometimes inconclusive or subject to varying interpretations.As such, there is no certain way to know in advance whether any of ourprospects will yield oil and natural gas in commercial quantities. Further, itis possible that we will participate in the drilling of more dry holes thanproductive wells or that all or substantially all of the wells drilled will be dryholes. The drilling of dry holes on prospects in which we have an interestcould adversely affect their values and our decision to undertake furtherexploration and development drilling of such prospects. It is not certain orpredictable whether, and no assurance can be made that, the wells drilled onthe properties in which we have an interest will be productive or, ifproductive, that we will recover all or any part of our investment in theproperties. In sum, our participation in future drilling activities may not besuccessful and, if unsuccessful, such failure will negatively impact ourrevenues and have a material adverse effect on our results of operations andfinancial condition. Our oil and natural gas revenues were $6,716,360 millionfor the year ended December 31, 2006. Future revenues could decline from thoselevels if our future drilling efforts are not successful. Furthermore, as ofDecember 31, 2006 we have capitalized costs totaling $48.2 million as evaluatedand unevaluated oil and gas properties. Should our future drilling activitiesbe unsuccessful, we may then be required to record an impairment charge equalto a portion of, or all, of the capitalized costs resulting in an immediateadverse impact on our results of operations and financial position.

***Our business may be harmed by failures of third partyoperators on which we rely.***

Our ability to manage and mitigate the various risksassociated with certain of our exploration and operations in Alberta, Canada,Indonesia and Australia is limited since we rely on third parties to operateour projects. We are a non-operating interest owner in our Canadian, Indonesianand Australian properties. With respect to our interests outside of theUnited States, we have entered into joint operating agreements with thirdparty operators for the conduct and supervision of 

11

----

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 fromour Indonesian property is diminished by the terms of our production sharingcontract in the Bengara Block.***

On September 29, 2006, we sold 70% of our interest inC-G Bengara to CNPC (Hong Kong) Limited, thus reducing our interest in C-GBengara from 40% to 12%. C-G Bengara is subject to a production sharingcontract, which means generally that C-G Bengara is entitled to receive, fromproduction proceeds, 100% of expenditures in the block as “cost recovery.” Oncethese costs 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” in this report for more informationconcerning the production sharing 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, there has been a general shortageof drilling rigs, equipment, supplies and oilfield services in North America,Australia and Indonesia, which may intensify with current increased industryactivity. In addition, the costs and delivery times of rigs, equipment andsupplies have risen. There can be no assurance that sufficient drilling andcompletion equipment, services and supplies will be available when needed.Shortages could delay our proposed exploration, development drilling, and salesactivities, which could have a material adverse effect on our results ofoperations. Our oil and natural gas revenues were $6.7 million for the yearended December 31, 2006. Future revenues could decline from those levels if weexperience delays in our proposed exploration, development drilling, and salesactivities. The demand for, and wage rates of, qualified rig crews have risenin the drilling industry due to the increasing number of active rigs inservice. If the demand for qualified rig crews continues to rise in thedrilling industry, then the oil and gas industry may experience shortages ofqualified personnel to operate drilling rigs. This could delay our drillingoperations and adversely affect our financial condition and results ofoperations.

***Ourworking interest in properties, and our ability to realize any profits fromsuch properties, will be diminished to the extent that we enter into farmoutarrangements with unaffiliated third parties.***

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

We recently sold 70% of our working interest in theBengara Block to an unaffiliated third party. The sale significantly diminishedour interest and thus our ability to realize future profits in the BengaraBlock.

12

----

***Competition withother oil and natural gas exploration and development drilling companies forviable oil and natural gas properties may limit our success.***

It is likely thatin seeking future property acquisitions, we will compete with companies whichhave substantially greater financial and management resources. Our competitioncomes primarily from three sources:

(a)                                  thosecompetitors that are seeking oil and gas fields for expansion, furtherdrilling, 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 areinherently imprecise. Any material inaccuracies in these reserve estimates orunderlying assumptions will affect materially the quantities and present valueof our reserves.***

Estimates of proved oil and natural gas reserves andthe future net cash flows attributable to those reserves are prepared byindependent petroleum engineers and geologists. There are numerousuncertainties inherent in estimating quantities of proved oil and natural gasreserves and cash flows attributable to such reserves, including factors beyondour control and that of our engineers. Reserve engineering is a subjectiveprocess of estimating underground accumulations of oil and natural gas that cannotbe measured in an exact manner. Different reserve engineers may make differentestimates of reserves and cash flows based on the same available data. Theaccuracy of an estimate of quantities of reserves, or of cash flows attributableto such reserves, is a function of the available data, assumptions regardingfuture oil and natural gas prices and expenditures for future developmentdrilling and exploration activities, and of engineering and geologicalinterpretation and judgment. Additionally, reserves and future cash flows maybe subject to material downward or upward revisions, based upon productionhistory, development drilling and exploration activities and prices of oil andnatural gas. Actual future production, revenue, taxes, development drillingexpenditures, operating expenses, underlying information, quantities ofrecoverable reserves and the value of cash flows from such reserves may varysignificantly from the assumptions and underlying information set forth herein.

***Competitivepressures may force us to implement new technologies at substantial cost andour limited financial resources may limit our ability to implement suchtechnologies at the same rate as our competitors.***

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

13

----

***We will requireadditional capital to fund our future activities. Our ability to pursue ourbusiness plan may be restricted by our access to additional financing.***

Until such time as the properties in which we owninterests are generating sufficient cash flow to fund planned capitalexpenditures, we will be required to raise additional capital through theissuance of additional securities or otherwise sell or farm out interests inour oil and natural gas properties to third parties. If and when the propertiesin which we own interests become productive and have adequate reserves, we mayborrow funds to finance our future oil and natural gas operations andexploratory and development drilling activities. We may not be able to raiseadditional funds in the future from any source or, if such additional funds aremade available to us, we may not be able to obtain such additional financing onterms acceptable to us. To the extent such funds are not available from any ofthose sources, our operations and activities will be limited to thoseoperations and activities we can afford with the funds then available to us. Wehave committed to a three well drilling program in our Madisonville project tofacilitate the expansion of the gas treatment plant. The commitment is notdiscretionary. While we have fulfilled the commitment to drill the first twowells of the three well commitment, we are further required to commence thedrilling of a third well sufficient to test the Smackover Formation (estimatedto be encountered at approximately 18,000 feet) on or before September 30,2008. This well is expected to cost approximately $10 million to drill andcomplete.  We have granted MGP a securityinterest in the Madisonville Field properties to secure the three wellcommitment. Subject to events of force majeure, and the availability ofsuitable drilling rigs, well services, and equipment, our failure to drill thiswell could result in the loss of our interest in the Madisonville Project. Ourlarger competitors, by reason of their size and relative financial strength,may be more easily able to access capital markets than us.

***Thevolatility in crude oil and natural gas prices could adversely affect ourfinancial results and ability to raise additional capital.***

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

Our current operations are particularly exposed tovolatility in natural gas prices because a portion of the fees we pay toprocess natural gas at the Madisonville gas treatment plant is fixed. The saleprice of natural gas must be above a minimum price of approximately $3.00 perMcf at the present time before we earn any net revenues from the sale ofnatural gas.

***We are subjectto a number of operational risks beyond our control against which we may nothave, or be able to obtain insurance.***

14

----

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 equipment failures that may result in damage to ordestruction of wells, producing formations, production facilities andequipment;

·       personal injuries or deathdue to accidents, human error or acts of God;

·       unavailability of materialsand equipment to drill and complete or re-complete wells; unfavorable weatherconditions; engineering and construction delays;

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

·       accidental leakage of toxicor hazardous materials, such as petroleum liquids or drilling fluids into theenvironment, remediation and clean-up costs; and

·       political instability andcivil unrest, insurrections or disruptions in foreign countries in which someof our interests are located.

If one or more of these events occurs, we could incursubstantial liabilities to third parties or governmental entities, the paymentof which could have a material adverse effect on our financial condition andresults of operations, or we could lose properties in which we have investedsignificant sums (totaling $48.2 million) which are capitalized as evaluatedand unevaluated oil and gas properties as of December 31, 2006.

***A loss not covered by insurance could result insubstantial expenses to us.***

We do not insure fully against all business riskseither because such insurance is not available or because premium costs areprohibitive. This is a common practice in the oil and gas industry. However, aloss not fully covered by insurance could result in expenses to us and couldhave a material adverse effect on our financial position and results ofoperations. Uninsured losses in excess of $1.0 million would be materiallyadverse.

***We are subject to extensive government regulationsthat can change from time to time, compliance with which are costly and couldnegatively impact our production, operations and financial results****.*

The oil and gas industry is subject to extensivegovernment regulations in the countries in which we operate. Matters subject toregulation include discharge permits for drilling operations, drilling bonds,reports concerning operations, unitization and pooling of properties andtaxation. Historically, our costs of complying with these regulations have notexceeded $100,000 per year. From time to time, regulatory agencies have imposedprice controls and limitations on production by restricting the rate of flow ofoil and natural gas wells below actual production capacity in order to conservesupplies of oil and natural gas. We are also subject to changing and extensivetax laws, the effects of which cannot be predicted. Legal requirements arefrequently changed and subject to interpretation, and we are unable to predictthe ultimate cost of compliance with these requirements or their effects on ouroperations. Future laws, or existing laws or regulations, as currentlyinterpreted or reinterpreted or changed in the future, could result inincreased operating costs, fines and liabilities, in amounts which are unknownat this time, any of which could materially adversely affect our results ofoperations and financial condition.

15

----

***Ourindustry is subject to extensive environmental regulation that may limit ouroperations and negatively impact our production.***

Extensive national, state, provincial and localenvironmental laws and regulations in the United States and foreignjurisdictions affect nearly all of our operations. These laws and regulationsset various standards regulating certain aspects of health and environmentalquality, provide for penalties and other liabilities for the violation of suchstandards and establish in certain circumstances obligations to remediatecurrent and former facilities and locations where operations are or wereconducted. In addition, special provisions may be appropriate or required inenvironmentally sensitive areas of operation.

Environmentallegislation may require that we, among other things:

·       acquire permits beforecommencing drilling;

·       restrict spills, releasesor emissions of various substances produced in association with our operations;

·       limit or prohibit drillingactivities on protected areas such as wetlands or wilderness areas;

·       take reclamation measuresto prevent pollution from former operations;

·       take remedial measures tomitigate pollution from former operations, such as plugging abandoned wells andremediating contaminated soil and groundwater;

·       take remedial measures withrespect to property designated as a contaminated site.

The cost of any of these actions is presently unknownbut is likely to be significant.

***Compliance withexisting or future environmental legislation is unknown but could besubstantial.***

Compliance with such legislation can requiresignificant expenditures and a breach may result in the imposition of fines andpenalties. The discharge of oil, natural gas or other pollutants into the air,soil or water may give rise to liabilities to governments and third parties andmay require us to incur substantial costs to remedy such discharge. Under theselaws and regulations, we could be liable for personal injury, clean-up costsand other environmental and property damages, as well as administrative, civiland criminal penalties. We could be required to cease production on propertiesif environmental damage occurs. Environmental legislation is evolving in amanner expected to result in stricter standards and enforcement, larger finesand liability and potentially increased capital expenditures and operatingcosts. Changes in, or enforcement of, environmental laws may result in a curtailmentof our production activities, or a material increase in the costs ofproduction, development drilling or exploration, any of which could have amaterial adverse effect on our financial condition and results of operations orprospects. We are not presently aware of any environmental liabilities or ableto predict the ultimate cost of liabilities not yet recognized. We haverecorded an asset retirement obligation in connection with the estimated futurecosts to plug certain wells in our Madisonville Project in Texas upon abandonmenttotaling approximately $48,842 as of December 31, 2006.

***Our Australian operations are subject to unique risksrelating to Aboriginal land claims and government licenses.***

Our Australian operations could be affected by nativetitle claims by Aboriginal groups. Australian law recognizes that in someinstances native title, that is the laws and customs of the Aboriginalinhabitants, has survived European settlement. Native title will only surviveif it has not been extinguished. Native title may be extinguished by an Act ofGovernment, such as the creation 

16

----

of a title that isinconsistent with native title. This may include a grant of the right toexclusive possession through freehold title or lease. Native title may also beextinguished if the connection between the land and the group of Aboriginalpeople claiming native title has been lost. Each authority to prospect, andlicense in areas in which we desire to engage in exploration or productionactivities must be examined individually in order to determine the validity ofany native title claim. We may be required to negotiate with any Aborigines whocan make a valid claim to having ancestral ties to the areas in which we desireto engage in exploration or production activities. These negotiations couldboth delay the timing of our exploration or production activities, as well asadd an additional layer of cost or a requirement to share revenues if anyAboriginal claimants are proved to have native title rights in our explorationareas.

***Ournatural gas deliveries to the Madisonville gas treatment plant may be affectedby the demands of Crimson Exploration, Inc. (“Crimson”) and other third partiesfor access to the plant, and as a result, our access to the plant could be restricted.***

We are dependent upon the Madisonville gas treatmentplant to treat our natural gas. We have committed all natural gas productionfrom our interest in the Madisonville Project to MGP, which has in turncommitted to provide treatment capacity of up to 68 MMcf/d for our natural gas.Third parties may seek access to the gas treatment plant through regulatoryproceedings, which could restrict our access to the plant, disrupt ourproduction operations and negatively impact our revenues. An example of such aproceeding is the complaint filed by Crimson with the Texas Railroad Commissiondescribed under “Properties—Description of the Properties—Texas—TheMadisonville Gas Treatment Plant and Gathering Facilities.” 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 theMadisonville gas treatment plant. The gas treatment plant is currentlyoperating at capacity. There is no guarantee that we will be able to maintainfull access to treatment capacity of up to 68 MMcf/d at the MadisonvillePlant at all times because, for example, Crimson now has the right to have itsnatural gas treated at the plant, which will 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,Australia, Canada or the United States could change in manners thatnegatively affect our operations and prospects in those countries.***

Our business activities in Indonesia, Australia,Canada and the United States are subject to political and economic risks,including: loss of revenue, property and equipment as a result of unforeseenevents like expropriation, nationalization, war, terrorist attacks andinsurrection; increases in import, export and transportation regulations andtariffs, taxes and governmental royalties; renegotiation of contracts withgovernmental entities; changes in laws and policies governing operations offoreign-based companies; exchange controls, currency fluctuations andother uncertainties arising out of foreign government sovereignty overinternational operations; laws and policies affecting foreign trade, taxationand investment; and the possibility of being subject to the exclusivejurisdiction of foreign courts in connection with legal disputes and thepossible inability to subject foreign persons to the jurisdiction of courts inthe United States.

***Terrorist attacks could have an adverse effect on ouroil and natural gas operations, especially overseas.***

To date, our operations have not been disrupted byterrorist activity. It is uncertain how terrorist activity will affect us inthe future, or what steps, if any, the Indonesian, Australian, Canadian orAmerican government may take in response to terrorist activities. The attack onthe New York World Trade Center in 2001 and the subsequent wars inAfghanistan and Iraq have 

17

----

increased the likelihoodthat U.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.

***If we do notsatisfy the work requirements of our Production Sharing Contract (“PSC”) andexploration permits, the Indonesian and/or the Australian government mayterminate all or part of our contracts. Please see the Glossary for adefinition of Terms.***

Our Indonesian PSCs and Australian exploration permitsrequire us and our partners to undertake work by specified dates in order tomaintain our oil and natural gas rights. See “Properties—Description of theProperties—Indonesia and Australia.” We may not be able to satisfy ourcontractual obligations. If we do not otherwise comply with the workrequirements of the PSCs and exploration permits, or successfully renegotiatethe terms, all or part of one or more of our contracts may be terminated. Ifthese contracts are terminated, we would also lose all of our investment inthat overseas prospect. If we forfeit our interest in the contract or permitareas, it will be necessary to record an impairment write-down equal to the netcapitalized costs recorded for the area forfeited. This could have a materialadverse impact on our financial condition and results of future operations infuture periods. On September 29, 2006, we sold 70% of our interest in C-GBengara to CNPC.   C-G Bengara owns 100%of the underlying rights in the Indonesian contract area known as the BengaraBlock.  CNPC has agreed to fund our unmetwork commitments in the Bengara Block. As discussed in greater detail under “Properties”in this report, C-G Bengara is subject to prior work commitments for thenine-year period ended December 3, 2006 requiring total expenditures of $24million. As of September 30, 2006, C-G Bengara had met approximately $6.3million of the $24.0 million required expenditures, leaving an approximate$17.7 million shortfall.  Theapplicable governing authority granted a deferral of the prior years’commitments until December 2006 and we expect to receive an additional deferraluntil December 2007. If we do not satisfy the prior and future work commitmentsand if we fail to secure further deferrals of such commitments, we will need torecord an impairment charge equal to the amount of costs capitalized which wereapproximately $562,000 as of December 31, 2006, and we may lose all of ourrights in the Bengara Block.

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

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

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

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

 

18

----

***Ouracquisition activities are subject to uncertainties, may not be successful andprovide a return to us on our investments.***

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

***We aredependent upon our key officers and employees and our inability to retain andattract key personnel could significantly hinder our growth strategy and causeour business to fail.***

While no assurances can be given that our currentmanagement resources will enable us to succeed as planned, a loss of one ormore of our current directors, officers or key employees could severely andnegatively impact our operations and delay or preclude us from achieving ourbusiness objectives. Stuart Doshi, David Creel and Chris Steinhauser, the threemembers of our senior management team, have a combined experience ofapproximately 100 years in the oil and gas industry. Although we have enteredinto employment agreements with Messrs. Doshi, Creel and Steinhauser, wecould suffer the loss of key individuals for one reason or another at any timein the future. There is no guarantee that we could attract or locate otherindividuals with similar skills or experience to carry out our businessobjectives. We maintain “key man” insurance with respect to our ChiefExecutive Officer, Stuart Doshi.

***Some ofour directors may become subject to conflicts of interest which could impairtheir abilities to act in our best interest.***

Nick DeMare, one of our directors, is a director,officer and/or significant shareholder of other natural resource companies andDavid Anderson, another one of our directors, is a director and officer ofDundee Securities Corporation, an investment banking firm that was the lead underwriterof our public offering of common stock in Canada and concurrent previousprivate placement of common shares with qualified institutional buyers in theU.S. Their association with these other companies in the oil and gas businessmay give rise to conflicts of interest from time to time. For example, theycould be presented with business opportunities in their capacities as ourdirectors, which they could, in turn, offer to the other companies for whomthey also serve as directors, rather than to us, whose interests might becompetitive with ours. Our directors are required by law to act honestly and ingood faith with a view to our best interests and to disclose any interest whichthey may have in any project or opportunity to us; however, their interests inthe other companies may affect their judgment and cause such directors to actin a manner that is not necessarily in our best interests.

***Ourdirectors and officers hold significant positions in our shares and theirinterests may not always be aligned with those of our other shareholders.***

As of March 30, 2007 our directors and officersbeneficially own 24% of our outstanding common stock. See “Security Ownershipof Certain Beneficial Owners and Management”. This shareholding level willallow the directors, officers and certain beneficial owners to have asignificant degree of influence on matters that are required to be approved byshareholders, including the election of directors and the approval of significanttransactions. The short-term

19

----

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.

***Ourfailure to manage internal or acquisition-based growth may cause operationaldifficulties and negatively affect our financial performance.***

We expect to experience internal and/oracquisition-based growth, which may bring many challenges. Growth in the numberof employees, sales and operations will place additional pressure on alreadylimited resources and infrastructure. No assurances can be given that we willbe able to effectively manage this or future growth. Our growth may place asignificant strain on our managerial, operational, financial and otherresources. Our success will depend upon our ability to manage our growtheffectively which will require that we continue to implement and improve ouroperational, administrative and financial and accounting systems and controlsand continue to expand, train and manage our employee base. Our systems,procedures and controls may not be adequate to support our operations and ourmanagement may not be able to achieve the rapid execution necessary to exploitthe market for our business model. If we are unable to manage internal and/oracquisition-based growth effectively, our business, results of operationsand financial condition will be materially adversely affected.

**Risks Related toOur Common Stock**

***Theshareholding position of holders of our common stock could be diluted by futureissuances and conversions of other securities.***

If our options and warrants are exercised for commonshares, holders of our common stock will experience immediate and, depending onthe magnitude of the exercises, substantial dilution. As of the date of thisreport, 2,057,855 shares of our common stock are issuable upon exercise of warrantsand 3,960,000 shares of our common stock are issuable upon exercise of options.

Investors may be subject to further dilution if wesell additional common shares or issue additional common shares in connectionwith future financings.  If a significantnumber of our common shares are sold in the public market, the market price ofour common shares could be depressed. This could hamper our ability to raisecapital by issuing additional equity securities.

***Our results may be affected by fluctuations incurrency exchange rates.***

Our financial statements are reported inU.S. dollars and all of our revenue, and most of our operating costs, arecurrently denominated in U.S. dollars; however, we have operations outsidethe United States and we plan to expend money in Indonesia, Canada andAustralia, where our operating costs will be denominated in local currencies.Fluctuations in exchange rates may increase our relative cost of operating inthese countries, and may therefore have a negative effect on our financialresults.

20

----

***Non U.S.holders of our common shares may be subject to U.S. federal income tax on thesale of our common shares and purchasers may have IRS withholding requirements***

Unless certain requirements are met, gain recognizedby a non U.S. holder on the sale of our common shares will be subject to U.S.federal income tax at normal graduated rates, and a purchaser will be requiredto withhold for the benefit of the IRS 10% of the purchase price since we are aUnited States real property holding corporation. There is an exemption fromU.S. federal income tax for non-U.S. holders of 5% or less of our common shares(and to withholding for all non U.S. holders) if our common shares are“regularly traded on an established securities market.”  In the event that 100 or fewer persons own50% or more of our common shares (which had been, and may now and may continueto be, the case), temporary Treasury Regulations provide that our common shareswill be “regularly traded on an established securities market” for a calendarquarter only if the established securities market is located in the UnitedStates and our common shares are regularly quoted by more than one broker ordealer making a market in our common shares; our common shares are currentlylisted on the American Stock Exchange (which constitutes an establishedsecurities market for this purpose) and quotes are being regularly made by atleast two broker dealers.  There can beno assurance, however, that our common shares will continue to be regularlytraded on an established securities market for this purpose in any particularcalendar quarter so as to avoid U.S. federal income tax on the sale of ourcommon shares by non-U.S. holders of 5% or less of our common shares and thewithholding requirement on the purchaser.

At such time thatit is no longer the case that 100 or fewer persons own 50% or more of ourcommon shares, under temporary Treasury Regulations, our common shares wouldalso be “regularly traded” on an established securities market for a calendarquarter if:  (a) our common shares trade,other than in de minimis quantities, on at least 15 days during the calendarquarter; (b) the aggregate number of our common shares traded during thecalendar quarter is at least 7.5% of the average number of our common sharesoutstanding during such calendar quarter (reduced to 2.5% if there are 2,500 ormore record shareholders); and (c) in the event that our common shares aretraded on an established securities market located outside the United States,the common shares are registered under Sec. 12 of the Securities Exchange Actof 1934 (which they presently are).

***There isa limited public market for our common shares, and the ability of ourshareholders  to dispose of their commonshares may be limited.***

Our common shares have been listed on The TorontoStock Exchange since March 2006, and have been trading on the AmericanStock Exchange since February 15, 2007. We cannot foresee the degree of liquidity that will be associated withour common shares. A holder of our common shares may not be able to liquidatehis, her or its investment in a short time period or at the market prices thatcurrently exist at the time the holder decides to sell. The purchase and saleof relatively small common share positions may result in disproportionately largeincreases or decreases in the price of our common shares. A trade involving alarge number of common shares could have an exaggerated effect on the reportedmarket price of our common shares.

***Our stock price may fluctuate significantly.***

The stock marketin general and the market for natural gas and oil exploration companies haveexperienced price and volume fluctuations that are often unrelated ordisproportionate to the operating results or asset values of companies. Thesebroad market and industry factors may seriously impact the market price andtrading volume of our common shares regardless of our actual operatingperformance. The market price of our common stock could also fluctuatesignificantly as a result of:

·       actual or anticipatedquarterly variations in our operating results and our reserve estimates;

·       changes in expectations asto our future financial performance or changes in financial estimates, if any,of public market analysts;

·       announcements relating toour business or the business of our competitors;

·       conditions generallyaffecting the oil and natural gas industry, including changes in oil andnatural gas prices;

·       speculation in the press orinvestment community;

21

----

·       general market and economicconditions;

·       the success of our operatingstrategy; and

·       the operating and stockprice performance of other comparable companies.

***The sale of large numbers of our common stock maydepress the market price of our common stock.***

***The sale of a substantial number ofshares of our common stock in the public market, or the perception thatsubstantial sales may occur, could cause the market price of our common stockto decrease.   Substantially all of theshares of our common stock are freely transferable or will be transferable incompliance with restrictions under the Securities Act of 1933, as amended.***

***We will continue to incur significant expenses as aresult of 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 well as related rules implemented bythe Securities and Exchange Commission, or SEC, and the American StockExchange, have required changes in corporate governance practices of publiccompanies.  Compliance with these laws,rules and regulations has increased our expenses, including our legal andaccounting costs, and made some activities more time-consuming and costly.  We also believe these laws, rules andregulations have made it more expensive for us to obtain director and officerliability insurance, and in the future we may be required to accept reducedpolicy limits and coverage or incur substantially higher costs to obtain thesame or similar coverage.  As a result,it may be more difficult for us to attract and retain qualified persons toserve on our board of directors or as officers. Furthermore, any additional increases in legal, accounting, insuranceand certain other expenses that we may experience in the future couldnegatively impact our financial performance and have a material adverse effecton our results of operations and financial condition***.

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

None.

**Item 2. *Properties***

Our principal executive office consists of 2,956square feet and is located at One Maritime Plaza, Suite 700, SanFrancisco, CA 94111.

**Description of theProperties**

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

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

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

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

22

----

·       **Australia**—onshore in two permit areas located in the SouthPerth basin.

We do not fully insure against all business riskseither because such insurance is not available or because premium costs areprohibitive. This is a common practice in the oil and gas industry. We believeour property is adequately insured in view of the nature of our operations andindustry practices in this regard.

***Texas***

*MadisonvilleProject*

We own and operate the interest in the MadisonvilleProject in Madison County, Texas. We own working interests in approximately2,974 gross and net acres of leases in the Rodessa Formation interval, as wellas approximately 2,812 gross and net acres of leases as to depths below theRodessa Formation interval. We also own a license as to12.5 square miles of 3-D seismic data over theMadisonville Field. In addition, we have entered into farmout agreements whichrequire us to drill certain wells in order to earn 100% working interest rightsin up to 1,742 acres in depths equivalent to the Rodessa Formation interval anddeeper.

The Madisonville Field, located approximately 100miles north of Houston, has produced oil and natural gas from four differenthorizons above the Rodessa Formation for over 50 years. The field wasdiscovered in 1945 with the Boring No. 1 well, which was drilled to theRodessa Formation. The well blew out at an uncontrolled rate for three daysduring a test; however, due to hydrogen sulphide, carbon dioxide and nitrogenin the Rodessa Formation natural gas, the gas reserves were never developed.Over 125 wells were drilled in the Madisonville Field to shallower intervalsabove the Rodessa Formation. In 1994, nearly 50 years after the initialdiscovery, United Meridian Corporation (“**UMC**”)drilled the Magness Well as the first follow-up well into the Rodessa Formationto the Boring No. 1 well. The Magness Well had 139 feet of net paybut the natural gas was found to contain 28% impurities.

UMC previously production tested the Magness Well in1994 through perforations in the lower most ten feet of the indicated RodessaFormation pay interval. The well tested at a rate of 12 MMcf/d from thislimited interval on a 22/64ths inch choke with flowing wellhead pressuresincreasing from 3,915 to 3,919 pounds per square inch. In 2001, we re-enteredand recompleted the Magness Well. A total of 139 feet of interval has beenperforated in the Rodessa Formation at approximately 12,000 feet of depth forthis well. The well was production tested over a 12-day period in 2001 onvarious choke sizes with flowing rates ranging up to approximately20.8 MMcf/d. We own a 100% working interest (75.1333% net revenueinterest) in the Magness Well located in the surrounding production unitconsisting of 629 gross and net acres. The Magness Well commenced production inMay of 2003.

The first development well, the Fannin Well, wasdrilled and completed in 2004. We own a 100% working interest (70.5636% netrevenue interest) in the Fannin Well located in the surrounding production unitconsisting of 704 gross (704 net) acres. A total of 146 feet of indicatedpay was perforated in the well and a flow test of the well was completed inDecember 2004 from the Rodessa Formation at rates of up to25.7 MMcf/d. We commenced production from the Fannin Well in early 2006.

In 2006, we drilled the Wilson and Mitchell wells. Weown a 100% working interest (70% net revenue interest) in the Wilson andMitchell wells. Presently, the Fannin and Magness wells are producing at acombined restricted rate of approximately 16.5 MMcf/d while the Wilson andMitchell wells are shut-in awaiting completion and/or pipeline connections. Theproduction rate is presently restricted while awaiting a planned expansion ofthe Madisonville Field gas treatment plant to 68 MMcf/d treating capacity.

23

----

The Madisonville Field is a geologic featureencompassing approximately 4,100 acres at the Rodessa limestone at about11,800 feet of depth. A 3-D seismic program shot in early 1998confirmed the size of the structure and slightly increased its size overearlier interpretations.

Our working interest covers the Rodessa Formation atapproximately 12,000 feet of depth. The Rodessa reserves are beingdeveloped through the recompletion of the Magness Well and the drilling ofadditional proved and probable undeveloped locations. Production began inMay 2003 and stabilized at a rate of 18 MMcf/d of raw gas from theMagness Well. The Magness and Fannin wells are currently producing at acombined restricted rate of approximately 16.5 MMcf/d. Current netsales production is approximately 10 MMcf/d. In addition, we own a workinginterest in certain leases and farmout rights which cover depths below theRodessa Formation.

The hydrogen sulphide, carbon dioxide and nitrogencombined comprise about 28% of the gas content. As described below, anunaffiliated third party purchases the untreated natural gas from us at thewell site point of delivery for a net price equal to the weighted average priceper MMBTU that the third party receives for the natural gas delivered to thesales pipeline less certain gathering, treatment and transportation charges. Asa result of the charges, we receive a net price that is substantially lowerthan we would otherwise receive if the gas did not contain the 28% ofimpurities. In addition, the high concentrations of hydrogen sulphide andcarbon dioxide result in higher capital and operating costs for our wells. Forexample, the hydrogen sulphide and carbon dioxide are corrosive to thewellbores. This means we have to utilize higher grade specification well tubingand casing which is more expensive than what we would utilize absent theimpurities. In addition, we continuously treat the well bores with chemicals designedto inhibit the corrosive effects of the impurities. We also maintain fieldpersonnel at or near the wellsites who monitor the wells on a twenty four hourbasis and equip the wellsites with extensive safety equipment systems due tothe toxic properties of the hydrogen sulphide and carbon dioxide. These factorsand others result in higher capital and operating costs for our wells in theMadisonville Project.

*The Madisonville Gas Treatment Plant and GatheringFacilities*

In order to produce the proven gas reserves from theRodessa Formation, we developed an onsite plan to treat and remove impuritiesfrom the Madisonville Project natural gas in order to meet pipeline-qualityspecifications. On June 15, 2001, we, through our subsidiary Redwood LP,entered into an agreement, which agreement was subsequently amended andrestated, together with certain related agreements (collectively, the “**Hanover Agreement**”), with Hanover pursuantto which Hanover committed to fund, construct and operate a dedicated naturalgas treatment plant 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 approximately 70 MMcf/dto transport the Madisonville Field natural gas to a major pipeline.  By April of 2003, the construction andinstallation of Hanover’s natural gas treatment plant and Gateway’s associatedpipeline and gathering facilities were completed. Gas production from theMagness Well commenced in May 2003. We received the first revenues fromthe sale of natural gas from the Madisonville Project in July 2003. Thenatural gas plant is currently capable of treating approximately up to18 MMcf/d of inlet natural gas from the Magness Well.

On July 25, 2005, MGP purchased the natural gastreatment plant from Hanover and purchased the gathering pipelines upstream ofthe gas treatment plant from Gateway. Concurrent with MGP’s purchase of the gastreatment plant and gathering pipelines, we, through our subsidiary Redwood LP,Gateway and MGP terminated the Hanover Agreement and entered into a newagreement, (the “**MGP Agreement**”),to treat and transport our gas production from the Madisonville Project. As aresult of the MGP Agreement, MGP committed to install and make operationaladditional treating facilities capable of treating 50 MMcf/d, whichcombined with the capacity of the current in-service

24

----

treating facilities will represent a total treatingcapacity of 68 MMcf/d for the Madisonville treatment plant. The MGPAgreement provides that the newly installed gas treatment facilities will be100% electrically driven when the treatment capacity is expanded. Currently,the existing in-service treatment plant utilizes some of the natural gasproduced and delivered from our well(s). The conversion to 100% electricity onthe expanded portion of the treatment plant is expected to reduce shrinkage ofour natural gas that occurs in the treating process.

Originally, the MGP Agreement required MGP to completethe additional treating facilities by March 1, 2006.  However, due to events of force majeure, theadditional treating facilities are only now nearing completion.  Representatives of MGP have indicated thatthey expect the full expansion of the treatment plant to 68 MMcf/dcapacity can be in place and operational by the second quarter of 2007;however, there can be no guarantee that the expansion will be completed by thattime.

We have proceeded to drill and complete our new developmentwells notwithstanding MGP’s delay in completing the expansion of the treatmentplant. To the extent that production begins at the new wells before theexpansion is completed, as is the case with the Fannin Well which was placed onproduction in March 2006, production of the wells will be restricted asnecessary pending completion of the plant expansion.

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 gasproduction from our interest in the Madisonville Project to MGP. MGP purchasesthe untreated 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 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. BeginningOctober 1, 2010, this fee of $1.10 per Mcf shall be charged for all gas measuredand 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 PriceIndex (“**CPI**”). One-half (1/2) of the foregoing gathering andmarketing fees are adjusted using the CPI. We have the right, upon giving60 days’ notice, to terminate the marketing fee whereupon we shall assumethe sole responsibility of marketing the natural gas sold. The **PPI** and the **CPI** are priceindices published by the U.S. Department of Labor.

For the first 18,000 Mcf/d of gas measured anddelivered to the inlet flange of the gas treatment plant, Gateway will receivea transportation fee of $0.10 per Mcf. This fee will remain in effect throughJuly 31, 2008. Beginning August 1, 2008 and terminating onJuly 31, 2010, the fee shall be reduced to $0.08 per Mcf for the first18,000 Mcf/d of gas measured and delivered to the inlet flange of the gastreatment plant. For any gas volumes in excess of 18,000 Mcf/d of gasmeasured and delivered to the inlet flange of the gas treatment plant, Gatewaywill receive a transportation fee of $0.12 per Mcf measured and delivered fromthe outlet flange of the plant. This fee will remain in effect throughJuly 31, 2008 and shall be reduced to $0.10 per Mcf thereafter.

25

----

After July 31, 2010, this transportation feeshall be $0.10 per Mcf for all volumes delivered from the outlet flange of theplant.

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 ourwell(s).

Our natural gas deliveries to the Madisonville gastreatment plant may be affected by third party demands for access to the plant.On July 20, 2005 Crimson Exploration Inc. (“**Crimson**”) filed a complaint with the TexasRailroad Commission (“**TRC**”)against Gateway and Hanover. The complaint alleged discrimination by Hanoverand Gateway, and requested that the TRC issue an order requiring Hanover andGateway to ratably process, take, transport, or purchase natural gas producedby Crimson into the Madisonville Field gas treatment plant. The complaint didnot allege any wrongdoing by Redwood or Redwood LP; however, the complaintreferred to the contractual relationship between each of Redwood LP,Hanover, and Gateway which was terminated July 25, 2005 as the basis forits discrimination complaint. Redwood received a subsequent notice datedJanuary 13, 2006 from the TRC informing Redwood that (i) Crimson hadfiled a request to docket its complaint against MGP for failure to ratably takegas pursuant to Texas regulations and (ii) a pre-hearing conference washeld on January 25, 2006 relating to the complaint. Redwood withdrew fromthe proceeding.

On January 23, 2006, our counsel received aletter from counsel for MGP reaffirming that regardless of the outcome of theproceedings before the TRC, MGP nonetheless recognizes that it has acontractual obligation to treat 68 MMcf/d of natural gas produced byRedwood LP and delivered to the treatment plant. After consultation withlegal counsel, we believe that our contract with MGP is fully enforceable.

On August 9, 2006, the Texas Railroad Commissionissued an order requiring MGP to ratably process, take, transport or purchasenatural gas produced by Crimson into the Madisonville gas treatment plant. Thegas treatment plant is currently operating at capacity. There is no guaranteethat we will be able to maintain full access to treatment capacity of up to68 MMcf/d at the Madisonville Plant at all times because, for example,Crimson now has the right to have its natural gas treated at the plant, whichmay reduce the plant’s ability to treat all of our natural gas, unless theplant’s capacity is further expanded.

To date, Crimson has permitted four wells to bedrilled to the Rodessa Formation. The drilling of two of these wells has beencompleted to a depth of approximately 12,635 feet. Crimson has also drilled aninjection well for disposal of waste products resulting from the treatment oftheir natural gas.

We have committed to a three-well drilling program tofacilitate the expansion of the gas treatment plant. We have drilled two of thethree required wells to the Rodessa formation. The commitment requires us to commence the drilling of the third wellsufficient to test the Smackover Formation (estimated to be encountered atapproximately 18,000 feet) on or before September 30, 2008. We estimatethe 18,000 foot well will cost $10 million to drill and complete. We havegranted MGP a security interest in the Madisonville Field properties to securethe three well commitment. The security interest shall be subordinated to anythird party lender in the event we secure future debt against the property. MGPhas granted us a similar security interest in the gas treatment plant to secureits obligation to expand the treatment plant on a timely basis.

*Other Interests inthe Madisonville Project*

Our working interest in the Madisonville Project issubject to a net profits interest in favor of the third party that sold us ourworking interests in the Madisonville Project. The net profits interest is12.5% (proportionately reduced to our interest) of the net operating profitsuntil payout is

26

----

achieved. After payout, the net profits interestincreases to 30% (proportionately reduced to our interest). “Payout”, forpurposes of the net profits interest, is defined and achieved at such time aswe have recouped from net operating cash flows our total net investment in theMadisonville Project plus a 33% cash on cash return.

***Alaska***

*The Cook InletAlaska CBM Project*

We entered into an agreement with Pioneer OilCompany, Inc. (“**Pioneer**”) datedApril 20, 2005, wherein we secured the Cook Inlet Option to acquire a 100%working interest, 81% net revenue interest, in approximately 116,806 acresonshore in Cook Inlet, Alaska. We have since acquired 5,368 additional acres.We believe this acreage to be prospective for both coal bed methane andconventional gas production.

The 122,174 acre lease position consists of twoseparate target areas that have been selected for exploration. These areas arecalled the Point MacKenzie and Trading Bay Prospects, respectively.

The Point MacKenzie Prospect is located six milesnorthwest of Anchorage. The Trading Bay Prospect is located 50 miles westof Anchorage across the Cook Inlet. The Cook Inlet basin contains a thicksection of terrestrial Tertiary rocks which includes shales, sandstones, andcoals. The coals occur in seams which are commonly 20 feet thick and canbe as thick as 70 feet. Accessible onshore areas have 200 to300 feet of coal shallower than 5,000 feet. Gas content for thesecoals ranges from 80 to 250 standard cubic feet per ton, but testingis restricted to a very small number of bore holes and is almost completelyunknown for most of the inlet.

Markets for natural gas in the Cook Inlet area includepower generation, heating, fertilizer production and liquefied natural gasexports. An extensive pipeline system supplies these facilities and crosses thePoint MacKenzie Prospect and Trading Bay Prospect lease blocks. These pipelinesare only partially filled with gas and could accommodate additional production.

In addition to coal bed methane reserve potential,preliminary log analysis indicates the Point MacKenzie Prospect and Trading BayProspect lease blocks may also contain conventional accumulations of naturalgas reserves in Tertiary sandstones.

The terms of the Cook Inlet Option provide for us topay total consideration of $20 per acre, or approximately $2.3 million,for the leases. The Cook Inlet Option provides that we will pay the total leaseconsideration in two installments. We paid the first installment totaling$1,068,063 on August 17, 2005 and we have received assignment of the 100%working interest in the leases. Within three years from the date of receipt ofassignment of the 100% working interest in the leases, we have the option toconduct a $2.5 million work program consisting of, but not limited to, amultiple test well drilling program on the leases over a three-year period,and, after completion of the work program and an evaluation of the results, toremit the final additional acreage consideration of $10 per acre for theleases. The Cook Inlet Option provides that if we fail to pay the leaseconsideration when due, fail to perform the work program or otherwise defaultunder the Cook Inlet Option, we shall forfeit our interest and reassign theleases to Pioneer, and we will have no further liability to Pioneer.

Approximately one to two miles of pipeline will berequired to tie in any wells drilled at a currently preferred location at thePoint MacKenzie Prospect, and approximately four to five miles of the pipelinewill be required to tie in any wells drilled at a currently preferred locationat the Trading Bay Prospect. We have not yet prepared an estimate of the costto tie these wells in.

We are aware of two major pipelines which transversethe acreage blocks, the Enstar 20” line and the UnoCal-Marathon 16” line.We estimate the UnoCal-Marathon 16” line presently has

27

----

available unused capacity of approximately40 MMcf/d. In addition, we estimate the Enstar 20” line has availableunused capacity of approximately 100 MMcf/d.

***California***

*Lokern Project*

We have a working interest in the Lokern Project,located in the southern San Joaquin basin, near Bakersfield, California. Theprimary exploration objective is the Miocene Stevens formation. The secondaryobjectives include the Miocene Reef Ridge and Pliocene Etchegoin sands. TheStevens formation is Upper Miocene age.

The Lokern Project is being developed in part as aresult of positive results from the Machii-Ross Ackerman show well drilled in1979 on acreage currently controlled by us. Based on log analysis, we believethat well had approximately 240 feet of potential net oil pay and an additional150 feet of potential pay in the Stevens zone. The Machii-Ross Ackermanwell was drilled to a depth of 15,078 feet by Machii-Ross Petroleum Company andwas plugged and abandoned as a dry hole. We believe, based on our log analysis,that the well may have been a bypassed producer.

We expect that a well will be drilled, either by us orthrough a farmout arrangement with a third party, to a depth of15,000 feet by 2008.

Based on our review of title information from publicauthorities and other publicly available sources, we believe that we have a100% working interest in the Lokern Project. As is customary in theU.S. oil and gas industry, we will not conduct a thorough title reviewwith respect to our interest in the Lokern Project until we have made adefinitive decision to drill in a particular lease area.

***Alberta***

*Pinnacle ReefProject*

The Pinnacle Reef Project is located in Alberta,Canada, approximately 100 miles northeast of Calgary. The primary explorationobjective is Leduc D3 Pinnacle Reefs. A Leduc D3 Pinnacle Reef refers to acertain type of reef complex within the Leduc formation. Secondary objectiveswill include the shallower Nisku formation and deeper Winnipegosis formation.

These formations are expected to be encountered atdepths of less than 10,000 feet. We, through our wholly-ownedsubsidiary, GeoPetro Canada, have acquired seismic data and plan to participatein the drilling of test wells.

We have a 56.25% working interest in 2,560 leasedacres.

***Indonesia***

C-G Bengara owns 100% of the underlying rights toexplore for and produce oil and natural gas within the contract area designatedas the Bengara II Block, which rights have been granted under a productionsharing contract dated December 4, 1997 (the “**Bengara II PSC**”) with Pertamina. Until recently, we owned 40%of CG Bengara and Continental Energy Corporation (“Continental”) owned theremaining 60% and, through it, the rights to the Bengara II PSC. On September29, 2006, we executed a definitive agreement to sell 70% of our interest in C-GBengara to CNPCHK (Indonesia) Limited (“CNPC”). We have retained a 12% stake inC-G Bengara and the Bengara II PSC. Continental has likewise sold its interestand retained an 18% interest in C-G Bengara and the Bengara II PSC.

28

----

The Bengara Block is located in the Tarakan Basin,mostly onshore but partially offshore astride the Bulungan River Delta in theIndonesian province of East Kalimantan. It originally covered a single contiguousarea of approximately 1.2 million gross acres, of which 300,000 grossacres were relinquished in 2001 by C-G Bengara in accordance with theterms of the Bengara II PSC. A portion of our holdings in Indonesiawas scheduled to be relinquished effective December 3, 2005. We haverequested a postponement of the relinquishment from BP Migas; however, ifthe postponement is not granted, then a further 300,000 gross acres willbe relinquished.

Geologically, the Bengara Block lies in the TarakanBasin near major oilfields at Tarakan and Bunyu. More than 320 MMbbls and96 bcf of natural gas have been produced from the Tarakan Basin accordingto records maintained by BP Migas. The Tarakan Basin is one of fivesedimentary basins making up eastern Borneo on the eastern margin of the broadarea of Southeast Asia and are some of the deepest in Indonesia, with seismicsurveys indicating depths greater than 20,000 feet in the Tarakan Basinsoutheast of Bunyu Island.

*The Makapan GasField*

Since 1938, only two wells have been drilled in theBengara Block, one of which resulted in the discovery of the Makapan Gas Field.The Muara Makapan No. 1 well was drilled in 1988 by P.T. Deminex Indonesiafrom a swamp barge positioned on one of the Bulungan River Delta mouth channeldistributaries. The well was drilled to a total depth of 10,800 feet and tested19.5 million cubic feet of gas per day together with 600 bbls of54 degree API condensate per day from a 33 feet thick sandstonesection near 6,000 feet. The well was plugged and abandoned as a naturalgas discovery. Several other gas zones indicated on logs were not tested. Thewell was not produced nor were any confirmation wells drilled due to the lackof a local natural gas market at the time the well was drilled. The Makapan GasField gas is a “Wet’ gas with a high LPG fraction which may be commercialto extract at the wellhead for a third revenue source in addition to the gasand condensate. The Makapan Gas Field lies mostly offshore in very shallowwater, less than 10 feet, amidst numerous islands of the Bulungan RiverDelta.

*Exploration in theBengara Block*

We believe that the key to successful prospecting inthe Bengara Block will be the identification of traps and understanding sanddistribution.

A striking feature of the Bengara Block is thepresence of a few old wellbores actively leaking oil into surface lakes. Siteinvestigations with a wireline unit are planned to determine the depths of theexisting wellbores and obtain rock and oil samples at depth if possible.

Nearly 2,200 line kilometres of 2-D seismic dataavailable within the Bengara Block appear to be adequate for both detailed andreconnaissance interpretation purposes. Some localized areas may benefit fromreprocessing. New seismic data is required in places where insufficient dataexists and for prospect confirmation in other locations. Field geology surveysare expected to confirm initial drilling targets without the need foradditional seismic data at this time.

Several separate and unique geologic plays within theBengara Block as well as a number of prospects and leads have been identified.Some well-defined prospects present immediate drilling targets. Explorationwithin the Bengara Block is in its formative stages and it is premature to makemeaningful resource or reserve estimates. However, the existing explorationwork to date indicates

29

----

that there may be potential petroleum accumulations inthe Bengara Block. Analysis of source rocks indicates a propensity for both oiland natural gas.

*Terms ofParticipation in the Bengara Block*

The Bengara II PSC is a “standard terms” PSCemployed by BP Migas for all oil and natural gas concessions in Indonesia.Generally, the joint venture participants are entitled to receive, fromproduction proceeds, 100% of expenditures in the block as “cost recovery”. Oncethese costs are recovered, C-G Bengara is entitled to a production share ofapproximately 26.7% of oil produced and 62.5% of all natural gas produced. Wewill be entitled to 12% of C-G Bengara’s share of any such production. Sharingterms for certain categories of oil vary slightly as defined in theBengara II PSC.

The term of the contract is thirty years or a shorterperiod if C-G Bengara elects to terminate its obligations under the contract orif no commercial hydrocarbons are discovered within the contract area. At theend of six years, unless mutually extended by C-G Bengara andBP Migas, the contract expires if no commercially produciblehydrocarbons have been discovered in the contract area. C-G Bengara andBP Migas have mutually extended the early termination provisions untilDecember 3, 2008. C-G Bengara may terminate the contract at any time byrelinquishing all of its rights and obligations under the contract area.

C-G Bengara is required to relinquish 25% of thecontract area within the first three years of the contract, a further 25% ofthe contract area within six years from the commencement of the contract and anadditional area within the first ten years so that the area retained thereaftershall not be in excess of 970 square kilometres, or 20% of the originaltotal contract area, whichever is less. C-G Bengara may designate which areasare to be relinquished subject to approval by BP Migas. C-G Bengara’sobligation to relinquish parts of the original contract area under theseprovisions does not apply to the surface area of any field in whichpetroleum has been discovered. In 2001, C-G Bengara relinquished approximately300,000 gross acres of the original 1.2 million gross acre contractarea pursuant to the requirement to relinquish 25% of the contract areawithin the first three years of the PSC. The 300,000 gross acresrelinquished were located in the western portion of the block which C-G Bengaraconsidered to be the least prospective for oil and natural gas. C-G Bengara wasrequired to relinquish an additional 25% of the contract area in December 2005.However, C-G Bengara received a one-year postponement of therelinquishment until December 3, 2006 from BP Migas. We haverequested a further postponement of the relinquishment untilDecember 2007; however, if the postponement is not granted, then a further300,000 gross acres will be relinquished.

C-G Bengara isrequired to pay to BP Migas specified amounts based on achieving certaincumulative production quantities of crude oil from the contract area when andif commercial production is established. These production bonuses are asfollows:
| **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  |   |

 

 

30

----

In order tomaintain the Bengara II PSC in effect, C-G Bengara is required to complete thefollowing work programs and expenditures during the first ten years of thecontract, unless the requirement is extended or waived by BP Migas:
| **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 |   |

 

To date, C-GBengara has not fulfilled the minimum work and cash expenditure requirementsdescribed above. These work and expenditure requirements were extended byBP Migas until December 2006 and an additional deferral untilDecember 2007 has been requested. In accordance with the terms of the contractand with BP Migas’ consent, C-G Bengara may carry forward such yearlycommitments to subsequent periods provided that BP Migas consents to anyadditional extensions. Failure of C-G Bengara to pay such commitments when dueor to farm out its interest to an industry partner, which pays such obligation,may result in the forfeiture of its interest in, and rights to explore, drilland develop, the Bengara Block.

Upon establishingcommercial production, if ever, C-G Bengara and BP Migas shall shareratably in the first 20% of oil and natural gas produced in the contract areawithin a given year according to the percentages specified below. After thefirst 20% of production, C-G Bengara is entitled to receive 100% of productionuntil cost recovery has been achieved. Cost recovery generally includes 100% ofthe operating and drilling costs and depreciation of fixed assets applicable tooil and natural gas operations within the contract area. After C-G Bengara hasreceived oil and natural gas production with a value sufficient to achieve costrecovery in a given year, C-G Bengara and BP Migas shall then shareratably in the production according to the percentages specified below:
| **Description** | ** ** | **BP Migas** | ** ** | **C-G Bengara** | ** ** | **Our net share** | ** ** |
|-----------------|------------|-------------------|------------|----------------------|------------|-----------------------------|------------|
| Oil production  |       | 73.2143           | %          | 26.7857              | %          | 3.2143                      | %          |
| Gas production  |       | 37.5              | %          | 62.5                 | %          | 7.5                         | %          |

 

Thus, once we have achieved cost recovery, we will endup receiving approximately 3.2% and 7.5% of the proceeds from the sale of oiland gas, respectively.

Upon the completion of five years after commercialproduction commences, C-G Bengara is further subject to a domestic marketobligation. This obligation requires C-G Bengara to sell and deliver toBP Migas, to meet Indonesia’s domestic crude oil needs, a specifiedquantity of crude oil at a price which is only 15% of the market price of theoil. However, for new fields, for a period of five years starting on the monthof the first delivery of crude oil produced from a new field, the fee perbarrel for such crude oil supplied to the Indonesian domestic market shall bethe market price, 

31

----

with the condition thatthe excess over the 15% of market price shall preferably be used to assistfinancing of continued exploration efforts in the contract area.

Upon the first commercial discovery of oil or naturalgas in the contract area, BP Migas has the right to demand that 10% of C-GBengara’s undivided interest in the total rights and obligations under theBengara II PSC be offered to itself or an entity owned by Indonesiannationals. The 10% interest shall be offered at a dollar amount equal to 10% ofC-G Bengara’s cumulative costs incurred in the contract area.

C-G Bengara is subject to prior work commitments, aspreviously described under “Terms of Participation in the Bengara Block”, forthe nine-year period ended December 3, 2006 requiring total expenditures of $24million. As of September 30, 2006, C-G Bengara had met approximately $6.3million of the $24.0 million required expenditures, leaving an approximate$17.7 million shortfall. BP Migas, the applicable governingauthority, has granted a deferral of the prior years’ commitments untilDecember 2006. We have requested and expect to receive an additional deferraluntil December 2007.

*Current andPlanned Activities in the Bengara Block*

In accordance withthe terms of our agreement dated September 29, 2006 to sell 70% of our interestin C-G Bengara to CNPC, CNPC has:

1.                                       Purchased14,000 and 21,000 shares of C-G Bengara from us and Continental, respectively,at a cost of $1 per share. As a result of the transaction, we and Continentalown 6,000 and 9,000 C-G Bengara shares, respectively, retaining a12% and 18% interest in C-G Bengara, respectively.

2.                                       Paidthe sum of $18.7 million (the “**Earning Obligation**”)into a special joint venture account at a Hong Kong international bank. Thefunds will be under joint signature control of CNPC, ourselves and Continental,and will be expended exclusively to pay for 2006 and 2007 exploration drillingin the Bengara II PSC area, including four exploration wells included in C-G Bengara’sapproved 2006 work program and budget.

3.                                       Agreedto provide development loans to pay 100%, and thereby “carry” our share andContinental’s share of all C-G Bengara’s exploitation, drilling, anddevelopment expenditures attributable to the Bengara II PSC, after the EarningObligation funds are expended, until an additional amount of U.S. $41.3 millionover and above the Earning Obligation funds has been expended.

4.                                       Agreedto pay a cash bonus totaling $5,000,000, in the proportions of $2,000,000 to usand $3,000,000 to Continental, respectively, contingent upon and withinfourteen business days of the receipt by C-G Bengara of the written approvalfrom governmental authorities approving the development of the first commercialoil or gas discovery within the Bengara II PSC contract area.

The Earning Obligation funds of $18.7 million,together with the $6.3 million previously spent, will satisfy all of the pastand future work commitments on the Bengara II PSC.

BP Migas previously waived the work programexpenditure requirement provisions of the Bengara II PSC untilDecember 2006. We did not satisfy our work expenditure commitments by December2006, and if BP Migas does not grant any further deferrals of thosecommitments, we may be compelled to relinquish our interest in the contractarea. In the event we relinquish our 

32

----

interest, we will recordan impairment expense equal to the costs which have been capitalized inconnection with the contract area. As of December 31, 2006, we have capitalizedcosts totaling approximately $562,000 in respect to the contract area.

*CG Xploration*

InNovember 2005, we and Continental formed CG Xploration to pursue newventure oil and gas exploration and production projects and obtain newexploration concessions in Indonesia. CG Xploration Inc. isincorporated in Delaware and is owned 50% by us and 50% by Continental.CG Xploration Inc. will actively pursue and may acquire new ventureopportunities on behalf of ourselves and Continental.CG Xploration Inc. is evaluating production acquisition opportunitiesand may participate in several undeveloped field exploitation opportunities andolder field rehabilitation opportunities. To date, CG Xploration has madeno acquisitions.

***Australia***

We have entered into joint exploration agreementscovering two exploration permit areas in Australia.

*Whicher Range*

We presently own a 26.22% working interest in theWhicher Range Gas field project (the ”**WhicherRange Project**”). The Whicher Range Project is located in the SouthPerth basin of Western Australia. The field was discovered by Union Oil Company(“**Unocal**”) in 1968. To date, atotal of five wells have been drilled on the Whicher Range structure. We havecorrelated each of these wells and interpret the gas bearing intervals in eachwell to be in the same stratigraphic interval. These five penetrations provide controlto extrapolate the existence of natural gas across this large geologicstructure. The discovery well encountered 581 feet of net natural gas payover 1,844 feet of gross interval and was drill stem tested at a combined rateof 5.5 MMcf/d from six intervals. The natural gas discovery was in the SueCoal Measures sand, a tight sandstone of Permian age. Due to the lack of amarket for natural gas at the time the well was drilled, Unocal did not developthe discovery. In 1995, we acquired a working interest in the200,895 gross (52,675 net) acre permit from the government ofWestern Australia, which was subsequently designated as Exploration PermitEP 408 (“**EP 408**”), thatincluded the known Whicher Range gas field. Oil and Gas Communications Pty Ltd.is the operator of the Whicher Range Project.

The most recent well on the Whicher Range structure,the Whicher Range No. 5 well, was drilled in 2003. A total of 300 feet ofestimated net pay were identified from well logs. Production casing wascemented in place from approximately 14,000 feet to surface.

During August and September 2004, amulti-zone hydraulic fracture stimulation program (“**frac**”) was performed on the Whicher Range No. 5 well overfour sandstone sequences starting from the bottom zone and progressing zone byzone to the uppermost zone. Diesel fuel was pumped into the formations at veryhigh pressures attempting to initiate fractures. A very hard and coarse grainedproppant material was then pumped into each fracture during the operation to holdthe fractures open after the pressure was released. A subsequent flow test fromall of the zones together yielded marginal gas rates and a decision was made toplug and abandon the well. We are attempting to sell or farm out our interestin the EP 408 permit.

33

----

*Other AustralianExploration Permit*

In addition to EP 408, we own a 32.588% workinginterest in Exploration Permit 381 located in the South Perth basin, SouthwestAustralia, consisting of 330,000 gross (107,540 net) acres.

**Natural Gas Reserves**

Our estimated total net proved reserves of natural gasand oil as of December 31, 2006, 2005 and 2004, and the present values ofestimated future net revenues attributable to those reserves as of those dates,are presented in the following tables.

**“Proved developedoil and gas reserves”** meansreserves 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.

**“Proved developednonproducing reserves”** meansreserves expected to be recovered from zones behind casing in existing wells.

**“Proved oil andgas 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 ismade. Prices include consideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations based upon futureconditions.

(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 by gas-oiland/or oil-water contacts, if any; and (B) the immediately adjoining portionsnot yet drilled, but which can be reasonably judged as economically productiveon the basis of available geological and engineering data. In the absence ofinformation on fluid contacts, the lowest known structural occurrence ofhydrocarbons controls the lower proved limit of the reservoir.

(ii)                                  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)                               Estimates of provedreserves 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

34

----

(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 2006 estimates wereprepared by MHA Petroleum Consultants, independent reservoir engineers, and arepart of their reserve reports on our natural gas and oil properties. The 2005and 2004 estimates were prepared by SprouleAssociates Inc., independent reservoir engineers, and are part oftheir reserve reports on our natural gas and oil properties.  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.
| ** **                      | ** ** | **AS OF DECEMBER 31,** | ** ** |
|---------------------------------|------------|---------------------------------------|------------|
| ** **                      | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                      | ** ** | **(MMcf)**                            | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
| Proved developed                |       | 12,335                                |       | 4,645 |   | 4,448 |   |
| Proved developed  non-producing |       | 12,365                                |       | 8,903 |   | 7,037 |   |
| Proved  undeveloped             |       | —                                |       | 7,881 |   | 6,923 |   |
|                            |       |                                  |       |   |   |   |   |
| Total                           |       | 24,600                                |       | 21,428 |   | 18,408 |   |

 

In accordance with Securities and Exchange Commissionregulations, estimates of our proved reserves and future net revenues are madeusing sales prices estimated to be in effect as of the date of such reserveestimates and are held constant throughout the life of the properties, exceptto the extent a contract specifically provides for escalation. Estimatedquantities of proved reserves and future net revenues therefrom are affected bynatural gas and oil prices, which have fluctuated significantly in recentyears. We filed reports with the U.S. Department of Energy inMay 2006 and the Alberta Securities Commission in June 2006 that includedtotal proved reserves inclusive of royalties and net profits interests as ofDecember 31, 2005 totaling 39,493 MMcf. The total net proved reserves,excluding royalties and net profits interests, as of December 31, 2005 was21,428 MMcf. The difference between the two numbers represents proved reservesattributable to royalties and net profits interests.

35

----

***Standardized Measure of Discounted Future Net CashFlows***

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 developmentdrilling and production costs were computed by applying year-end costs to beincurred in producing and further developing the proved reserves. Future incometax expenses were computed by applying, generally, year-end statutory tax rates(adjusted for permanent differences, tax credits and allowances) to theestimated net future pre-tax cash flows. The discount was computed byapplication of a 10% discount factor. The calculations assume the continuationof existing economic, operating and contractual conditions. However, sucharbitrary assumptions have not proven to be the case in the past. Otherassumptions of equal validity could give rise to substantially different results.
| ** **                                                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|-----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                | ** ** | **(in thousands)**                    | ** ** |
| Future cash  inflows                                      |       | $                                          | 101,867    |   | $ | 162,459 |   | $ | 90,815 |   |
| Future  production costs                                  |       | (37,783                                    | )          | (60,176 | ) | (30,240 | ) |
| Future  development costs                                 |       | (1,075                                     | )          | (6,560 | ) | (4,860 | ) |
| Future income  taxes                                      |       | (8,128                                     | )          | (18,941 | ) | (9,609 | ) |
| Future net cash  flows                                    |       | 54,882                                     |       | 76,782 |   | 46,106 |   |
| 10% annual  discount                                      |       | (8,341                                     | )          | (13,293 | ) | (8,455 | ) |
| Standardized measure of  discounted future net cash flows |       | $                                          | 46,541     |   | $ | 63,489 |   | $ | 37,651 |   |

 

36

----

***Pricing Assumptions***

**SEC regulations require that the gas and oil prices used inthe MHA Petroleum Consultants and SprouleAssociates Inc. reserve reports included herewith are theperiod-end prices for natural gas at December 31, 2006, 2005 and 2004,respectively. These prices are projected without inflation for the life of thewells included in the reserve reports. The pricing assumptions are listedbelow:**

| AVERAGE YEAR-END PRICE | ** ** |
|----------------------------------|------------|
| **2006 REPORT**             | ** ** | **2005 REPORT** | ** ** | **2004 REPORT** | ** ** |
| **Gas ($/MMBtu)**           | ** ** | **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** |
|                             |       |   |   |   |   |
| $                                | 5.40       |   | $ | 7.80 |   | $ | 5.20 |   |
|                                  |            |  |  |  |  |  |  |  |

** **

**DrillingActivities**

The followingindicates the number of natural gas and oil wells drilled during the periodsindicated.
| ** **                    | ** ** | **Productive** | ** ** | **Dry**    | ** ** | **Total Wells** | ** ** |
|-------------------------------|------------|----------------|------------|------------|------------|----------------------|------------|
| ** **                    | ** ** | **Gross**      | ** ** | **Net**    | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| 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 |   |
|                          |       |           |       |       |       |                 |       |   |   |   |   |   |   |
| Year ended  December 31, 2004 |       |           |       |       |       |                 |       |   |   |   |   |   |   |
| Exploratory                   |       | 0              |       | 0          |       | 1                    |       | 0.75 |   | 1 |   | 0.75 |   |
| Development                   |       | 1              |       | 1          |       | 0                    |       | 0 |   | 1 |   | 1 |   |
|                          |       |           |       |       |       |                 |       |   |   |   |   |   |   |

 

**Acreage andProductive Wells**

The followingtable sets forth our ownership interest in undeveloped acreage, developedacreage and productive wells in the areas indicated where we own a workinginterest as of December 31, 2006. Gross represents the total number ofacres or wells in which we own a working interest. Net represents ourproportionate working interest resulting from our ownership in gross acres or wells.Productive wells are wells in which we have a working interest and that arecapable of producing natural gas or oil. Wells that are completed in more thanone producing horizon are counted as one well.

37

----

 
| ** ** | ** ** | **Undeveloped Acreage** | ** ** | **Developed Acreage** | ** ** | **Producing Wells** | ** ** | **Non-Producing Wells** | ** ** |
|------------|------------|------------------------------|------------|----------------------------|------------|--------------------------|------------|------------------------------|------------|
| ** ** | ** ** | **Gross**                    | ** ** | **Net**                    | ** ** | **Gross**                | ** ** | **Net**                      | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
|       |       |                         |       |                       |       |                     |       |                         |       |   |   |   |   |   |   |   |   |
| Indonesia  |       | 900,000                      |       | 108,000                    |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
| Australia  |       | 530,896                      |       | 160,216                    |       | —                   |       | —                       |       | — |   | — |   | 2 |   | 0.52 |   |
| Texas      |       | 3,383                        |       | 3,383                      |       | 1,333                    |       | 1,333                        |       | 2 |   | 2.00 |   | 4 |   | 3.02 |   |
| California |       | 1,280                        |       | 1,280                      |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
| Alaska     |       | 122,174                      |       | 122,174                    |       | —                   |       | —                       |       | — |   | — |   | — |   | — |   |
|       |       |                         |       |                       |       |                     |       |                         |       |   |   |   |   |   |   |   |   |
| Total      |       | 1,557,733                    |       | 395,053                    |       | 1,333                    |       | 1,333                        |       | 2 |   | 2.00 |   | 6 |   | 3.54 |   |

 

38

----

The following table setsforth as of December 31, 2006, the expiration periods of the gross and netundeveloped acreage:
| ** **                   | ** ** | **Undeveloped Acreage** | ** ** |
|------------------------------|------------|------------------------------|------------|
| ** **                   | ** ** | ** **                   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                   | ** ** | **United States**       | ** ** | **Indonesia** | ** ** | **Australia** | ** ** |
| ** **                   | ** ** | **Gross**                    | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Twelve months  ended         |       |                         |       |   |   |   |   |   |   |   |   |   |   |
| December 31,  2007           |       | 2,135                        |       | 2,135 |   | 900,000 |   | 108,000 |   | — |   | — |   |
| December 31, 2008            |       | 123,691                      |       | 123,691 |   | — |   | — |   | 530,896 |   | 160,216 |   |
| December 31,  2009           |       | 526                          |       | 526 |   | — |   | — |   | — |   | — |   |
| December 31,  2010           |       | 44                           |       | 44 |   | — |   | — |   | — |   | — |   |
| December 31,  2011 and later |       | 441                          |       | 441 |   | — |   | — |   | — |   | — |   |
|                         |       |                         |       |   |   |   |   |   |   |   |   |   |   |
| Total                        |       | 126,837                      |       | 126,837 |   | 900,000 |   | 108,000 |   | 530,896 |   | 160,216 |   |

 

**Volumes, Pricesand Production Costs**

Substantially allof our production is derived from our Madisonville Project in Madison County,Texas. The following table sets forth information with respect to ourproduction volumes, average prices received and average production costs forthe periods indicated:
| ** **                | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|---------------------------|------------|--------------------------------------------|------------|
| ** **                | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| Production:               |       |                                       |       |   |   |   |   |
| Natural gas (MMcf)        |       | 2,229                                      |       | 1,991 |   | 2,317 |   |
| Natural gas (MMcfd)       |       | 6.81                                       |       | 5.46 |   | 6.35 |   |
|                      |       |                                       |       |   |   |   |   |
| Average Sales  Prices (1) |       |                                       |       |   |   |   |   |
| Natural gas ($per Mcf)    |       | $                                          | 3.01       |   | $ | 4.01 |   | $ | 2.51 |   |
|                      |       |                                       |       |   |   |   |   |
| Lease Operating  Expense  |       |                                       |       |   |   |   |   |
| ($per Mcf)                |       | $                                          | 0.72       |   | $ | 0.44 |   | $ | 0.34 |   |

----

(1)    Representssales price realized net of treatment costs.

**BusinessRisks** and Other Special Considerations

Refer to “Risk Factors” in this report for adiscussion of business risks and other special considerations.

**Item 3. *Legal Proceedings***

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

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

Not applicable.

 

39

----

**PART II**

**Item 5.**          ***Market for the Registrant’s CommonEquity, Related Shareholder Matters and Issuer Purchases of Equity Securities***

 

On February 15,2007, our common stock commenced trading on the American Stock Exchange underthe symbol “GPR”.   Our common stockpreviously traded in the United States over-the-counter market in the PinkSheets under the symbol “GPRC”. Our common stock is also listed on the TorontoStock Exchange under the symbol “GEP.s”.  Those shares of our common stock which trade on the Toronto StockExchange may not presently be purchased by United States persons or persons inthe United States pursuant to SEC Regulation S. On March 28, 2007, the lastreported sale prices for our common stock on the American Stock Exchange andToronto Stock  were  $4.95 and $2.80, respectively. The followingtable sets forth the high and low sale prices of our common shares as reportedon the American Stock Exchange and the Toronto Stock Exchange and bid prices asquoted in the United States in the “pink sheets” over-the-counter market forthe periods presented. Prior to the first quarter of 2006, there was no tradingmarket for our common shares.
| ** **                            | ** ** | **American Stock** | ** ** | **Toronto Stock** | ** ** | ** **                     | ** ** | ** ** | ** ** |
|---------------------------------------|------------|-------------------------|------------|------------------------|------------|--------------------------------|------------|------------|------------|
| ** **                            | ** ** | **Excchange **(1)  | ** ** | **Excchange **(2) | ** ** | **U.S. Pink Sheets** | ** ** |
| ** **                            | ** ** | **High**                | ** ** | **Low**                | ** ** | **High**                       | ** ** | **Low**    | ** ** | **High** | ** ** | **Low** | ** ** |
| **2007**                              | ** ** | ** **              | ** ** | ** **             |       |                           |       |       |       |   |   |   |   |
| First Quarter  through March 28, 2007 |       | 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 |   |

----

(1)             Ourcommon stock commenced trading on the American Stock Exchange on February 15,2007.

(2)             Ourcommon stock is quoted 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, 2007, there were 494 holders of recordof our common shares.

Over-the-counter market quotations reflectinter-dealer prices, without retail mark-up, mark-down or commission, and maynot necessarily represent actual transactions.

For the year theyear ended December 31 2006, the number of unoptioned shares available at thebeginning and at the close of the year for the granting of options under ouroption plan(s) was as follows:

 

|                   | ** ** | **Number of**                | ** ** |
|-------------------|------------|-----------------------------------|------------|
| ** **        | ** ** | **securities**                    | ** ** |
| ** **        | ** ** | **remaining available**      | ** ** |
| ** **        | ** ** | **for future issuance** | ** ** |
| ** **        | ** ** | **under equity**             | ** ** |
| ** **        | ** ** | **compensation plans**       | ** ** |
|              | ** ** | ** **                        | ** ** |
| January 1, 2006   |       | 1,124,750                         |       |
| December 31, 2006 |       | 994,750                           |       |

 

Therewere no changes in the exercise price of outstanding options throughcancellation or reissuance or otherwise.

**Dividends**

On March 28, 2007, all outstanding shares of Series AA8% Convertible Preferred Stock converted to common shares. Dividends on SeriesAA preferred stock are no longer payable. The holders of Series AApreferred stock were entitled to receive ratably such cash dividends, as weredeclared from time to time by the board of directors out of funds legallyavailable therefor and, when declared, dividends were paid at the rate of $0.28per share per annum, paid on a calendar quarter basis. Prior to the conversion,we had declared and paid dividends on a quarterly basis with respect to alloutstanding shares of Series AA preferred stock at the rate of $0.28 pershare per year from the time the Series AA stock was issued. 

The holders of our common stock shall be entitled toreceive ratably such lawful dividends as may be declared by the Board ofDirectors. We have never paid any dividends, whether cash or property, on ourcommon stock. For the foreseeable future it is anticipated that any earningswhich may be generated from our operations will be used to finance our growthand that dividends will not be paid to common stockholders. 

40

----

We have never paid any dividends, whether cash orproperty, on our common stock. No dividend on our common stock may be paidunless, at the time of such payment, all accrued dividends on ourSeries AA Preferred Stock have been paid. Dividends on Series AA preferredstock are no longer payable since all of which converted to common stock onMarch 28, 2007. The holders of our common stock shall be entitled to receiveratably such lawful dividends as may be declared by the Board of Directors. Forthe foreseeable future it is anticipated that any earnings which may begenerated from our operations will be used to finance our growth and thatdividends will not be paid to common stock shareholders.

**Recent Sales of Unregistered Securities**

During the year ended December 31, 2006, we sold the followingsecurities without registration under the Securities Act:

OnJanuary 31, 2006, we issued a $1,000,000 8% unsecured promissory note dueJanuary 31, 2007 to one accredited investor. The private placementissuance of the unsecured promissory note was exempt from the registrationrequirements of the Securities Act pursuant to Section 4(2) of the SecuritiesAct and Rule 506 of Regulation D. The investor in the private placement was anaccredited investor, as defined in Rule 501(a). We did not accomplish the offeror sale of the securities sold in the private placement through any manner ofgeneral solicitation or general advertising. We made available to the investor,prior to purchase, the opportunity to ask questions and receive answersconcerning the terms and conditions of the private placement.

In February 2006, we issued 927,314 Common Sharesfor proceeds of $3,245,600 as follows:
| SHARES  | ** ** | **PRICE PER  SHARE** | ** ** | **FUNDS** | ** ** | **ISSUANCE DATE** | ** **        |
|---------|------------|---------------------------|------------|-----------|------------|------------------------|-------------------|
| 285,714 |       | 3.50                      |       | $         | 1,000,000  |                   | February  1, 2006 |   |
| 428,572 |       | 3.50                      |       | 1,500,000 |       | February  6, 2006      |              |
| 6,743   |       | 3.50                      |       | 23,600    |       | February  15, 2006     |              |
| 71,429  |       | 3.50                      |       | 250,000   |       | February  15, 2006     |              |
| 6,283   |       | 3.50                      |       | 22,000    |       | February  15, 2006     |              |
| 71,429  |       | 3.50                      |       | 250,000   |       | February  15, 2006     |              |
| 28,572  |       | 3.50                      |       | 100,000   |       | February  15, 2006     |              |
| 28,572  |       | 3.50                      |       | 100,000   |       | February  15, 2006     |              |
| 927,314 |       |                      |       | $         | 3,245,600  |                   |              |   |

 

Theseshares were issued to eight accredited investors. The private placement wasexempt from the registration requirements of the Securities Act pursuant toSection 4(2) of the Securities Act and Rule 506 of Regulation D. Each of theinvestors in the private placement was either an accredited investor, asdefined in Rule 501(a), or one we reasonably believed to be. The purchase agreementsigned by each 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 each 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 each investor, prior to purchase, theopportunity to ask questions and receive answers concerning the terms andconditions of the private placement.

OnMarch 30, 2006, we issued 3,730,021 common shares at an issue price of$3.50 per common share and 519,500 common shares issued on a “flow-through”basis under the *Income Tax Act*(Canada) at an issue price of $3.85 per common shares for aggregate grossproceeds of $15,055,149. The sale of common shares was conducted(a) outside the United States pursuant to the exemption fromregistration provided by Regulation S of the Securities Act, and(b) within the United States to six qualified institutional buyerspursuant to Rule 144A. The offering of common shares was underwritten byDundee Securities Corporation and Westwind Partners Inc. Total underwritingdiscounts and commissions of $1,053,860 were paid to the underwriters inconnection with the sale of common shares.

OnDecember 31, 2006, we issued 75,000 shares of common stock pursuant to anexercise of stock warrants at $2.00 per share for proceeds of $150,000. Theseshares were issued to three accredited investors. The private placement wasexempt from the registration requirements of the Securities Act pursuant toSection 4(2) of the Securities Act and Rule 506 of Regulation D. Each ofthe investors in the private placement was either an accredited investor, asdefined in Rule 501(a), or one we reasonably believed to be. The purchaseagreement signed by each investor contained customary and appropriaterepresentations and warranties regarding the investor’s status as an accreditedinvestor, and that the investor was acquiring the securities for his or her ownaccount and not with a view to resale or distribution. It also containedquestions further attesting to his or her status as an accredited investor. Inaddition, we did not accomplish the offer or sale of the securities sold in theprivate placement through any manner of general solicitation or generaladvertising. Moreover, it was disclosed to each investor prior to sale that,except as otherwise may be provided in any registration rights granted to himor her, the securities purchased would not be registered under the SecuritiesAct and could therefore not be resold unless first registered under theSecurities Act or an exemption from registration was available. We placed alegend on each certificate representing the securities sold stating that thesecurities have not been registered under the Securities Act and furthersetting forth customary and appropriate restrictions on the transferability ofthe securities. Finally, we made available to each investor, prior to purchase,the opportunity to ask questions and receive answers concerning the terms andconditions of the private placement.

**Use of Proceeds**

Our registration statementon Form S-1 (Reg. No. 333-135485) registered up to 16,499,991 shares of ourcommon stock, no par value per share, including 5,943,105 shares of commonstock issuable upon exercise of warrants and options, for resale by sellingshareholders. The registration statement was declared effective by theSecurities and Exchange Commission on February 8, 2007. The offering commencedon February 8, 2007 and has not terminated. We will not receive any proceedsfrom the sale of our common stock by the selling shareholders under theregistration statement; however if all warrants and options to acquire ourcommon stock being registered thereunder are exercised, we will realize cashproceeds of approximately $14,019,681, which we expect to use for generalworking capital purposes and the drilling of wells in our Texas, Alaska, Californiaand Indonesian prospects.

If less than the $14,019,681proceeds are realized from the exercise of such warrants and options, theproceeds will be spent in the following order of priority:

1.    Alaska Cook Inlet Project, up to approximately $3.0 million willbe expended for the drilling of pilot program wells.

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

3.    General working capital.

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

**Item 6. *Selected Consolidated Financial Data***

The following selected consolidated financial datashould be read in conjunction with “Management’s Discussion and Analysis ofFinancial Condition and Results of Operations” and our consolidated financialstatements and the related notes to those statements included elsewhere in thisreport. The consolidated statements of operations data for the years endedDecember 31, 2004, 2005 and 2006 and the balance sheet data as ofDecember 31, 2005 and 2006 are derived from our audited consolidated financialstatements included elsewhere in this report. The consolidated statements ofoperations data for the years ended December 31, 2002 and 2003 and thebalance sheet data as of December 31, 2002, 2003 and 2004 are derived fromour audited consolidated financial statements not included in this report.   Historical results are not necessarilyindicative of the results to be expected in the future, and the results for theyears presented should not be considered indicative of our future results ofoperations.

41

----

 
| ** **                                                 | ** ** | **For The Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Consolidated  Statement of Operations:**                 |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Revenues**                                               |       | $                                                             | 6,716,360  |   | $ | 7,975,990 |   | $ | 5,825,072 |   | $ | 2,452,648 |   | $ | 21,659 |   |
| **Lease operating expense**                                |       | 1,602,932                                                     |       | 878,176 |   | 780,237 |   | 582,889 |   | 19,955 |   |
| **General and administrative**                             |       | 2,347,447                                                     |       | 1,551,747 |   | 1,963,649 |   | 1,259,269 |   | 856,491 |   |
| **Net profits expense**                                    |       | 632,708                                                       |       | 856,837 |   | 579,590 |   | 225,869 |   | — |   |
| **Impairment expense**                                     |       | 38,849                                                        |       | — |   | 2,038,422 |   | 473,496 |   | — |   |
| **Depreciation and depletion expense**                     |       | 2,406,612                                                     |       | 1,832,693 |   | 2,077,004 |   | 798,555 |   | 5,138 |   |
| **Earnings (loss) from operations**                        |       | (312,188                                                      | )          | 2,856,537 |   | (1,613,830 | ) | (887,430 | ) | (859,925 | ) |
| **Net income (loss)**                                      |       | (482,406                                                      | )          | 2,640,471 |   | (2,077,615 | ) | (1,684,692 | ) | (1,284,480 | ) |
| **Net income (loss) attributable  to common shareholders** |       | $                                                             | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) | $ | (1,943,565 | ) | $ | (1,299,700 | ) |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Earnings  (Loss) per Share:**                            |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Basic**                                                  |       | $                                                             | (0.04      | ) | $ | 0.10 |   | $ | (0.14 | ) | $ | (0.12 | ) | $ | (0.09 | ) |
| **Diluted**                                                |       | $                                                             | (0.04      | ) | $ | 0.09 |   | $ | (0.14 | ) | $ | (0.12 | ) | $ | (0.09 | ) |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Weighted  Average Number of Common**                     |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Shares Outstanding:**                                    |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Basic**                                                  |       | 25,990,868                                                    |       | 20,890,841 |   | 18,901,607 |   | 16,497,898 |   | 14,465,177 |   |
| **Diluted**                                                |       | 25,990,868                                                    |       | 24,001,888 |   | 18,901,607 |   | 16,497,898 |   | 14,465,177 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Production  Data:**                                      |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Natural gas (Mcf)**                                      |       | 2,229,059                                                     |       | 1,991,105 |   | 2,316,895 |   | 1,217,327 |   | 14,737 |   |
| **Natural gas (Mcfd)**                                     |       | 6,107                                                         |       | 5,455 |   | 6,348 |   | 3,335 |   | 40 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Production  Data reduced by net profits interests:**     |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Natural gas (Mcf)**                                      |       | 1,950,427                                                     |       | 1,742,217 |   | 2,027,283 |   | 1,065,161 |   | 12,895 |   |
| **Natural gas (Mcfd)**                                     |       | 5,344                                                         |       | 4,773 |   | 5,554 |   | 2,918 |   | 35 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Average  Sales Prices:**                                 |       |                                                          |       |   |   |   |   |   |   |   |   |
| **Natural gas (per Mcf)**                                  |       | $                                                             | 3.01       |   | $ | 4.01 |   | $ | 2.51 |   | $ | 2.01 |   | $ | 1.47 |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |
|                                                       |       |                                                          |       |   |   |   |   |   |   |   |   |

 

42

----

 
| ** **                            | ** ** | **For the Years Ended December 31,** | ** **  |
|---------------------------------------|------------|---------------------------------------------------------------|-------------|
| ** **                            | ** ** | **2006**                                                      | ** **  | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| **Balance  Sheet Information:**       |       |                                                          |        |   |   |   |   |   |   |   |   |
| Current assets                        |       | $                                                             | 2,366,081   |   | $ | 1,718,893 |   | $ | 1,579,388 |   | $ | 2,967,626 |   | $ | 832,255 |   |
| Total assets                          |       | 39,061,478                                                    |        | 25,014,826 |   | 22,771,411 |   | 18,875,981 |   | 13,652,187 |   |
| Current  liabilities                  |       | 3,604,342                                                     |        | 3,574,466 |   | 7,582,377 |   | 1,471,248 |   | 2,383,725 |   |
| Long-term  liabilities                |       | 48,842                                                        |        | 26,641 |   | 24,705 |   | 5,242,554 |   | 4,853,409 |   |
| Redeemable  Series AA Preferred Stock |       | 5,924,068                                                     |        | 5,924,068 |   | 5,924,068 |   | 5,924,068 |   | 768,283 |   |
| Deficit                               |       | $                                                             | (10,393,985 | ) | $ | (9,382,179 | ) | $ | (11,493,253 | ) | $ | (8,886,275 | ) | $ | (6,942,710 | ) |

 

**Item 7. *Management’s Discussion and Analysis of FinancialCondition 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. Factors that could cause or contribute to suchdifferences include, but are not limited to, market prices for natural gas andoil, economic and competitive conditions, regulatory changes, estimates ofproved reserves, potential failure to achieve production from developmentdrilling projects, capital expenditures and other uncertainties, as well asthose factors discussed below and elsewhere in this report, particularly in “RiskFactors” and “Cautionary Notes Regarding Forward Looking Statements”, all ofwhich are difficult to predict and which expressly qualify all subsequent oraland written forward-looking statements attributable to us or persons acting onour behalf. In light of these risks, uncertainties and assumptions, the forwardlooking events discussed may not occur. We do not have any intention orobligation to update forward-looking statements included in this report afterthe date of this report, except as required by law.*

43

----

**Overview**

We are an oil and gas company in the business ofexploring and developing oil and natural gas reserves on a worldwide basis. Sinceinception, we have conducted leasehold acquisition, exploration and drillingactivities on our North American, Australian and Indonesian prospects. Theseprojects currently encompass approximately 1.56 million gross (396,080net) acres, consisting of mineral leases, production sharing contract 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 significant cash inflows until 2003 were the recovery of capital investedin projects through sale or other divestiture of interests in oil and gasprospects to industry partners.

Since 2003, substantially all of our revenue has beengenerated from natural gas sales derived from the Magness #1 well in theMadisonville Field in East Texas under spot gas purchase contracts at marketprices. Natural gas sales from the Madisonville Field are expected to accountfor substantially all of our revenues for 2007. We expect the majority of ourcapital expenditures in 2007 to be the costs of drilling and completing wellsin the Madisonville Field.
| ** **                                                 | ** ** | **For The Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                       |       |                                                          |       |   |   |   |   |
| **Consolidated  Statement of Operations:**                 |       |                                                          |       |   |   |   |   |
| **Revenues**                                               |       | $                                                             | 6,716,360  |   | $ | 7,975,990 |   | $ | 5,825,072 |   |
| **Lease operating expense**                                |       | 1,602,932                                                     |       | 878,176 |   | 780,237 |   |
| **General and administrative**                             |       | 2,347,447                                                     |       | 1,551,747 |   | 1,963,649 |   |
| **Net profits expense**                                    |       | 632,708                                                       |       | 856,837 |   | 579,590 |   |
| **Impairment expense**                                     |       | 38,849                                                        |       | — |   | 2,038,422 |   |
| **Depreciation and depletion expense**                     |       | 2,406,612                                                     |       | 1,832,693 |   | 2,077,004 |   |
| **Earnings (loss) from operations**                        |       | (312,188                                                      | )          | 2,856,537 |   | (1,613,830 | ) |
| **Net income (loss)**                                      |       | (482,406                                                      | )          | 2,640,471 |   | (2,077,615 | ) |
| **Net income (loss) attributable  to common shareholders** |       | $                                                             | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) |

 

**Revenueand Operating Trends in 2007**

As discussed in “Properties — Texas — MadisonvilleProject,” in order to produce the gas reserves from the Rodessa Formation, wedeveloped an onsite plan to treat and remove impurities from the MadisonvilleProject natural gas in order to meet pipeline-quality specifications. In2003, the construction and installation of a natural gas treatment plant with adesigned capacity of 18 MMcf/d and associated pipeline and gathering facilitieswere completed.  The treatment plant andassociated pipeline and gathering facilities are owned by an unaffiliated thirdparty.

The natural gas plant is currently treatingapproximately 16.5 MMcf/d of inlet natural gas from our Magness and FanninWells.  These wells accounted forapproximately 99% of our revenue in 2006.

In 2005 we secured a commitment from MGP to installand make operational additional treating facilities capable of treating 50MMcf/d, which combined with the capacity of the current in-service treatingfacilities will represent a total designed treating capacity of 68 MMcf/d forthe Madisonville treatment plant.  Ouragreement with MGP provides that the newly installed gas treatment facilitieswill be 100% electrically driven when the treatment capacity is expanded.Currently, the existing in-service treatment plant utilizes some of the naturalgas produced and delivered from our well(s). The conversion to 100% electricityon the expanded portion of the treatment plant is expected to reduce shrinkageof our natural gas that occurs in the treating process.  

44

----

Representatives of MGPhave indicated that they expect the full expansion of the treatment plant to 68MMcf/d capacity can be in place and operational by the second quarter of 2007.

Upon completion of the plant expansion, we expect toproduce our Fannin Well at a higher rate as the well rate has previously beenrestricted due to capacity limitations in the gas treatment plant.  We also expect to commence production fromour Mitchell Well, which is currently shut-in awaiting the plant expansion.  In addition, later in 2007 we expect tofracture stimulate the Wilson Well, and provided such stimulation issuccessful, we will place the Wilson Well on production.

In addition, our contract with MGP provides that forthe first 18,000 Mcf/d of gas measured and delivered to the inlet flange of thegas treatment plant, we will pay MGP a treating fee of $1.50 per Mcf (this feeis presently $1.55 per Mcf adjusted for inflation).  For any gas volumes in excess of 18,000 Mcf/dof gas delivered to the inlet flange of the gas treatment plant, the treatingfee we pay to MGP is reduced from $1.50 to $1.10 per Mcf ($1.14 per McfAdjusted for inflation).  We record ourrevenues net of these treating fees. Thus, if we are able to increase our inlet production volumes over 18MMcf/d on a sustained basis, we expect to experience a disproportionatelyhigher increase in revenue due to lower average treating fees per Mcf.

While there can be no assurance, the (i) higherproduction rates from our wells, combined with the (ii) potentially reducedshrinkage rates and (iii) lower average treating fees per Mcf, may result inhigher net production and increased revenue during 2007 as compared to 2006 andprior periods.

**Industry Overview for the Year Ended December 31,2006**

The year 2006 saw softening natural gas prices. The Houston Ship Channelprice, the index price prevailing in the locale of our Madisonville Project inMadison County, Texas, as quoted in Gas Daily as of December 29, 2006, was$5.40 versus $7.80 as of December 31, 2005. In the year of 2005, thenatural gas prices were strong as a result of hurricane related supplydisruptions and generally tight supplies of natural gas in theUnited States. Availability of capital, particularly equity capital forjunior oil and natural gas companies, continued to show improvement in 2006. Asa result of the initial public offering in Canada in March 2006, we were ableto drill two wells in our Madisonville Project during 2006.

**Company Overview in 2006**

Our net loss aftertaxes for the year ended December 31, 2006 was $1,011,806.  From ourinception, through mid-2003, we only received nominal revenues from our oil andnatural gas activities, while incurring substantial acquisition and explorationcosts and overhead expenses which have resulted in an accumulated deficitthrough December 31, 2006 of $10,393,985. Commencing in May 2003, weplaced our Madisonville Project into production. Substantially all of our oiland natural gas sales for the year ended December 31, 2006 were derivedfrom our Madisonville Project, from two producing wells, the UMC Ruby Magness#1 well (the “Magness Well”) and the Angela Farris Fannin #1 well (the FanninWell”).

**Comparison of Results of Operations for the twelveended December 31, 2006 and 2005**

During the twelve months ended December 31, 2006, we had oil and naturalgas revenues of $6,716,360. Our net production was 2,229,059 thousand cubicfeet (Mcf) of natural gas at an average price of $3.01 per Mcf.  During the twelve months ended December 31,2005, we had oil and natural gas revenues of $7,975,990.  Our net production for the twelve monthsended December 31, 2005 was 1,991,105 Mcf at an average price of $4.01 per Mcf.Revenues decreased in the twelve months ended December 31, 2006 as compared tothe prior year period due to lower gas prices in spite of 12% 

45

----

higherproduction volumes.  Prices wereapproximately 25% lower for the twelve months ended December 31, 2006 versusthe same period in 2005.

During the twelve months ended December 31, 2006, we incurred leaseoperating expenses of $1,602,932. Our average lifting cost for the 2006 periodwas $0.72 per Mcf. During the twelve months ended December 31, 2005, weincurred lease operating expenses of $878,176. Our average lifting cost for the2005 period was $0.44 per Mcf. The higher average lifting cost in 2006 was dueto higher lease operating costs and production taxes attributable to the Fannin#1 well. The primary reason for the increase in average lifting cost per Mcfwere increases in production costs related to the Fannin #1 well which wasplaced in production in March 2006. The production for the Magness and theFannin wells is at present limited to the current treatment plant’s capacity ofup to 18,000 Mcf/d.  Therefore, theproduction from the Fannin #1 and the Magness #1 wells is limited to a ratethat is below the combined productive flow capability of the wells.  A majority of the lease operating costs arefixed costs such as chemical treatments for the wells, insurance, ad valoremtax, and salaries paid to the field personnel. During the twelve months endedDecember 31, 2006, the total lease operating costs for the Magness #1 well were$752,924 versus $878,176 in the same period of 2005. The net production of theMagness #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 Faninn #1 well in 2006 whereas in thecomparable 2005 period it did not.  As aresult, the average lifting cost for Magness #1 well was $0.65 per Mcf for thetwelve months ended December 31, 2006 versus $0.44 per Mcf in the same periodof 2005.  The Fannin #1 well’s averagelifting cost was higher than the Magness #1 well due mainly to the severancetax of $230,600 which was incurred on the Fannin #1 well for the twelve monthsended December 31, 2006.  The Magness #1 wellis exempt from the severance tax.  Theaverage lifting cost for the Fannin #1 well was $0.79 per Mcf for the twelvemonths ended December 31, 2006.

During the twelve months ended December 31, 2006, we incurred netprofits interest expense of $632,708 associated with the Magness and Fanninwells as compared to $856,837 during the twelve months ended December 31, 2005.The 26% decrease resulted from lower net revenues from the wells in the twelvemonths ended December 31, 2006 versus 2005. The net profits interest is12.5% of the net operating profits from ourMagness and Fannin wells.

General and administrative expenses for the twelve months ended December31, 2006 were $2,347,447 compared to $1,551,747 for the twelve months endedDecember 31, 2005. This represents a $795,700 increase over the prior yearperiod due to primarily to:

1.               $198,000 of stock based compensation,

2.               a $265,000 increase in directors and officersliability insurance,

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

4.               $285,000 in legal, audit, printing and filing feesassociated with the S-1 registration statement which was prepared for theresale of some of our common stock.

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

46

----

Depreciation, depletion andamortization expense (“DD&A”) for the twelve months ended December 31, 2006was $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 was due tohigher net production in the twelve months period of 2006 and an increase inthe amount of capitalized cost in the U.S. full cost pool.

Loss fromoperations totaled $312,188 for the twelve months ended December 31, 2006 ascompared to income from operations of $2,856,537 for the twelve months endedDecember 31, 2005. The decrease in the income from operations was due primarilyto lower gas prices, higher lease operating expenses, and higher G&Aexpenses.

Other income for the twelve months ended December 31, 2006 and 2005consisted of interest income in the amount of $198,050 and $18,969,respectively. The reason for the increased interest income was higher averagecash and cash equivalent balances during 2006 period as compared to 2005 periodresulting from net proceeds received from common stock offerings completed byus in 2006.

During the twelve months ended December 31, 2006 and 2005, we incurredinterest expense of $306,682 and $217,768, respectively. The higher interestexpense in the current year period was due to $194,691 in expense related tothe amortization of debt issuance costs in connection with a debt financing inJanuary 2006 consisting of: (i) the fair market value assigned to common stockwarrants issued, and (ii) a loan origination fee paid.

Net loss beforetaxes for the twelve months ended December 31, 2006 was $420,820 as compared tonet income 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 taxexpense for the twelve months ended December 31, 2006 was $61,586 compared to$17,267 in the same period of 2005. The increased income tax expense was due to2005 alternative minimum tax paid in 2006.

**Industry Overviewfor the Year Ended December 31, 2005**

The year 2005 saw continued strong natural gas prices asa result of hurricane related supply disruptions and generally tight suppliesof natural gas in the United States. 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 31, 2005, was $7.80versus $5.82 as of December 31, 2004. Availability of capital,particularly equity capital for junior oil and natural gas companies, continuedto show improvement in 2005, and in 2005, we raised $4,727,824 net of issuancecosts through equity financing transactions. As a result, and through the saleof one of our Indonesian property interests, we were able to repay ourindebtedness of $1.7 million to various creditors and improve our capitalposition during 2005.

**During 2005, we received a weightedaverage net price of $4.01 per mcf of gas sold. As further discussed under “Properties—Texas—MadisonvilleProject”, we receive revenue for our gas sales net of certain costs to treatand transport the gas. The weighted average gross price during 2005, prior tothe deduction of the treating and transportation costs, was $6.81. Thiscompares to $7.80 which was the price prevailing on the last day of 2005.**

 

47

----

**Company Overview in 2005**

Our net income after taxes for the year endedDecember 31, 2005 was $2,640,471. From our inception to 2003, we onlyreceived nominal revenues from our oil and natural gas activities, whileincurring substantial acquisition and exploration costs and overhead expenseswhich resulted in our sustaining an accumulated deficit throughDecember 31, 2005 of $9,382,179. We placed our Madisonville Project intoproduction in May 2003. Substantially all of our oil and natural gas salesfor the year ended December 31, 2005 were derived from our MadisonvilleProject, from one producing well, the Magness #1 well.

**Comparison of Results of Operations for the twelvemonths ended December 31, 2005 and 2004**

During the year ended December 31, 2005, we hadoil and natural gas revenues of $7,975,990. Our net production was 1,991,105thousand cubic feet (Mcf) of natural gas at an average price of $4.01 per Mcf.During the year ended December 31, 2004, we had oil and natural gasrevenues 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. This is because average prices in 2005 were60% higher than 2004, more than offsetting the 14% drop in production from 2004to 2005. Production was lower due to normal declines associated with theproduction of reserves****from theMagness #1 well.

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

During the year ended December 31, 2005, weincurred net profits interest expense of $856,837 associated with the MagnessWell compared to $579,590 during the year ended December 31, 2004. Theincrease resulted from higher revenues associated with the Magness Well in 2005versus 2004.

General and administrative expenses for the year endedDecember 31, 2005 were $1,551,747 compared to $1,963,649 for the yearended December 31, 2004. This represents a $411,902 decrease over theprior year period due to stock based compensation incurred in 2004. During 2004we issued 500,000 shares of our common stock for cash proceeds of $500,000in connection with the exercise of stock options by an officer and director.Concurrent with the exercise of stock options, the officer sold117,647 shares of common stock to us at the estimated fair market valueprice prevailing at that time of $4.25 per share. We recorded compensationexpense of $500,000 in connection with the purchase of stock.

Depreciation, depletion and amortization expense forthe year ended December 31, 2005 was $1,832,693 compared to $2,077,004 inthe year ended December 31, 2004, which amounts represent amortization ofthe U.S. full cost pool for the year ended December 31, 2005 and2004, respectively. The decrease was due to lower net production in 2005 aswell as an upward revision in net proved reserve estimates during the year.

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

48

----

Earnings from operations totaled $2,856,537 for theyear ended December 31, 2005 compared to a loss of $1,613,830 for the yearended December 31, 2004. The increase in the earnings from operations wasdue primarily to higher revenues associated with the Magness Well.

Other income for the year ended December 31, 2005and 2004 consisted of interest income in the amount of $18,969 and $6,548,respectively. The reason for the increase was higher average cash and cashequivalents balances for the 2005 period as compared to 2004.

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

Net income after taxes for the year endedDecember 31, 2005 was $2,640,471 compared to net loss of $2,077,615 forthe year ended December 31, 2004. The increase in net income was primarilydue to higher revenues associated with the Magness Well and theimpairments expense recorded in the previous period.

**Industry Overview for the Year Ended December 31,2004**

The year 2004 saw continued strong natural gas pricesas a result of tight supplies of natural gas in the United States. TheHouston Ship Channel price, the index price prevailing in the locale of theMadisonville Project, as quoted in Gas Daily as of December 30, 2004, was$5.82 versus $5.76 as of December 31, 2003. Availability of capital,particularly equity capital for junior oil and natural gas companies, continuedto show improvement in 2004 and in 2004, we raised $3,479,899 net of issuancecosts through equity financing transactions.

**Revenue Trend in 2004**

The results of operations for the year ended 2004reflected a full year of production revenues from the Madisonville Projectwhere we had one well on production. Substantially all of our oil and naturalgas sales for the year ended December 31, 2004 were derived from ourMadisonville Project in Madison County, Texas.

**Comparison of Results of Operations for the Yearsended December 31, 2004 and 2003**

During the year ended December 31, 2004, we hadoil and natural gas revenues of $5,825,072. Our net production was2,316,895 Mcf at an average price of $2.51 per Mcf. During the year endedDecember 31, 2003, we had oil and natural gas revenues of $2,452,648. Ournet production was 1,217,327 Mcf at an average price of $2.01 per Mcf for2003.

During the year ended December 31, 2004, weincurred lease operating expenses of $780,237. Our average lifting cost forthis period was $0.34 per Mcf. During the year ended December 31, 2003, weincurred lease operating expenses of $582,889. Our average lifting cost forthis period was $0.48 per Mcf. The reason for the significant decrease inaverage lifting cost per Mcf was that the Magness Well experiencedsignificantly higher production volumes in 2004 versus 2003.

During the year ended December 31, 2004, weincurred net profits interest expense of $579,590 associated with the MagnessWell compared to $225,869 in 2003. This was due to higher revenues associatedwith the Magness Well in 2004 versus 2003.

General and administrative expenses for the year endedDecember 31, 2004 were $1,963,649 compared to $1,259,269 for 2003. Thisrepresents a $704,380 or a 56% increase over the prior year period. The primaryreason for the increase was a $500,000 non-cash charge associated withstock-based compensation. During 2004 we issued 500,000 shares ofour common stock for cash proceeds of $500,000 in connection with the exerciseof stock options by an officer and director.

49

----

Concurrent with the exercise of stock options, theofficer sold 117,647 shares of common stock to us at the estimated fairmarket value price at that time of $4.25 per share. We recorded compensationexpense of $500,000 in connection with the purchase of stock. The balance ofthe increase was due to additional employees and salary increases.

Depreciation, depletion and amortization expense forthe year ended December 31, 2004 was $2,077,004 compared to $798,555 for2003, substantially all of which represents amortization of the U.S. full costpool for the respective periods. The increase was due to higher depletionexpense associated with the Magness Well due to higher production in 2004versus 2003.

For the years ended December 31, 2004 and 2003,we incurred impairment expense of $2,038,422 and $473,496, respectively. The2004 impairment write-downs were associated with the Canadian and Australiancost pools while the 2003 impairment write-down was due to the expiration ofPermit #386 in Australia. We expensed the costs of drilling dry holes in Canadaand Australia during 2004. The impairment charge in 2003 relates to the costscapitalized in connection with an exploration permit which expired during 2003.

Loss from operations totaled $1,613,830 for the yearended December 31, 2004 compared to a loss of $887,430 for 2003. Theincrease in the loss from operations was due to higher impairments anddepletion expenses.

Other income for the year ended December 31, 2004and 2003 consisted of interest income in the amount of $6,548 and $4,769,respectively. The reason for the increase was higher average cash and cashequivalents balances for the 2004 period as compared to 2003.

During the years ended December 31, 2004 and2003, we incurred interest expense of $402,958 and $802,031, respectively. Thehigher interest expense in the prior year period was due to short-termborrowings which were incurred to drill and complete the injection well andequipment for production of the Magness Well. In 2004, we incurred debtconversion expense of $67,375 associated with the conversion of $1,347,500 oflong-term debt to equity.

Net loss after taxes for the year endedDecember 31, 2004 was $2,077,615 compared to a loss of $1,684,692 for theyear ended December 31, 2003. The increase in net loss was primarily dueto higher impairments and depletion.

**Recent Developments**

On September 29, 2006, we sold to CNPC 70% of ourshareholding in C-G Bengara and our interest in the Bengara Block, reducing ourinterest from 40% to 12%. CNPC is a wholly owned subsidiary of CNPC (Hong Kong)Ltd. who is party to the agreements as guarantor. CNPC (Hong Kong) Ltd. is apublicly held company based in Hong Kong and its shares trade on the Hong KongStock Exchange under the listing number 0135.HK. CNPC (Hong Kong) Ltd. is a 52%owned subsidiary of the China National Petroleum Company based in Beijing, PRC.See “Properties—Description of Properties—Indonesia.”

During 2006, ourwholly-owned subsidiary, Redwood Energy Production, L.P. (“**Redwood LP**”),was a defendant in two lawsuits, titled the “Miller Lawsuit” and “Redwood vs.George Mejlaender.” To avoid the costs of continued litigation, RedwoodLP, the Miller plaintiffs and the Mejlaender plaintiffs, through mediation,entered into a binding settlement agreement on June 1, 2006 to resolve allof their disputes. Under the terms of thesettlement, Redwood LP paid the plaintiffs $1,100,000 in cash upon the closingof the settlement, executed a 6% promissory note in favor of the Miller andMejlaender plaintiffs with a December 29, 2006 maturity date in the amount of$900,000 secured by Redwood LP’s interest in the Magness Well, and assigned theplaintiffs overriding royalty interests of 2% in the Magness Well, 2% in theFannin Well, 0.75% in the Wilson Well, and agreed to assign 0.5%, 0.3% and 0.2%in the first, second and third wells, respectively, in the event these wellsare drilled and completed by Redwood LP below the Rodessa-Sligo Interval. Theplaintiffs have assigned to Redwood LP any and all ownership interests they mayhave had in the

50

----

Madisonville Prospect below the top of theRodessa-Sligo Interval and conveyed all of their overriding royalty interestsin the Madisonville Prospect in the Rodessa-Sligo Interval and below. Thecombined $2.0 million has been recorded to evaluated oil and gas properties. OnDecember 28, 2006, we paid the 6% promissory note, plus accrued interest, infull.

In February 2007, we borrowed $900,000 pursuant to three promissorynotes bearing interest at 8% per annum. The notes mature on October 31, 2007. In connection with these notes, we paid loan origination fees totaling$27,000 and issued three year warrants exercisable to to purchase 45,000 sharesof our common stock at $3.50 per share which expire in February 2009.

In February 2007, we received an extension of the maturity date of ourpromissory note payable to Pine Hill Capital, LLC to October 31, 2007.  Inconnection with the extension, we paid a loan extension fee of $30,000 andgranted a three-year warrant to purchase 50,000 shares of our common stock at$3.50 per share.  Under our agreementwith Pine Hill, we agreed to pay the entire remaining principal balance of ournote, which is $1,000,000 as of March 30, 2007, plus accrued interest, on October31, 2007.  If we do not repay the note byOctober 31, 2007, or receive an extension, continuing the terms of our originalloan agreement with Pinehill, we are required to dedicate 5% of our net cashflow from the Madisonville Project located in Madison County, Texas, toward theunpaid principal and all accrued & unpaid interest on the note, until allsuch amounts are paid-in-full.  Net cashflow means our gross revenues, less royalties, production taxes & netprofits interest expense.

In February 2007, Stuart J. Doshi, Presidentand CEO, loaned $100,000 to us pursuant to a promissory note bearing interestat 8% per annum, payable upon demand. We repaid the note plus accrued intereston March 28, 2007.

On June 7, 2006, we loaned $1,000,000 to G. Carter Sednaoui, a 5%shareholder, evidenced by a full-recourse short-term promissory note payable tous with an original maturity date of March 31, 2007.  On March 30, 2007, we extended the maturitydate of the note to June 30, 2007.

On March 28, 2007, all 1,890,710 of our outstandingshares of our Series AA Stock, automatically converted into 1,890,710 shares ofour common stock, no par value per share. Under our Amended and RestatedArticles of Incorporation, and as more fully described in Note 7 to ourConsolidated Financial Statements, the Series AA stock automatically convertsinto common shares on a one-for-one share basis effective the first trading dayafter the reported high selling price for our common shares is at least $5.25per share for any consecutive ten trading days, which condition was met onMarch 27, 2007. As a result of the conversion of our Series AA stock to commonstock on March 28, 2007, dividends on the Series AA Stock ceased accruing onDecember 31, 2006. In 2006, dividends paid on the Series AA Stock totaled$529,400.

**Liquidity and Capital Resources**

We had a working deficit of $1,238,261versus $1,855,573 at December 31, 2006 and December 31, 2005,respectively. Our working capital increased during year ended December 31, 2006due primarily to initial public offering (“IPO”) in Canada in March 2006, whichconsisted of 3,730,021 common shares from our treasury at an issue price of$3.50 per common share and 519,500 common shares issued on a “flow-through”basis under the *Income Tax Act* ofCanada at an issue price of $3.85 per common share for aggregate gross proceedsof $15,055,149. We utilized most of the net proceeds of the offering to funddrilling of wells in the Madisonville Project.

We have historically financed ourbusiness activities through December 31, 2006 principally through issuances ofcommon shares, promissory notes and Common Share purchase warrants in privateplacements and more recently, an initial public offering. These financings aresummarized as follows:
| ** **                                                      | ** ** | **Years Ended**            | ** ** |
|-----------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                      | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** | **December 31, 2004** | ** ** |
|                                                            |       |                            |       |   |   |   |   |
| Proceeds from sale of  Common Shares and warrant exercises, net |       | $                               | 16,717,604 |   | $ | 4,727,824 |   | $ | 3,479,899 |   |
| Payment on preferred  dividends                                 |       | (529,400                        | )          | (529,397 | ) | (529,363 | ) |
| Repayments of  promissory notes                                 |       | —                          |       | (4,781,807 | ) | — |   |
| Proceeds from  promissory notes                                 |       | 1,900,000                       |       | — |   | 2,075,000 |   |
| Payment of loan fee                                             |       | (30,000                         | )          | — |   | (1,158,569 | ) |
| Repayment of promissory  notes                                  |       | (900,000                        | )          | — |   | — |   |
| Deferred offering costs                                         |       | (1,213,789                      | )          | (730,906 | ) | (150,255.00 | ) |
| Purchase of treasury  stocks                                    |       | —                          |       | (592,435 | ) | — |   |
|                                                            |       |                            |       |   |   |   |   |
| Net cash  provided by financing activities                      |       | $                               | 15,944,415 |   | $ | (1,906,721 | ) | $ | 3,716,712 |   |

 

51

----

The net proceeds of our equityfinancings have been primarily invested in oil and natural gas propertiestotaling $16,721,944, $5,602,741 and $9,171,589 for the years endedDecember 31, 2006, 2005 and 2004, respectively.

Our cash balance at December 31,2006 was $734,561 compared to a cash balance of $914,826 at December 31,2005. The change in our cash balance is summarized as follows:
| Cash balance at December 31,  2005            |   | $           | 914,826 |   |
|-----------------------------------------------|--------|-------------|---------|--------|
| Sources of cash:                              |   |        |    |
| Cash provided by  operating activities        |   | 1,601,869   |    |
| Cash provided by  financing activities        |   | 15,944,415  |    |
|                                          |   |        |    |
| Total sources of  cash including cash on hand |   | 18,461,110  |    |
|                                          |   |        |    |
| Uses of cash:                                 |   |        |    |
| Cash used in  investing activities:           |   |        |    |
| Oil and natural  gas property expenditures    |   | (16,721,944 | )       |
| Furniture,  fixtures and equipment            |   | (4,605      | )       |
| (Increase) in  related party notes receivable |   | (1,000,000  | )       |
| Total uses of  cash                           |   | (17,726,549 | )       |
|                                          |   |        |    |
| Cash balance at  December 31, 2006            |   | $           | 734,561 |   |

 

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 “Outlookfor 2007” for a description of our expected capital expenditures for 2007. Ifwe are unable to generate revenues necessary to finance our operations over thelong-term, we may have to seek additional capital through the sale of ourequity or borrowing. As noted in “Recent Developments,” we periodically borrowfunds pursuant to short term promissory notes to finance our activities.

**Contractual Obligations**

A summary of ourcontractual obligations as of December 31, 2006 is provided in thefollowing table:
| ** **                                                                | ** ** | **Payments Due By Period (6)** | ** ** |
|---------------------------------------------------------------------------|------------|----------------------------------------------------|------------|
| ** **                                                                | ** ** | ** **                                         | ** ** | **Less than** | ** ** | ** ** | ** ** | ** ** | ** ** | **More than** | ** ** |
| **Contractual Obligations at December 31, 2006** | ** ** | **Total**                                          | ** ** | **1 year** | ** ** | **1-3 years** | ** ** | **3-5 years** | ** ** | **5 years** | ** ** |
| Operating lease obligations(1)                                            |       | $                                                  | 168,256    |   | $ | 76,856 |   | $ | 91,400 |   | $ | — |   | $ | — |   |
| Production sharing  contract (2)                                          |       | 120,000                                            |       | 120,000 |   | — |   | — |   | — |   |
| Madisonville Field  drilling obligation (3)                               |       | 10,000,000                                         |       | — |   | 10,000,000 |   | — |   | — |   |
| Cook Inlet Alaska work  program (4)                                       |       | 3,568,063                                          |       | — |   | 3,568,063 |   | — |   | — |   |
| Canadian flow-through  shares (5)                                         |       | 2,000,075                                          |       | 2,000,075 |   | — |   | — |   | — |   |
|                                                                      |       |                                               |       |   |   |   |   |   |   |   |   |
| Total                                                                     |       | $                                                  | 15,856,394 |   | $ | 2,196,931 |   | $ | 13,659,463 |   | $ | — |   | $ | — |   |

----

(1)             Leasefor our principal executive office located at One Maritime Plaza,Suite 700, San Francisco, CA 94111.

52

----

(2)             Wehave work program commitments associated with our participation net to our 12%working interest in the Bengara II PSC (production sharing contract) inIndonesia. These work program commitments must be met in order to maintain the productionsharing contract in effect**.**

(3)             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 forcemajeure, including, but not limited to rig availability, requires us tocommence the drilling of a well sufficient to test the Smackover Formation(estimated to be encountered at approximately 18,000 feet) on or beforeSeptember 30, 2008. The commitment is not discretionary.  We have granted MGP a security interest inthe Madisonville Field properties to secure the commitment. The securityinterest shall be subordinated to any third party lender in the event we securefuture debt against the property. MGP granted us a security interest in theMadisonville Field Gas Treatment Plant to secure their obligation to expand thecapacity of the facilities.

(4)             Withinthree years from the date of receipt of assignment of the 100% working interestin the leases in our Cook Inlet Alaska CBM Project, we have the option toconduct a $2.5 million work program consisting of, but not limited to, amultiple test well drilling program on the leases over a three-year period,and, after completion of the work program and an evaluation of the results, toremit the final additional acreage consideration of $10 per acre for the leasesestimated at approximately $1,068,000. The Cook Inlet Option provides that ifwe fail to pay the lease consideration when due, fail to perform the workprogram or otherwise default under the Cook Inlet Option, we shall forfeit ourinterest and reassign the leases to Pioneer with no further liability to us.

(5)             Itis required that we expend $2,000,075 of the proceeds realized from theCanadian offering from the issuance of 519,500 “flow-through” shares towardCanadian exploration expense pursuant to Canadian tax law. Canadian explorationexpense generally means, but is not limited to, the drilling of exploratorywells in Canada. Pursuant to the terms of our agreement with the subscribers ofthe “flow-through” shares, we must renounce the tax deductions which wouldresult from these expenditures and pass the deductions through to the holdersof these shares. We must incur these expenditures by the end of our fiscal yearended December 31, 2007.

(6)             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.

In addition to the above future commitments, our 12%owned subsidiary, C-G Bengara, is subject to prior work commitments for theeight-year period ended December 3, 2006 requiring total expenditures of $24million in the Indonesian contract area known as the Bengara Block. As ofSeptember 30, 2006, C-G Bengara had met approximately $6.3 million of the$24.0 million required expenditures, leaving an approximate $17.7 millionshortfall. BP Migas, the applicable governing authority, has granted a deferralof the prior years’ commitments. On September 29, 2006, we sold to CNPC 70% ofour shareholding in our C-G Bengara subsidiary and our interest in the BengaraBlock, reducing our interest from 40% to 12%. Per the terms of the agreement,CNPC has deposited an $18.7 million earning obligation into a C-G Bengaraaccount jointly controlled by CNPC, Continental and us. The funds are to beused exclusively to pay for 2007 exploration drilling in the 900,000 BengaraBlock in East Kalimantan, Indonesia. The earning obligation funds of $18.7million, together with the $6.3 million previously spent, will satisfy all ofthe past and future work commitments on the Bengara Block. C-G Bengara has fourexploration wells planned, permitted and approved by Indonesian oil and gasregulatory authorities for drilling in 2007. C-G Bengara is

53

----

now preparing plans for conducting the drillingprogram and expects to commence drilling activities in the second quarter of2007.

The above amounts do not include program commitmentsfor our Exploration Permit (EP) 408. The program commitments for EP 408have been substantially met and require no further significant expenditures.

Other than the above commitments, the timing of mostof our capital expenditures is discretionary. We have no material long-termcommitments associated with our capital expenditure plans or operatingagreements. Consequently, we have a significant degree of flexibility to adjustthe level of such expenditures as circumstances warrant. The level of capitalexpenditures will vary in future periods depending on the success we experienceon planned exploratory and appraisal drilling activities, natural gas and oilprice conditions and other related economic and political factors. Accordingly,we have not yet prepared an estimate of capital expenditures for periods beyond2007.

**Income Taxes**

As of December 31, 2006, we had net operating loss (NOL) carryforwardsof approximately $22,932,000 for federal income tax purposes beginning toexpire in 2010 and $10,926,000 for state income tax purposes which began toexpire in 2006.

Asignificant change in our ownership may limit our ability to use these NOLcarryforwards. Statement of Financial Accounting Standards No. 109, *Accounting for Income Taxes*, requires thatthe tax benefit of such net operating loss be recorded as an asset. AtDecember 31, 2006, we had net deferred tax assets of approximately $3.7 millionrelated to the NOL and other temporary differences. We have recorded a fullvaluation allowance of $3.7 million at December 31, 2006, due touncertainties surrounding the realizability of the deferred tax asset.

**Off BalanceSheet Arrangements**

Asof December 31, 2006, we had no off balance sheet arrangements.

**FinancialInstruments**

We have not committed any forwardsales of our natural gas and do not employ any other financial instruments.

**Outlook for 2007**

Depending on capitalavailability, we are forecasting capital spending of up to approximately$16.0 million in 2007, allocated as follows:

1.                                       Madisonville Project, Madison County, Texas.Approximately $11.0 million will be expended in the Madisonville Fieldarea as follows: $10,000,000 to drill a deep well location, and $1,000,000 tobe utilized for land acquisition, engineering and permitting.

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

3.                                       Central Alberta Reef Project. Up to approximately$2.0 million will be expended to drill exploratory wells and acquire 3-D seismic data.

54

----

We may, in our discretion, decideto allocate resources towards other projects in addition to or in lieu of,those listed above should other opportunities arise and as circumstanceswarrant.

We expect commodity prices to bevolatile, reflecting the current tight supply and demand fundamentals for NorthAmerican natural gas and world crude oil. Political events around the world,which are difficult to predict, will continue to influence both oil and gasprices. Higher prices for oil and gas often lead to higher levels of drillingactivity which in turn lead to higher costs to explore, develop and acquire oiland gas reserves due to greater competition for resources and supplies. Thesehigher costs could affect the returns on our capital expenditures. Higher crudeprices could also help keep natural gas prices high by keeping alternativefuels, such as heating oil and residual fuel, expensive.

**Impact of Inflation &Changing Prices**

As thefollowing table illustrates, average sales prices of natural gas have changedin the past three years.  This has led tochanges in revenues and earnings from operations:
| ** **                      | ** ** | **For the Year Ended December 31,** | ** ** |
|---------------------------------|------------|--------------------------------------------------------------|------------|
| ** **                      | ** ** | **2006 (1)**                                            | ** ** | **2005** | ** ** | **2004 (2)** | ** ** |
| Average Sales Prices  per Mcf   |       | $                                                            | 3.01       |   | $ | 4.01 |   | $ | 2.51 |   |
| Net Production Volume  Mcf      |       | 2,229,059                                                    |       | 1,991,105 |   | 2,316,895 |   |
| Revenues                        |       | $                                                            | 6,716,360  |   | $ | 7,975,990 |   | $ | 5,825,072 |   |
| Earnings (loss) from  Operation |       | $                                                            | (312,188   | ) | $ | 2,856,537 |   | $ | (1,613,830 | ) |

----

(1) Includes $38,849impairment expense

 

(2) Includes $2,038,422impairment expense

We arehighly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices couldimpair our ability to raise additional capital on acceptable terms.  Likewise, a material decrease in current andprojected natural gas prices could also impact our revenues and cashflows.  This could impact our ability tofund future activities.

Changingprices have had a significant impact on costs of drilling and completing wells,particularly in the Madisonville Field area where we are currently the mostactive.  The estimated cost of drillingand completing a Rodessa formation well at approximately 12,300 feet of depthhas increased from $3.0 million to $6.5 million in 2006 due to higher costsassociated with tubular goods, well equipment, and day rates for drillingcontracts, 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 consolidated financialstatements have been prepared by management in accordance with U.S. GAAP.

The preparation of consolidatedfinancial statements in conformity with U.S. GAAP requires management tomake estimates and assumptions that affect the amounts reported in theconsolidated financial statements and accompanying notes. Actual results coulddiffer from those estimates.

55

----

Management believes the mostcritical accounting policies that may have an impact on our financial resultsrelate to the accounting for oil and gas properties. Amortization, abandonmentcosts and full cost ceiling limitation write-downs are all based onnumerous estimates, many of which are beyond management’s control. Reservesrecognition is central to much of the accounting for an oil and gas company asdescribed below.

Significant accounting policiesare contained in Note 2 to the consolidated financial statements. Asummary of the unaudited supplementary oil and gas reserve information iscontained in Note 12 to the consolidated financial statements.

The following discusses theaccounting estimates that are critical in determining the reported financialresults:

*Oil and GasProperties* — Wefollow the full cost method of accounting for oil and gas producing activitiesas prescribed by U.S. GAAP and, accordingly, capitalizes all costsincurred in the acquisition, exploration, and development of proved oil and gasproperties, including the costs of abandoned properties, dry holes, geophysicalcosts, and lease rentals. All general corporate costs are expensed as incurred.In general, sales or other dispositions of oil and gas properties are accountedfor as adjustments to capitalized costs, with no gain or loss recorded.Amortization of evaluated oil and gas properties is computed on the units ofproduction method based on all proved reserves on a country by country basis.Unevaluated oil and gas properties are assessed for impairment eitherindividually or on an aggregate basis. The net capitalized costs of evaluatedoil and gas properties (full cost ceiling limitation) are not to exceed theirrelated estimated future net revenues discounted at 10%, and the lower of costor estimated fair value of unproved properties, net of tax considerations.

*Reserves —*We engage independentpetroleum engineering consultants to evaluate our reserves. Reserves, futureproduction profiles, and net revenues are estimated by independent professionalreservoir engineering firms. While we engage qualified reservoir engineeringfirms, their estimates are inherently uncertain, involve numerous assumptionsthat may not be realized, and predict asset values that may not be indicativeof the true market value of the assets evaluated. As a result of the inherentuncertainties and changing technical and economic assumptions, reserveestimates are subject to revisions that can materially impact our depletionrates, ceiling test calculations and results of operations.

*AssetRetirement Obligation —*We provide for the estimated site restoration and abandonment costs oftangible long-lived assets using a fair value method, which approximates thecost a third party would incur in performing the tasks necessary to retire suchassets. The reported liability is a discounted amount. The amount of theliability is affected by factors such as the number of wells, the timing of theexpected expenditures and the discount factor. These estimates will change andthe revisions could impact the amortization rates.

*Stock Based Compensation* —We have a stock- based compensation plan that allows employees topurchase our common shares.. Option exercise prices approximate the marketprice for the common shares on the date the options were issued. Optionsgranted under the plan are generally fully exercisable after five years andexpire five to ten years after the grant date. Under U.S. GAAP, prior to2006, we elected not to expense compensation cost for stock-basedemployee compensation at fair value but did disclose the impact of the fairvalue accounting of employee stock options in Note 2 to the annualaudited consolidated financial statements. We adopted Statement of Financial Accounting Standards No.123(R) (“Statement 123R”) on January 1, 2006, which is the beginning of ourfirst interim period following the effective date of Statement 123R. As notedabove, we previously disclosed the impact of, but did not expense stock-basedemployee compensation in accordance with Accounting Principal Board Opinion 25.We have applied the

56

----

modified prospective method of adoption,and accordingly, the financialstatements for our prior interim periods and fiscal years will not reflect anyrestated amounts.  We have recorded$201,335 of stock-based employee compensation for the twelve months endedDecember 31, 2006 in connection with the portion of previously granted employeestock options that vest on or after January 1, 2006. The impact of the fairvalue accounting of employee stock options is estimated on the date of grantusing the Black-Scholes option pricing model with assumptions for: riskfree interest rates, expected dividend yields, expected life of the optionsfrom the date of grant, and expected volatility.

**Risks andUncertainties**

There are a number of risks that face participants inthe U.S., Canadian and international oil and natural gas industry, including anumber of risks that face us in particular. Accordingly, there are risks involved in an ownership of oursecurities.  See “Risk Factors” for adescription of the principal risks faced by us.

**Item 7A. *Quantitative and Qualitative Disclosures About MarketRisk***

We are exposed to market risks arising fromfluctuating prices of crude oil, natural gas and interest rates as discussedbelow.

*CommodityRisk.*   Our major commodity price risk exposure isto the prices received for our natural gas production. Realized commodityprices received for our production are the spot prices applicable to naturalgas in the East Texas region. Prices received for natural gas are volatile andunpredictable and are beyond our control. For the year ended December 31,2006, a 10% change in the prices received for natural gas production would havehad an approximate $800,000 impact on our revenues.

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

*Hedging.* We didnot enter into any hedging transactions during the years ended December 312006, 2005 and 2004.

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

The reports of our independent registered publicaccounting firms and our consolidated financial statements and supplementalinformation required to be filed under Item 8 of Form 10-K are presentedbeginning on Page F-1 of this Form 10-K.

**Item 9. *Changes in andDisagreements With Accountants on Accounting and Financial Disclosure***

None.

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

57

----

**Management’s Conclusion on the Effectiveness of DisclosureControls and Procedures**

Our Chief Executive Officer and the Chief FinancialOfficer performed an evaluation of our disclosure controls and procedures,which have been designed to permit us to effectively identify and timelydisclose important information. They concluded that our disclosure controls andprocedures were effective as of December 31, 2006 to provide reasonableassurance that the information required to be disclosed in our reports filedunder the Exchange Act is recorded, processed, summarized and reported withinthe time periods specified in the rules and forms of the SEC, and that suchinformation is accumulated and communicated to our management including ourChief Executive Officer and our Chief Financial Officer, as appropriate, toallow timely decisions regarding required disclosures. While our disclosurecontrols and procedures provide reasonable assurance that the appropriateinformation will be available on timely basis, this assurance is subject tolimitations inherent in any control system, no matter how well it may bedesigned or administered.

**Changes in Internal Control over Financial Reporting**

There was no change in our internal control over financialreporting during the quarter ended December 31, 2006, that our ChiefExecutive Officer and Chief Financial Officer concluded materially affected, oris reasonably likely to materially affect, our internal control over financialreporting. 

This annual report does not include a report ofmanagement’s assessment regarding internal control over financial reporting oran attestation report of the Company’s registered public accounting firm due toa transition period established by rules of the Securities and Exchange Commissionfor newly public companies.

**Item 9B. *OtherInformation***

None.

 

58

----

**PART III**

**Item 10. *Directors and Executive Officers of the Registrant***

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

**Item 11. *Executive Compensation***

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

**Item 12.*Security Ownership of Certain BeneficialOwners and Management and Related Shareholder Matters***

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

**Item 13. *Certain Relationships and Related Transactions***

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

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

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

**PART IV**

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

1.                                   Thefinancial statements listed in the “Index to Consolidated Financial Statements”at page F-1 are filed as part of this report.

2.                                   Allother schedules are omitted because they are not applicable, not required orthe required information is included in the consolidated financial statementsor related notes.

3.                                   Exhibitsincluded or incorporated herein.  SeeExhibit Index.

 

**GLOSSARYOF OIL AND NATURAL GAS TERMS**

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

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

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

“**Bengara Block**”means the contract area in the Indonesian province of East Kalimantandesignated as the Bengara (II) PSC Block.

59

----

“**BP Migas**”means Badan Pelaksana Minyak Dan Gas Muni, a new executive boardestablished by the government of Indonesia in 2002 for oil and gas upstreamoperations and an implementing body created to assume the role of Pertamina’sregulatory functions and responsibilities in managing oil and gas contractors.

“**CBM**” means coalbed methane, which is methane found in coal seams. It is produced bynon-traditional means, and therefore, while it is sold and used the same astraditional natural gas, its production is different. CBM is generated eitherfrom a biological process as a result of microbial action or from a thermalprocess as a result of increasing heat with depth of the coal. Often a coalseam is saturated with water, with methane held in the coal by water pressure.

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

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

“**CNPC**” meansCNPCHK (Indonesia) Limited. CNPC is a wholly owned subsidiary ofCNPC (Hong Kong) Limited, a publicly held company based in Hong Kongwhere its shares trade on the Hong Kong Stock Exchange under the listing number0135.HK.

“**Company**”or “**GeoPetro**” means GeoPetroResources Company, a corporation incorporated under the laws of the State ofCalifornia and its wholly-owned subsidiaries.

“**Condensate**”means a low-density, high-API gravity liquid hydrocarbon product that isgenerally produced in association with natural gas. Condensate is mainlycomposed of propane, butane, pentane and heavier hydrocarbon fractions.

“**Continental**”means Continental Energy Corporation.

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

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

“**Earning Obligation**”means $18.7 million paid by CNPC into a special joint venture account at a HongKong international bank, which funds are under joint signature control of CNPC,ourselves and Continental, and will be expended to pay for 2007 explorationdrilling in the Bengara II PSC area.

“**EIA**”means the United States Energy Information Administration.

“**EP 408**”means the approximately 201,000 gross (52,675 net) acre permit areaincluding the Whicher Range gas field in the South Perth basin of WesternAustralia designated as Exploration Permit 408.

“**Evaluated Properties**”****means those properties that are producing oil or gas or onwhich, based on known geological and engineering data, oil and gas reserves arereasonably certain to exist.

“**Fannin Well**”means the Angela Farris Fannin No. 1 well located at the MadisonvilleField.

“**Farmout**” means an agreement wherebya third party agrees to pay for the drilling of a well on one or more ofGeoPetro’s properties in order to earn an interest therein with GeoPetroretaining a residual interest in such properties.

“**Flow-ThroughShare**” means a share of common stock issued as a “flow-throughshare” within the meaning of Canadian tax law.

60

----

“**Gateway**”means Gateway Processing Company, a Texas corporation that has constructedpipeline facilities at the Madisonville Field.

“**GeoPetro Alaska**”means GeoPetro Alaska LLC, an Alaska limited liability company, which is awholly-owned subsidiary of GeoPetro.

“**GeoPetro Canada**”means GeoPetro Canada Ltd., an Alberta corporation, which is a wholly-ownedsubsidiary of GeoPetro.

“**Hanover**”means Hanover Compression Limited Partnership, a Delaware limited partnershipthat has constructed and previously operated treatment facilities at theMadisonville Field.

“**Hanover Agreement**”means, collectively, the First Amended and Restated Master Agreement, dated asof September 12, 2002 among Redwood, Hanover and Gateway, as amended,providing for the processing of natural gas from the Madisonville Field, andthe agreements related thereto, which agreements were in effect prior toAugust 2005.

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

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

“**MadisonvilleProject**” means the oil and natural gas exploration, development andproduction project at the Madisonville Field.

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

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

“**MGP**”means Madisonville Gas Processing, LP, a Colorado Limited Partnership thathas purchased from Hanover and currently operates the treatment facilities atthe Madisonville Field, and is jointly owned by JPMorgan Partners and BearCub Investments LLC.

“**MGP Agreement**”means, collectively, the Termination and Release Agreement, Madisonville FieldDevelopment Agreement, Gas Purchase Contract between Redwood LP as Seller,and MGP as Buyer, Escrow Agreement and Dedication Agreement, all effective asof August 1, 2005 among Redwood LP, MGP, Gateway and Gateway PipelineCompany, providing for the termination of the Hanover Agreement, the expansionof the treatment facilities and the provision of the gathering, processing,transportation and sale of natural gas from the Madisonville Field.

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

“**Pertamina**”means Perusahaan Pertambangan Minyak Dan Gas Bumi Negara, the previousIndonesian state-owned oil and natural gas company established in 1971which had exclusive authority to explore, drill for, and produce oil andnatural gas minerals in Indonesia. In accordance with the new Indonesian Oiland Gas Law, its corporate form has been changed to become a state-ownedlimited liability company established under Indonesian Company Law, and allrights and obligations of Pertamina under existing PSCs shall pass toBP Migas.

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

**“Proveddeveloped oil and gas reserves”** means reserves that can be expected tobe recovered through existing wells with existing equipment and operatingmethods. Additional oil and gas expected to be obtained through the applicationof fluid injection or other improved recovery techniques for supplementing thenatural forces 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 recoveredfrom zones behind casing in existing wells.

61

----

**“Proved oil 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 ismade. Prices include consideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations based upon futureconditions.

(i)                                     Reservoirsare considered proved if economic producibility is supported by either actualproduction or a conclusive formation test. The area of a reservoir consideredproved includes (A) that portion delineated by drilling and defined by gas-oiland/or oil-water contacts, if any; and (B) the immediately adjoining portionsnot yet drilled, but which can be reasonably judged as economically productiveon the basis of available geological and engineering data. In the absence ofinformation on fluid contacts, the lowest known structural occurrence ofhydrocarbons controls the lower proved limit of the reservoir.

(ii)                                  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)                               Estimates of provedreserves 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, reservoir characteristics,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”** means reserves that are expected to berecovered from new wells on undrilled acreage, or from existing wells where arelatively major expenditure is required for recompletion. Reserves onundrilled acreage shall be limited to those drilling units offsettingproductive units that are reasonably certain of production when drilled. Provedreserves for other undrilled units can be claimed only where it can bedemonstrated with certainty that there is continuity of production from the existingproductive formation. Under no circumstances should estimates for provedundeveloped reserves be attributable to any acreage for which an application offluid injection or other improved recovery technique is contemplated, unlesssuch techniques have been proved effective by actual tests in the area and inthe same reservoir.

“**PSC**”means a production sharing contract, being a contract with Pertamina wherebyPertamina contracts with a petroleum company to explore for, develop andextract petroleum substances from a particular license area, on Pertamina’sbehalf, at the risk and expense of the petroleum company, in exchange for ashare of the production.

“**Redwood**”means Redwood Energy Company, a Texas corporation, which is a wholly-ownedsubsidiary of GeoPetro and which is the general partner of, and holds a 5%interest in, Redwood LP.

“**Redwood LP**”means Redwood Energy Production, L.P., a Texas limited partnership, thesole limited partner of which is GeoPetro and which is 100% owned, directly orindirectly, by GeoPetro.

62

----

“**Rodessa Formation**”means the geological formation at the Madisonville Field existing at a depth ofapproximately 12,000 feet.

“**Seismic**” means data collected that uses reflectedseismic waves to produce images of the Earth’s subsurface. The method requiresa controlled seismic source of energy, such as dynamite or a specialized airgun. By noting the time it takes for a reflection to arrive at a receiver, itis possible to estimate the depth of the feature that generated the reflection.

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

“**Series AAStock**” means the preferred stock of GeoPetro designated asSeries AA preferred stock, all of which converted to GeoPetro’s commonstock on March 28, 2007.

“**Tertiary Sandstones**”means sandstones which were deposited during a geologic time period rangingfrom 2 to 63 million years ago.

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

“**Unevaluated Properties**”means properties not yet evaluated through exploration and drilling as towhether or not they have proved reserves.

“**U.S. GAAP**”means the accounting principles generally 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.

**ABBREVIATIONS ANDCONVERSIONS**

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

 

 

63

----

**SIGNATURES**

Pursuant to the requirements of Section 13 or15(d) of the Securities Exchange Act of 1934, the registrant has duly causedthis report to be signed on its behalf by the undersigned, thereunto dulyauthorized, on March 30, 2007.
|        | **GEOPETRO RESOURCES COMPANY**                                             | ** **          |
|--------|----------------------------------------------------------------------------|---------------------|
|   | By:                                                                        | /s/ Stuart J. Doshi |   |
|   | Stuart J. Doshi                                                            |                |
|   | Chairman of the  Board of Directors, President and Chief Executive Officer |                |
|        |                                                                            |                     |  |

 

Pursuant to the requirements of the SecuritiesExchange Act of 1934, this report has been signed below by the followingpersons on behalf of the registrant and in the capacities indicated on March30, 2007.
| **Signature**            | ** ** | **Title**                                                            | ** ** | **Date**       |
|--------------------------|------------|----------------------------------------------------------------------|------------|----------------|
| ** **               | ** ** | ** **                                                           | ** ** | ** **     |
| /s/ Stuart J. Doshi      |       | Chairman of the  Board, President                                    |       | March 30, 2007 |
| Stuart J. Doshi          |       | and Chief  Executive Officer                                         |       |           |
|                     |       |                                                                 |       |           |
| /s/ David V. Creel       |       | Vice President  of Exploration and                                   |       | March 30, 2007 |
| David V. Creel           |       | Director                                                             |       |           |
|                     |       |                                                                 |       |           |
| /s/ J. Chris Steinhauser |       | Vice President  of Finance and                                       |       | March 30, 2007 |
| J. Chris Steinhauser     |       | Chief Financial  Officer, Principal  Accounting Officer and Director |       |           |
| /s/ Kevin M. Delehanty   |       | Director                                                             |       | March 30, 2007 |
| Kevin M. Delehanty       |       |                                                                 |       |           |
|                     |       |                                                                 |       |           |
| /s/ Thomas D. Cunningham |       | Director                                                             |       | March 30, 2007 |
| Thomas D. Cunningham     |       |                                                                 |       |           |
|                     |       |                                                                 |       |           |
| /s/ David G. Anderson    |       | Director                                                             |       | March 30, 2007 |
| David G. Anderson        |       |                                                                 |       |           |
|                     |       |                                                                 |       |           |
| /s/ Nick DeMare          |       | Director                                                             |       | March 30, 2007 |
| Nick DeMare              |       |                                                                 |       |           |

 

64

----

**GEOPETRO RESOURCES COMPANY**

**INDEXTO FINANCIAL STATEMENTS**
|                                                                                                                  | ** ** | ** ** |
|------------------------------------------------------------------------------------------------------------------|------------|------------|
| CONSOLIDATED FINANCIAL STATEMENTS FOR THE FISCAL  YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004              | ** ** | ** ** |
|                                                                                                             | ** ** | ** ** |
| Report of  Independent Registered Public Accounting Firm                                                         |       |       |
|                                                                                                             |       |       |
| Consolidated Balance  Sheets as of December 31, 2006 and 2005                                               |       |       |
|                                                                                                             |       |       |
| Consolidated  Statements of Operations for the years ended December 31, 2006, 2005 and  2004                |       |       |
|                                                                                                             |       |       |
| Consolidated  Statements of Shareholders’ Equity for the years ended December 31,  2006, 2005 and 2004 |       |       |
|                                                                                                             |       |       |
| Consolidated  Statements of Cash Flows for the years ended December 31, 2006, 2005 and  2004                |       |       |
|                                                                                                             |       |       |
| Notes to  Consolidated Financial Statements                                                                      |       |       |

 

F-1

----

 

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

March 29, 2007,

To the Shareholders and Board of Directors

GeoPetro Resources Company

San Francisco, California

We have audited the accompanyingconsolidated balance sheets of GeoPetro Resources Company and subsidiaries asof December 31, 2006 and 2005, and the related consolidated statements ofoperations, shareholders’ equity, and cash flows for each of the three years inthe period ended December 31, 2006. These consolidated financialstatements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these consolidated financialstatements based on our audits.

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement. An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements. An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

In our opinion, the consolidatedfinancial statements referred to above present fairly, in all materialrespects, the financial position of GeoPetro Resources Company and subsidiariesas of December 31, 2006 and 2005, and the results of their operations andtheir cash flows for each of the three years in the period ended December 31,2006, in conformity with accounting principles generally accepted in theUnited States of America.

As discussed in Note 2 to theaccompanying consolidated financial statements, effective January 1, 2006, theCompany adopted Statement of Financial Accounting Standard No. 123(R),Share-Based Payment. 

(Signed) ***HEIN & ASSOCIATES LLP***

Irvine, California

F-2

----

***GEOPETRO RESOURCES COMPANY***

**CONSOLIDATED BALANCE SHEETS**
| ** **                                                           | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
|----------------------------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                                                           | ** ** | **2006**              | ** ** | **2005**              | ** ** |
| **ASSETS**                                                           |       |                  |       |                  |       |
|                                                                 |       |                  |       |                  |       |
| **Current Assets:**                                                  | ** ** | ** **            | ** ** | ** **            | ** ** |
| Cash and cash  equivalents                                           |       | $                     | 734,561    |                  | $          | 914,826 |   |
| Accounts  receivable — oil and gas sales                        |       | 394,337               |       | 691,564               |       |
| Accounts  receivable — other                                    |       | 115,770               |       | 8,392                 |       |
| Related party  notes receivable                                      |       | 1,000,000             |       | —                |       |
| Prepaid expenses                                                     |       | 121,413               |       | 104,111               |       |
| Total current  assets                                                |       | 2,366,081             |       | 1,718,893             |       |
|                                                                 |       |                  |       |                  |       |
| **Oil  and Gas Properties,** at cost (full cost method):             |       |                  |       |                  |       |
| Unevaluated  properties                                              |       | 4,503,481             |       | 3,636,504             |       |
| Evaluated  properties                                                |       | 43,701,510            |       | 27,846,543            |       |
| Less—accumulated  depletion and impairments                     |       | (11,557,257           | )          | (9,130,869            | )          |
| Net oil and gas  properties                                          |       | 36,647,734            |       | 22,352,178            |       |
|                                                                 |       |                  |       |                  |       |
| **Furniture, Fixtures and  Equipment,** at cost, net of depreciation |       | 41,547                |       | 56,013                |       |
|                                                                 |       |                  |       |                  |       |
| **Other  Assets**— deposits  and other noncurrent assets        |       | 6,116                 |       | 6,583                 |       |
| **Deferred Offering Costs**                                          |       | —                |       | 881,159               |       |
|                                                                 |       |                  |       |                  |       |
| **Total Assets**                                                     |       | $                     | 39,061,478 |                  | $          | 25,014,826 |   |
|                                                                 |       |                  |       |                  |       |
| **LIABILITIES  AND SHAREHOLDERS’ EQUITY**                       | ** ** | ** **            | ** ** | ** **            | ** ** |
|                                                                 |       |                  |       |                  |       |
| **Current Liabilities:**                                             | ** ** | ** **            | ** ** | ** **            | ** ** |
| Trade payables                                                       |       | $                     | 654,427    |                  | $          | 1,928,169 |   |
| Short term notes  payable                                            |       | 982,301               |       | —                |       |
| Interest payable                                                     |       | 73,205                |       | —                |       |
| Dividends  payable                                                   |       | 133,438               |       | 133,438               |       |
| Production taxes  payable                                            |       | 662,905               |       | 310,186               |       |
| Other taxes  payable                                                 |       | 9,206                 |       | 24,766                |       |
| Royalty owners  payable                                              |       | 951,271               |       | 865,244               |       |
| Net profits  interest payable                                        |       | 137,589               |       | 312,663               |       |
| Total current  liabilities                                           |       | 3,604,342             |       | 3,574,466             |       |
|                                                                 |       |                  |       |                  |       |
| **Asset Retirement Obligations**                                     |       | 48,842                |       | 26,641                |       |

 

See accompanying notes tothese consolidated financial statements.

F-3

----

 
| ** **                                                                                                                                                                                                                                                            | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                                                                                                            | ** ** | **2006**              | ** ** | **2005**              | ** ** |
|                                                                                                                                                                                                                                                                  |       |                  |       |                  |       |
| **Commitments and Contingencies  (Note 7)**                                                                                                                                                                                                                           |       |                  |       |                  |       |
|                                                                                                                                                                                                                                                                  |       |                  |       |                  |       |
| **Shareholders’ Equity:**                                                                                                                                                                                                                                        |       |                  |       |                  |       |
| Series A preferred  stock, no par value; 1,000,000 shares authorized 0 shares after conversion on  March 30, 2006 and 1,000,000 shares issued and outstanding at December 31,  2005, respectively                                                                     |       | —                |       | 674,425               |       |
| Series AA preferred  stock, no par value; 5,000,000 shares authorized 1,890,710 shares issued and  outstanding at December 31, 2006, and December 31, 2005, respectively.  Liquidation value is $6,750,923 at December 31, 2006, and December 31, 2005,  respectively |       | 5,924,068             |       | 5,924,068             |       |
| Common stock, no par  value; 100,000,000 shares authorized 27,423,758 and 21,171,923 shares issued  and outstanding at December 31, 2006 and December 31, 2005, respectively                                                                                          |       | 40,112,265            |       | 24,815,184            |       |
| Additional paid-in  capital                                                                                                                                                                                                                                           |       | 918,381               |       | 534,656               |       |
| Treasury stock, at  cost; 1,257,043 shares held at December 31, 2006 and December 31, 2005,  respectively                                                                                                                                                             |       | (1,152,435            | )          | (1,152,435            | )          |
| Accumulated deficit                                                                                                                                                                                                                                                   |       | (10,393,985           | )          | (9,382,179            | )          |
| Total shareholders’  equity                                                                                                                                                                                                                                      |       | 35,408,294            |       | 21,413,719            |       |
|                                                                                                                                                                                                                                                                  |       |                  |       |                  |       |
| **Total Liabilities and Shareholders’ Equity**                                                                                                                                                                                                                   |       | $                     | 39,061,478 |                  | $          | 25,014,826 |   |
|                                                                                                                                                                                                                                                                       |            |                       |            |                       |            |  |  |

 

***Seeaccompanying notes to these consolidated financial statements.***

F-4

----

***GEOPETRO RESOURCES COMPANY***

**CONSOLIDATED STATEMENTS OF OPERATIONS**
| ** **                                                 | ** ** | **For the Years Ended December 31,** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                 | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                       |       |                                                          |       |   |   |   |   |
| **Revenues**                                               |       |                                                          |       |   |   |   |   |
| Oil and gas  sales                                         |       | $                                                             | 6,716,360  |   | $ | 7,975,990 |   | 5,825,072 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Costs and expenses:**                                    |       |                                                          |       |   |   |   |   |
| Lease operating  expense                                   |       | 1,602,932                                                     |       | 878,176 |   | 780,237 |   |
| General and  administrative                                |       | 2,347,447                                                     |       | 1,551,747 |   | 1,963,649 |   |
| Net profits  interest                                      |       | 632,708                                                       |       | 856,837 |   | 579,590 |   |
| Impairments  expense                                       |       | 38,849                                                        |       | — |   | 2,038,422 |   |
| Depreciation and  depletion expense                        |       | 2,406,612                                                     |       | 1,832,693 |   | 2,077,004 |   |
| Total costs and  expenses                                  |       | 7,028,548                                                     |       | 5,119,453 |   | 7,438,902 |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Income (loss) from operations**                          |       | (312,188                                                      | )          | 2,856,537 |   | (1,613,830 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Other Income and (Expense):**                            |       |                                                          |       |   |   |   |   |
|                                                       |       |                                                          |       |   |   |   |   |
| Interest expense                                           |       | (306,682                                                      | )          | (217,768 | ) | (402,958 | ) |
| Debt conversion  expense                                   |       | —                                                        |       | — |   | (67,375 | ) |
| Interest income                                            |       | 198,050                                                       |       | 18,969 |   | 6,548 |   |
| Total other  expense                                       |       | (108,632                                                      | )          | (198,799 | ) | (463,785 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) Before Taxes**                         |       | (420,820                                                      | )          | 2,657,738 |   | (2,077,615 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| Income tax  expense                                        |       | (61,586                                                       | )          | (17,267 | ) | — |   |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) After Taxes**                          |       | (482,406                                                      | )          | 2,640,471 |   | (2,077,615 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| Preferred stock  dividend                                  |       | (529,400                                                      | )          | (529,397 | ) | (529,363 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Net Income (Loss) Available to  Common Shareholders**    |       | $                                                             | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Earnings (Loss) per Share:**                             |       |                                                          |       |   |   |   |   |
| Basic                                                      |       | $                                                             | (0.04      | ) | $ | 0.10 |   | $ | (0.14 | ) |
| Diluted                                                    |       | $                                                             | (0.04      | ) | $ | 0.09 |   | $ | (0.14 | ) |
|                                                       |       |                                                          |       |   |   |   |   |
| **Weighted Average Number of Common  Shares Outstanding:** |       |                                                          |       |   |   |   |   |
| Basic                                                      |       | 25,990,868                                                    |       | 20,890,841 |   | 18,901,607 |   |
| Diluted                                                    |       | 25,990,868                                                    |       | 24,001,888 |   | 18,901,607 |   |

 

***Seeaccompanying notes to these consolidated financial statements.***

F-5

----

# ***GEOPETRO RESOURCES COMPANY***

**CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY**

**FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 and 2004**
| ** **                                       | ** ** | **Preferred Stock** | ** ** | **Preferred Stock** | ** ** | ** **            | ** ** | ** **                  | ** ** | ** **   | ** ** | ** **      | ** ** | ** **             | ** ** | **Total**  | ** ** |
|--------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|-----------------------|------------|-----------------------------|------------|--------------|------------|-----------------|------------|------------------------|------------|------------|------------|
| ** **                                       | ** ** | **Series A**        | ** ** | **Series AA**       | ** ** | **Common stock** | ** ** | **Additional Paid-in** | ** ** | **Treasury** | ** ** | **Accumulated** | ** ** | **Shareholders’** | ** ** |
| ** **                                       | ** ** | **Shares**               | ** ** | **Amount**               | ** ** | **Shares**            | ** ** | **Amount**                  | ** ** | **Shares**   | ** ** | **Amount**      | ** ** | **Captial**            | ** ** | **Stock**  | ** ** | **Deficit** | ** ** | **Equity** | ** ** |
| ** **                                       |       |                     |       |                     |       |                  |       |                        |       |         |       |            | ** ** | ** **             |       |       |       |   |   |   |   |
| **Balances,**December 31,  2003                  |       | 1,000,000                |       | $                        | 674,425    |                  | 1,890,710  |                        | $          | 5,924,068    |       | 17,656,950      |       | $                      | 14,509,961 | ** ** | **$**      | **—** |   | $ | (60,000 | ) | $ | (8,886,275 | ) | $ | 12,162,179 |   |
| Issuance of common stock for cash, net           |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | 1,609,822    |       | 3,479,899       | ** ** | **—**             | ** ** | **—** | ** ** | **—** |   | 3,479,899 |   |
| Conversion of notes payable                      |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | 719,147      |       | 2,097,500       | ** ** | **—**             | ** ** | **—** | ** ** | **—** |   | 2,097,500 |   |
| Treasury stock purchased                         |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | (117,647     | )          | **—**      | ** ** | **—**             |       | (500,000   | )          | **—** |   | (500,000 | ) |
| Stock compensation expense                       |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  | ** ** | **—**   | ** ** | **—**      |       | 500,000                | ** ** | **—** | ** ** | **—** |   | 500,000 |   |
| Fair value of warrants issued with notes payable |       | **—**               |       | **—**               |       | **—**            |       | **—**                  |       | **—**   |       | **—**      |       | 31,729                 |       | **—** |       | **—** | ** ** | 31,729 | ** ** |
| Net loss                                         |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  | ** ** | **—**   | ** ** | **—**      | ** ** | **—**             | ** ** | **—** |       | (2,077,615 | ) | (2,077,615 | ) |
| Dividends on Series AA Preferred                 |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  | ** ** | **—**   | ** ** | **—**      | ** ** | **—**             | ** ** | **—** |       | (529,363) |   | (529,363 | ) |
| **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, net           |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | 1,443,047    |       | 4,727,824       | ** ** | **—**             | ** ** | **—** | ** ** | **—** |   | 4,727,824 |   |
| Treasury stock purchased                         |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | (139,396     | )          | **—**      | ** ** | **—**             |       | (592,435   | )          | **—** |   | (592,435 | ) |
| Fair value of warrants extension                 |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  | ** ** | **—**   | ** ** | **—**      |       | 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, net           |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  |       | 5,176,835    |       | 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 |   |
| Fair market value of the options                 |       | **—**               | ** ** | **—**               | ** ** | **—**            | ** ** | **—**                  | ** ** | **—**   | ** ** | **—**      |       | 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    |       | 27,348,758      |       | $                      | 40,112,265 | ** ** | $          | 918,381 |   | $ | (1,152,435 | ) | $ | (10,393,985 | ) | $ | 35,408,294 |   |

 

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

F-6

----

***GEOPETRO RESOURCES COMPANY***

**CONSOLIDATED STATEMENTS OF CASH FLOWS**
| ** **                                                                                          | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                                          | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                                                                |       |                                                          |       |   |   |   |   |
| **Cash  Flows From Operating Activities:**                                                          |       |                                                          |       |   |   |   |   |
|                                                                                                |       |                                                          |       |   |   |   |   |
| Net income (loss)                                                                                   |       | $                                                             | (482,406   | ) | $ | 2,640,471 |   | $ | (2,077,615 | ) |
| Adjustments to reconcile net income (loss) to net  cash provided by (used in) operating activities: |       |                                                          |       |   |   |   |   |
| Depreciation and depletion                                                                          |       | 2,406,612                                                     |       | 1,832,693 |   | 2,077,004 |   |
| Stock compensation expense                                                                          |       | 201,335                                                       |       | 2,927 |   | 531,729 |   |
| Non-cash interest expense                                                                           |       | 194,691                                                       |       | — |   | (17,304 | ) |
| Impairment expense                                                                                  |       | 38,849                                                        |       |   |   | 2,038,422 |   |
| Asset retirement obligations                                                                        |       | 2,664                                                         |       | 1,936 |   | 1,237 |   |
| Changes in  operating assets and liabilities:                                                       |       |                                                          |       |   |   |   |   |
| (Increase) decrease in accounts receivable                                                          |       | 297,226                                                       |       | (239,195 | ) | 179,159 |   |
| (Increase) decrease in other receivables                                                            |       | (107,378                                                      | )          | 81,608 |   | (90,000 | ) |
| (Increase) in prepaid expenses                                                                      |       | (17,302                                                       | )          | (77,752 | ) | (15,945 | ) |
| Deposits and other noncurrent assets                                                                |       | 466                                                           |       | (794 | ) | 4,625 |   |
| Increase (decrease) in trade payables                                                               |       | (1,273,742                                                    | )          | 662,791 |   | 1,013,524 |   |
| Increase (decrease) in interest payable                                                             |       | 73,205                                                        |       | (88,388 | ) | 29,034 |   |
| Increase (decrease) in dividends payable                                                            |       | —                                                        |       | 361 |   | 20,769 |   |
| Increase (decrease) in production taxes payable                                                     |       | 352,720                                                       |       | (27,794 | ) | 337,980 |   |
| Increase (decrease) in other taxes payable                                                          |       | (15,561                                                       | )          | (21,522 | ) | 46,288 |   |
| Increase in royalty owners payable                                                                  |       | 86,027                                                        |       | 157,251 |   | 74,211 |   |
| Increase (decrease) in net profit interest payable                                                  |       | (175,074                                                      | )          | 91,197 |   | 57,518 |   |
| Increase in asset retirement obligations                                                            |       | 19,537                                                        |       | — |   | 11,094 |   |
| Net cash provided by operating activities                                                           |       | 1,601,869                                                     |       | 5,015,790 |   | 4,221,730 |   |
|                                                                                                |       |                                                          |       |   |   |   |   |
| **Cash  Flows from Investing Activities:**                                                          |       |                                                          |       |   |   |   |   |
|                                                                                                |       |                                                          |       |   |   |   |   |
| Oil and gas property expenditures                                                                   |       | (16,721,944                                                   | )          | (5,602,741 | ) | (9,171,589 | ) |
| Proceeds from sale of oil and gas interest                                                          |       | —                                                        |       | 2,400,000 |   | — |   |
| Acquisition of furniture, fixtures & equipment                                                  |       | (4,605                                                        | )          | (2,162 | ) | (81,876 | ) |
|  (Increase) in related party notes receivable                                                  |       | (1,000,000                                                    | )          | — |   | — |   |
| Net cash used in  investing activities                                                              |       | (17,726,549                                                   | )          | (3,204,903 | ) | (9,253,465 | ) |
|                                                                                                     |            |                                                               |            |  |  |  |  |  |  |  |

 

***Seeaccompanying notes to these consolidated financial statements.***

F-7

----

 
| ** **                                                                                                    | ** ** | **For the Years Ended December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                                                                                    | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| **Cash  Flows from Financing Activities:**                                                                    |       |                                                          |       |   |   |   |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
|  Proceeds from sale of common shares, option  and warrant exercises, net                                 |       | 16,717,604                                                    |       | 4,727,824 |   | 3,479,899 |   |
|  Payments of preferred dividends                                                                         |       | (529,400                                                      | )          | (529,397 | ) | (529,363 | ) |
|  Proceeds from promissory notes, net                                                                     |       | 1,900,000                                                     |       | — |   | 2,075,000 |   |
|  Payments of loan fee                                                                                    |       | (30,000                                                       | )          | — |   | — |   |
|  Repayments of promissory notes                                                                          |       | (900,000                                                      | )          | (4,781,807 | ) | (1,158,569 | ) |
|  Deferred offering costs                                                                                 |       | (1,213,789                                                    | )          | (730,906 | ) | (150,255 | ) |
|  Purchase of treasury stock                                                                              |       | —                                                        |       | (592,435 | ) | — |   |
| Net cash provided by (used in) financing activities                                                           |       | 15,944,415                                                    |       | (1,906,721 | ) | 3,716,712 |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| **Net  Increase in Cash and Cash Equivalents:**                                                               |       | (180,265                                                      | )          | (95,834 | ) | (1,315,023 | ) |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| **Cash  and Cash Equivalents:**                                                                               |       |                                                          |       |   |   |   |   |
| Beginning of period                                                                                           |       | 914,826                                                       |       | 1,010,660 |   | 2,325,683 |   |
| End of period                                                                                                 |       | $                                                             | 734,561    |   | $ | 914,826 |   | $ | 1,010,660 |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| **Supplemental  Disclosure of Cash Flow Information:**                                                        |       |                                                          |       |   |   |   |   |
| Cash paid for interest                                                                                        |       | $                                                             | 38,682     |   | $ | 291,731 |   | $ | 297,266 |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| Cash paid for income taxes                                                                                    |       | $                                                             | 61,586     |   | $ | — |   | $ | — |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| **Supplemental  Disclosure of Non-Cash Investing and Financing Activities:**                                  |       |                                                          |       |   |   |   |   |
|                                                                                                          |       |                                                          |       |   |   |   |   |
| Issuance of  common stock for conversion of notes payable and cancellation of common stock  purchase warrants |       | —                                                        |       | — |   | $ | 2,097,500 |   |

 

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

F-8

----

***GEOPETRORESOURCES COMPANY***

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

**1.         Organization and Nature of Operations**:

*GeoPetro* — GeoPetro Resources Company (“GeoPetro” or the “Company”) wasoriginally incorporated as GeoPetro Company under the laws of the State ofWyoming in 1994 to participate in the oil and gas acquisition, exploration,development and production business in the United States andinternationally. GeoPetro Company was subsequently merged into GeoPetroResources Subsidiary Company, a California corporation, on June 28, 1996.GeoPetro’s name was then changed to GeoPetro Resources Company. GeoPetro’scorporate offices are in San Francisco, California. The accompanyingconsolidated financial statements include the accounts of GeoPetro and itswholly-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 incurred a net loss of$1,011,806 in 2006, net income of $2,111,074 in 2005, and net loss of$2,606,978 in 2004, and had an accumulated deficit at December 31, 2006,of $10,393,985. GeoPetro expects to make significant capital expenditures inthe foreseeable future. Management believes that GeoPetro will be successful inobtaining adequate sources of cash to fund its anticipated capital expendituresthrough the end of 2007 and to follow through with plans for continuedinvestments in oil and gas properties. GeoPetro’s success, in part, depends onits ability to generate additional financing, farm-out certain of its projectsand manage its relations with the companies that provide exploration anddevelopment services. GeoPetro’s success also depends on its ability toeffectively manage growth and develop proven reserves. Additionally, GeoPetro’soperations are subject to all of the environmental and operational risksnormally associated with the oil and gas industry. GeoPetro maintains insurancethat is customary in the industry.

Since its inception, GeoPetro has participated as a working interestowner in the acquisition of undeveloped leases, seismic options, lease optionsand foreign concessions and has participated in seismic surveys and thedrilling of test wells on its undeveloped properties. Further leaseholdacquisitions and seismic operations are planned for 2007 and future periods. Inaddition, drilling is scheduled during 2007 and future periods on GeoPetro’sundeveloped properties. It is anticipated that these exploration activitiestogether with others that may be entered into may impose financial requirementswhich may exceed the existing working capital of GeoPetro. Management may raiseadditional equity and/or debt capital, and has farmed-out certain of itsprojects to finance its continued participation in planned activities. In theopinion of GeoPetro management, GeoPetro can continue as a going concern evenif additional financing is unavailable. However, if additional financing is notavailable, GeoPetro may be compelled to reduce the scope of its businessactivities. If GeoPetro is unable to fund planned expenditures, it may benecessary to:

F-9

----

1.                                       forfeit its interest in wells that are proposed tobe drilled;

2.                                       farm-out its interest in proposed wells;

3.                                       sell a portion of its interest in prospects anduse the sale proceeds to fund its participation for a lesser

interest; and

4.                                       reduce general and administrative expenses.

In order for GeoPetro to maintain its interest in the Indonesian andAustralian contract and permit areas, certain work and expenditure commitmentsmust be met or an extension must be granted by the applicable governingauthority. In the event that GeoPetro does not meet the commitments and noextensions are granted for meeting the commitments, GeoPetro will forfeit itsinterest in the contract or permit areas requiring an impairment write-downequal to the capitalized costs recorded for the area forfeited. This could havea material adverse impact on GeoPetro’s results of operations in futureperiods.

In July 2005, GeoPetro entered into agreements with unaffiliatedcompanies that have purchased and are operating a dedicated gas treatment plantand related pipelines to process and transport GeoPetro’s gas from theMadisonville Project in Madison County, Texas. These agreements are discussedin detail in Note 10. In connection with the Madisonville Project,GeoPetro re-completed an existing well for production from the Rodessa formationinterval at approximately 11,800 feet of depth and completed an injection wellfor disposal of waste gasses from the production well. GeoPetro initiated gassales from the Madisonville Project in May 2003. A second well wasdrilled, tested and completed during 2004 and is presently producing on arestricted rate awaiting a planned expansion of the gas treatment plant.  Two additional development wells were drilledduring 2006. Another well is planned for drilling during 2007 in theMadisonville Project.

Other than the above work and expenditure commitments, the timing ofmost of GeoPetro’s capital expenditures is discretionary. GeoPetro has nomaterial long-term commitments associated with its capital expenditure plans oroperating agreements. Consequently, GeoPetro has a significant degree offlexibility to adjust the level of such expenditures as circumstances warrant.The level of capital expenditures will vary in future periods depending on thesuccess of exploratory drilling activities, gas and oil price conditions andother related economic factors. See Note 11 for a discussion of financingactivity subsequent to year end.

F-10

----

**2.         Summaryof Significant Accounting Policies**:

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

*Use of Estimates and Significant Estimates —*Certain amounts in GeoPetro’s financial statements are based uponsignificant estimates, including oil and gas reserve quantities which form thebasis for the calculation of depreciation, depletion, amortization andimpairment of oil and gas properties. Actual results could materially differfrom those estimates.

*Oil and Gas Properties* — GeoPetro follows the full cost method ofaccounting for oil and gas producing activities and, accordingly, capitalizesall costs incurred in the acquisition, exploration, and development of provedoil and gas properties, including the costs of abandoned properties, dry holes,geophysical costs, and annual lease rentals. All general corporate costs areexpensed as incurred. In general, sales or other dispositions of oil and gasproperties are accounted for as adjustments to capitalized costs, with no gainor loss recorded. Amortization of evaluated oil and gas properties is computedon the units of production method based on all proved reserves on a country bycountry basis. Unevaluated oil and gas properties are assessed for impairmenteither individually or on an aggregate basis. The net capitalized costs ofevaluated oil and gas properties (full cost ceiling limitation) are not toexceed their related estimated future net revenues discounted at 10%, and thelower of cost or estimated fair value of unproved properties, net of taxconsiderations.

*Joint Ventures* — Some exploration and production activitiesare conducted jointly with others and, accordingly, the accounts reflect onlyGeoPetro’s proportionate interest in such activities.

*RevenueRecognition* — Revenue is recognized upon delivery of oil andgas production and is shown net of applicable royalty payments, processing andtransportation fees. Inaddition, the Company recognizes revenue from the Madisonville Field net ofapplicable fees to gather, treat and transport the Company’s natural gasproduction. The applicable fees are paid to unrelated third parties. Revenuefrom the Madisonville Field is recognized when the price for gas deliveredbecomes fixed and determinable. The price for gas delivered to the purchaser,Madisonville Gas Processing LP (“MGP”), becomes fixed and determinable afterthe gas has been gathered, treated, and transported to a common carrierpipeline where it is then resold by MGP to the common carrier pipeline on aspot market basis. The proceeds from the sale of the gas are deposited directlyinto an escrow account under the joint signature control of the Company andMGP. The fees to gather, treat and transport the gas are distributed to MGP inaccordance with agreements between them and the Company. The remaining netproceeds are distributed to the Company. See Note 10 for a more detaileddiscussion of the fees under the “MGP Agreement.”

F-11

----

*Asset Retirement Obligation* — In accordance with Statement of FinancialAccounting Standards No. 143, *Accountingfor Asset Retirement Obligations* (“SFAS 143”), the fair valueof an asset retirement cost, and corresponding liability, should be recorded aspart of the cost of the related long-lived asset and subsequently allocated toexpense using a systematic and rational method. GeoPetro recorded an assetretirement obligation to reflect GeoPetro’s legal obligations related to futureplugging and abandonment of its oil and gas wells. GeoPetro estimated theexpected cash flow associated with the obligation and discounted the amountusing a credit-adjusted, risk-free interest rate. At least annually,GeoPetro reassesses the obligation to determine whether a change in theestimated obligation is necessary. GeoPetro evaluates whether there areindicators that suggest the estimated cash flows underlying the obligation havematerially changed. Should those indicators suggest theestimated obligation has materially changed, GeoPetro will accordinglyupdate its assessment.
|                                                   | ** ** | **December 31,** | ** ** |
|---------------------------------------------------|------------|-----------------------|------------|
| ** **                                        | ** ** | **2006**              | ** ** | **2005** | ** ** | **2004** | ** ** |
| Asset retirement obligations, beginning of period |       | $                     | 26,641     |   | $ | 24,705 |   | $ | 12,374 |   |
| Liabilities incurred                              |       | 19,537                |       | — |   | 11,094 |   |
| Accretion expense                                 |       | 2,664                 |       | 1,936 |   | 1,237 |   |
|                                              |       |                  |       |   |   |   |   |
| Asset retirement  obligations, end of period      |       | $                     | 48,842     |   | $ | 26,641 |   | $ | 24,705 |   |

 

*Furniture, Fixtures and Equipment —*Furniture,fixtures and equipment are stated at cost. Depreciation is provided onfurniture, fixtures and equipment using the straight-line method over anestimated service life of three to seven years.

*Income Taxes* — GeoPetro accounts for income taxes usingthe asset and liability method wherein deferred tax assets and liabilities arerecognized for the future tax consequences attributable to differences betweenfinancial statement carrying amounts of existing assets and liabilities andtheir respective tax bases. Deferred tax assets and liabilities are measuredusing enacted tax rates expected to apply to taxable income in the years inwhich the temporary differences are expected to be recovered or settled.Because management has determined that realization of deferred tax assets isnot likely, the net deferred tax assets are fully reserved.

F-12

----

*Concentrations of Credit Risk* — Credit risk represents the accounting lossthat would be recognized at the reporting date if counterparties failedcompletely to perform as contracted. Concentrations of credit risk (whether onor off balance sheet) that arise from financial instruments exist for groups ofcustomers or counterparties when they have similar economic characteristicsthat would cause their ability to meet contractual obligations to be similarlyaffected by changes in economic or other conditions described below. The creditrisk amounts for cash and accounts receivable do not take into account thevalue of any collateral or security.

GeoPetro maintains several cash accounts with three financialinstitutions. Accounts at each institution are insured by the Federal DepositInsurance Corporation up to $100,000. As of December 31, 2006, theuninsured bank balance was $973,682. GeoPetro has not experienced any losses insuch accounts and believes it is not exposed to any significant credit risk.

During 2006, 2005 and 2004, the Company had sales to customers exceeding10% of total sales as follows:
|            | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------|------------|----------|------------|----------|------------|----------|------------|
|       |       |     |       |     |       |     |       |
| Customer A |       | 79       | %          | 99.7     | %          | 99.6     | %          |
| Customer B |       | 21       | %          | —   |       | —   |       |

 

At December 31, 2006, 2005 and 2004, the Company had accountsreceivable balances from Customer A of $394,337 or 77%, $691,564, or 100%, and$449,947, or 99.5% of total accounts receivable respectively. 

*Allowance for Doubtful Accounts* — Trade accounts receivable are recorded atnet realizable value. If the financial condition of GeoPetro’s customers wereto deteriorate, resulting in an impairment of their ability to make payments,additional allowances may be required. Delinquent trade accounts receivable arecharged against the allowance for doubtful accounts once uncollectibility hasbeen determined. The allowance is determined through an analysis of thepast-due status of accounts receivable and assessments of risk that are basedon historical trends and an evaluation of the impact of current and projectedeconomic conditions. There was no activity in the allowance for doubtfulaccounts as of December 31, 2006 and 2005.

*Fair Value of Financial Instruments* — The estimated fair values for financialinstruments are determined at discrete points in time based on relevant marketinformation. These estimates involve uncertainties and cannot be determinedwith precision. For certain of GeoPetro’s financial instruments, includingcash, accounts receivable, accounts payable and current portion of notespayable, the carrying amounts approximate fair value due to their maturities. 

F-13

----

*Stock-Based Compensation* — Statement of Financial AccountingStandards No. 123, *Accounting for Stock-BasedCompensation* (“SFAS 123”), encourages, but does not require,companies to record compensation cost for stock-based employeecompensation at fair value prior to January 1, 2006. GeoPetro elected toaccount for stock-based compensation using the intrinsic value methodprescribed in Accounting Principles Board Opinion No. 25 (“APB 25”), *Accounting for Stock Issued to Employees,*and related interpretations.

In accordance with SFAS 123, GeoPetro discloses the impact of thefair value accounting of employee stock options. Transactions in equityinstruments with non-employees for goods or services have been accounted forusing the fair value method as prescribed by SFAS 123.

The following table illustrates the effect on GeoPetro’s net loss andloss per share as if GeoPetro had applied the fair value recognition provisionsof SFAS 123 to its stock-based employee compensation awards grantedin 2003 and in 2005, and recognized expense over the applicable award vestingperiod. There were no stock-based employee compensation awards granted in 2004.
|                                                                        | ** ** | **As at and for the Years Ended  December 31,** | ** ** |
|------------------------------------------------------------------------|------------|------------------------------------------------------------------------------------|------------|
| ** **                                                             | ** ** | **2005**                                                                           | ** ** | **2004** | ** ** |
|                                                                   |       |                                                                               |       |   |   |
| Net income  (loss) available to common shareholders – as reported |       | $                                                                                  | 2,111,074  |   | $ | (2,606,978 | ) |
| Compensation –  FAS 123                                           |       | (98,870                                                                            | )          | (63,655 | ) |
|                                                                   |       |                                                                               |       |   |   |
| Pro forma income (loss)                                                |       | $                                                                                  | 2,012,204  |   | $ | (2,670,633 | ) |
|                                                                   |       |                                                                               |       |   |   |
| Income (loss)  per share – as reported                            |       | $                                                                                  | 0.09       |   | $ | (0.14 | ) |
| Pro forma income (loss)  per share                                     |       | $                                                                                  | 0.08       |   | $ | (0.14 | ) |

 

The assumptionsmade for purposes of estimating the fair value of the stock options areincluded in Note 8.

Effective January1, 2006, the Company adopted the fair value recognition provisions of Statementof Financial Accounting Standard 123(R) “*Share-BasedPayment”* (“SFAS 123(R)”) using the modified prospective transitionmethod. In addition, the Securities and Exchange Commission issued Staff AccountingBulletin 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 year ended December 31,2006 includes: (a) compensation cost for all share-based payments grantedprior to, but not yet vested as of January 1, 2006, based on the grant datefair value estimated in accordance with the original provisions of SFASNo. 123, and (b) compensation cost for all share-based paymentsgranted beginning January 1, 2006, based on the grant date fair value estimatedin

F-14

----

accordance withthe provisions of SFAS 123(R). In accordance with the modified prospectivetransition method, results for prior periods have not been restated.

The adoption of SFAS123(R) resulted in stock compensation expense for the year ended December 31,2006 of $201,335 to income from continuing operations and income before incometaxes, of which the entire amount was recorded to general and administrativeexpenses. The Company did not recognize a tax benefit from the stockcompensation expense because the Company considers it is more likely than notthat the related deferred tax assets, which have been reduced by a full valuationallowance, will not be realized.

The fair value of each option grant was estimated on the date of grantusing the Black-Scholes option pricing model with the following weighted-averageassumptions used for grants in 2003 and 2005: risk-free, weighted-averageinterest rates ranging from 2.52 to 3.75 percent, expected dividend yieldof 0 percent, expected life of 5 years from the date of grant, andexpected volatility of 10 and 25 percent. After the initial publicoffering on March 30, 2006, an expected volatility factor of 58% was used forthe newly issued common stock options and the extension of common stockwarrants. A newly issued stock option is an option that was granted on or afterMarch 30, 2006 or a previously granted stock option that is modified on orafter March 30, 2006. The fair value of all newly issued stock options grantsis estimated using the Black-Scholes option pricing model with the followingweighted average assumptions used for grants and modifications of prior grantsmade on or after March 30, 2006 for the twelve months ended December 31, 2006:risk-free, weighted average interest rate of 4.9 percent based on the U.S.Treasury yield curve in effect at the time of grant, expected dividend yield of0 percent, expected life of 5 years from the date of grant (the remaining termof the option in the case of option extensions), and expected volatility of58%. GeoPetro has selected 10 publicly traded “small cap” companies whoseprimary business is oil and gas exploration and production.  Small cap, for purposes of this analysis, isdefined as companies with a market capitalization 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 expectedvolatilities were expressed as a range, a simple average of the range is usedas an expected volatility for that entity.

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

F-15

----

*Income (Loss) Per Common Share —*Basic earnings per share excludes dilution and is calculated by dividingnet income or loss by the weighted average number of common shares outstandingfor the period. Diluted earnings per share reflects the potential dilution thatcould occur if securities or other contracts to issue common stock wereexercised or converted into common stock or resulted in the issuance of commonstock that then shared from the earnings of the entity. Potential common sharesfor the periods ended December 31, 2006 and 2004 were excluded from theearnings per share computation because the Company incurred net losses and wereanti-dilutive. At December 31, 2005, 1,506,064 outstanding warrants and20,000 outstanding options to purchase common stock were not included inthe diluted EPS calculation because the warrants’ and options’ exercise priceswere greater than the average market price of the common shares.1,890,710 shares of Series AA Stock were not included in the diluted EPScalculation at December 31, 2005 because they were anti-dilutive.
|                                                     | ** ** | **For the Years Ended December 31,** | ** ** |
|-----------------------------------------------------|------------|---------------------------------------------------------------|------------|
| ** **                                          | ** ** | **2006**                                                      | ** ** | **2005** | ** ** | **2004** | ** ** |
|                                                |       |                                                          |       |   |   |   |   |
| Net Income  (Loss) and Adjustments:                 |       |                                                          |       |   |   |   |   |
| Net Income  (Loss) Available to Common Shareholders |       | $                                                             | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) |
| Adjustments                                         |       | Anti-dilutive                                                 |       | Anti-dilutive |   | Anti-dilutive |   |
| Net Earnings  (Loss) for Diluted Calculation        |       | $                                                             | (1,011,806 | ) | $ | 2,111,074 |   | $ | (2,606,978 | ) |
|                                                |       |                                                          |       |   |   |   |   |
| Shares:                                             |       |                                                          |       |   |   |   |   |
| Weighted Average  Shares Outstanding                |       | 25,990,868                                                    |       | 20,890,841 |   | 18,901,607 |   |
| Outstanding  Options                                |       | Anti-dilutive                                                 |       | 1,927,660 |   | Anti-dilutive |   |
| Series A  Preferred Stock - Conversion              |       | Anti-dilutive                                                 |       | 1,000,000 |   | Anti-dilutive |   |
| Outstanding  Warrants                               |       | Anti-dilutive                                                 |       | 183,387 |   | Anti-dilutive |   |
| Average Number  of Shares for Diluted Calculation   |       | 25,990,868                                                    |       | 24,001,888 |   | 18,901,607 |   |
| Diluted EPS                                         |       | $                                                             | (0.04      | ) | $ | 0.09 |   | $ | (0.14 | ) |

 

*Segment Reporting* — GeoPetro has oil and gas exploration,development and production operations in the United States, Canada,Australia and Indonesia. All revenues and related costs are associated withoperations in the United States. A summary of assets and capital expendituresby geographical segment is included in Note 3.

*Cash Equivalents —*Cash and cash equivalents include cash on hand, amounts held in banksand highly liquid investments purchased with an original maturity of threemonths or less.

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

Capitalized costs at year end and costs incurred relating to GeoPetro’soil and gas activities are summarized as follows:

F-16

----

 
|                                            | ** ** | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals**  | ** ** |
|--------------------------------------------|------------|------------------------|------------|---------------|------------|---------------|------------|------------|------------|-------------|------------|
| 2006 Capitalized  costs:                   |       |                   |       |          |       |          |       |       |       |        |       |
| 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:                            |       |                   |       |          |       |          |       |       |       |        |       |
| 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 |   |

 
|                                            | ** ** | **United States** | ** ** | **Australia** | ** ** | **Indonesia** | ** ** | **Canada** | ** ** | **Totals** | ** ** |
|--------------------------------------------|------------|-------------------|------------|---------------|------------|---------------|------------|------------|------------|------------|------------|
| 2005 Capitalized  costs:                   |       |              |       |          |       |          |       |       |       |       |       |
| 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 |   |
|                                       |       |              |       |          |       |          |       |       |       |       |       |
| Costs incurred:                            |       |              |       |          |       |          |       |       |       |       |       |
| 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 gas properties, includingsales of partial interests in prospects, are treated as adjustments tocapitalized costs, with no gain or loss recorded.

*Evaluated Oil and Gas Properties —*In periods prior to 2004 it was determined that the total net costs inthe U.S. and Australian evaluated cost pool exceeded their net realizablevalue. Accordingly, impairment write-downs of $2,426,526 were recorded inthe prior periods. During 2004 it was determined that the total net costs inthe Australian evaluated cost pool exceeded their net realizable value.Accordingly, impairment write-downs of $1,599,244 were recorded for theyear ended December 31, 2004. In addition, an impairment write-downassociated with the Canadian evaluated

F-17

----

cost pool of $439,178 was recorded for the year ended December 31,2004 and $38,849 was recorded for the year ended December 31, 2006.  

*Unevaluated Oil 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, 2006 and2005 represent exploration costs in connection with GeoPetro’s California andAlaskan prospects. The prospects and their related costs in unevaluatedproperties have been assessed individually. The current status of theseprospects is that seismic data is being interpreted on an on-going basis on thesubject lands within the prospects.

Drilling in California and Alaskan prospects is expected to commence asearly as 2007 and will continue in future periods. As the prospects areevaluated through drilling in future periods, the property acquisition andexploration costs associated with the wells drilled will be transferred toevaluated properties where they will be subject to amortization.

*Unevaluated Oil and Gas Properties — Australia —*Unevaluated costs incurred in Australia represent costs in connectionwith the exploration of two exploration permit areas in Australia. Theprospects and their related costs in unevaluated properties have been assessedindividually and no impairment charges were considered necessary for theAustralian properties for any of the periods presented. The current status ofthese prospects is that appraisal wells have been drilled and are beingevaluated for commerciality on the subject lands within the prospects.

*Unevaluated Oil and Gas Properties — Indonesia —*Unevaluated costs incurred in Indonesia represent costs in connectionwith one production sharing contract area in Indonesia and costs incurred inpursuing additional oil and gas projects in Indonesia. The prospect and itsrelated costs in unevaluated properties have been assessed individually and noimpairment charges were considered necessary for the Indonesian property forany of the periods presented. The current status of this prospect is that fourexploratory locations have been identified for drilling in 2007 on the subjectlands within the prospect.  A drill righas been transported to the prospect and is expected to commence drilling thefirst of four planned wells in the second quarter of 2007. In October 2005, theCompany sold its interest in another Indonesian production sharing contract forcash consideration of $2,400,000.  Theproceeds realized were credited to the Indonesian unevaluated cost pool.

As noted, drilling is expected to commence on the remaining productionsharing contract in 2007 and is expected to continue in future periods. As theprospect is evaluated through drilling in future periods, the propertyacquisition and exploration costs associated with the wells drilled will betransferred to evaluated properties where they will be subject to amortization.

The Company’sinterest in the production sharing contract is 12% and is held in its partiallyowned subsidiary, C-G Bengara.  Theproduction sharing contract is subject to prior work commitments for theeight-year period ended December 3, 2006 requiring total expenditures of $24million. As of September 30, 2006, approximately $6.3 million of the $24.0million required expenditures had been met, leaving an approximate $17.7million shortfall. BP Migas, the applicable governing authority, has granted adeferral of the prior years’ commitments. On September 29, 2006, the Companysold to CNPC 70% of its interest in C-G Bengara and the underlying rights tothe

F-18

----

production sharingcontract, reducing its interest from 40% to 12%. Per the terms of theagreement, CNPC deposited an $18.7 million earning obligation into an accountjointly controlled by CNPC, Continental and the Company. The funds are to beused exclusively to pay for 2007 exploration drilling in the production sharingcontract. The earning obligation funds of $18.7 million, together with the $6.3million previously spent, are expected to satisfy all of the past and futurework commitments on the production sharing contract. As noted above, fourexploration wells are planned for drilling in 2007 with drilling activitiesexpected to commence in the second quarter of 2007. 

In the event that the Company does not meet the work program commitmentsand provided that no extensions are granted for meeting the commitments, theCompany must forfeit its interest in the production sharing contract. If theCompany forfeits its interest, it will be necessary to record an impairmentwrite-down equal to the capitalized costs recorded for the areaforfeited.

*Breakdown of Unevaluated Oil and Gas Properties —*The following table sets forth a summary of oil and gas property costsnot being amortized at December 31, 2006, by the period in which the costswere incurred:
|                                | ** ** | **Totals** | ** ** | **Year Ended  December 31,  2006** | ** ** | **Year Ended  December 31,  2005** | ** ** | **Year Ended  December 31,  2004** | ** ** | **2003 and Prior  Years** | ** ** |
|--------------------------------|------------|------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|----------------------------------------------|------------|-------------------------------------|------------|
|                           |       |       |       |                                         |       |                                         |       |                                         |       |                                |       |
| Unproved  property acquisition |       | $          | 1,853,945  |                                         | $          | 351,803                                      |       | $                                            | —     |                                | $          | 13,475 |   | $ | 1,488,667 |   |
| Exploration                    |       | 2,649,536  |       | 515,174                                      |       | (816,974                                     | )          | (68,144                                      | )          | 3,019,480                           |       |
| Total                          |       | $          | 4,503,481  |                                         | $          | 866,977                                      |       | $                                            | (816,974   | )                                   | $          | (54,669 | ) | $ | 4,508,147 |   |

 

Management expects thatplanned activities for the year 2007 will enable the evaluation ofapproximately 5% of the costs as of December 31, 2006. Evaluation of 30%of the remaining costs is expected to occur in 2008 with the remaining 65% in2009 and beyond.

**4.****                              SHORT AND LONG-TERM DEBT**:

Short term non-convertible debt at December 31, 2006 and 2005consisted of the following:
|                                                                                                                                                                                                                                                    | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|
|                                                                                                                                                                                                                                               |       |       |       |       |       |
| **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 January 31, 2007, including interest at 8% (a) |       | 1,073,205  |       | —     |       |
|                                                                                                                                                                                                                                               |       |       |       |       |       |
|                                                                                                                                                                                                                                               |       | $          | 1,073,205  |       | $          | — |   |
|                                                                                                                                                                                                                                                    |            |            |            |            |            |  |  |

 

F-19

----

----

(a)  The Company issued a$1,000,000 short term promissory note on January 31, 2006 with a maturity dateof January 31, 2007.  The note may berepaid at any time without penalty.  In theevent the note is not repaid by the maturity date, the Company has agreed todedicate 5% of the net cash flow from the Madisonville Project in Texas towardthe repayment of the note and any accrued interest thereon.  In connection with the note, the Company paida loan origination fee of $30,000 and granted a three-year exercisable warrantto purchase 150,000 Common Shares at $3.50 per share. The fair value of thewarrants on the date of issuance, $182,390, as well as the $30,000 loanorigination fee, was recorded as a debt discount and is being amortized overthe life of the promissory note. As of December 31, 2006, the unamortized debtdiscount was $17,699.

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

The provision for income taxesconsist of the following:

|                        | ** ** | **2006** | ** ** | **2005** | ** ** |
|------------------------|------------|----------|------------|----------|------------|
| Current                |       |     |       |     |       |
| Federal                |       | $        | 59,500     |     | $          | 16,000 |   |
| State                  |       | 2,500    |       | 1,000    |       |
| Total                  |       | 62,000   |       | 17,000   |       |
| Deferred               |       |     |       |     |       |
| Federal                |       | —   |       | —   |       |
| State                  |       | —   |       | —   |       |
| Total                  |       | —   |       | —   |       |
|                   |       |     |       |     |       |
| Total Income Provision |       | $        | 62,000     |     | $          | 17,000 |   |

 

The actual income tax (benefit) expense differs from the expected tax (benefit)expense as computed by applying the US Federal corporate income tax rate of 35%for each period as follows:

|                                           | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------------|------------|----------|------------|----------|------------|
|                                      |       |     |       |     |       |
| Amount of expected tax (benefit)  expense |       | $        | (169,000   | )        | $          | 930,000 |   |
| Non-deductible expenses                   |       | 5,000    |       | 5,000    |       |
| Alternative minimum tax                   |       | —   |       | 17,000   |       |
| Expiration of net  operating loss         |       | —   |       | (49,000  | )          |
| Utilization of NOL                        |       | 630,000  |       | —   |       |
| Other                                     |       | (10,000  | )          | 5,000    |       |
| Valuation allowance  adjustment           |       | (394,000 | )          | (891,000 | )          |
|                                      |       |     |       |     |       |
|                                      |       | $        | 62,000     |     | $          | 17,000 |   |

 

Deferred income taxes reflect thenet tax effects of temporary differences between carrying amounts of assets andliabilities for financial reporting purposes and the amounts used for incometax purposes. Significant components of the Company’s deferred tax assets(liabilities) are as follows:

F-20

----

 

|                                         | ** ** | **2006**   | ** ** | **2005**   | ** ** |
|-----------------------------------------|------------|------------|------------|------------|------------|
| Deferred tax assets  (liabilities):     |       |       |       |       |       |
| Net operating  loss carryforwards       |       | $          | 8,654,000  |       | $          | 6,061,000 |   |
| Oil and gas  property basis differences |       | (5,069,000 | )          | (2,018,000 | )          |
| Credit carryforawrds                    |       | —     |       | 16,000     |       |
| Stock  compensation                     |       | 74,000     |       | —     |       |
| Other                                   |       | 13,000     |       | 6,000      |       |
|                                    |       |       |       |       |       |
| Total deferred tax  assets              |       | 3,672,000  |       | 4,065,000  |       |
| Valuation allowance                     |       | (3,672,000 | )          | (4,065,000 | )          |
|                                    |       |       |       |       |       |
| Total net deferred taxes                |       | $          | —     |       | $          | — |   |

 

As of December 31, 2006, GeoPetro had net operating loss (NOL)carryforwards of approximately $22,932,000 for federal beginning to expire in2010 and $10,926,000 for state which began to expire in 2006. A significant change in ownership ofGeoPetro may limit GeoPetro’s ability to use these NOL carryforwards.

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

The Company appointed David G. Anderson as aDirector on March 30, 2006. Mr. Anderson is the Senior Vice Presidentand a director of Dundee Securities Corporation, the lead underwriter inconnection with a sale of common shares the Company completed on March 30,2006. The decision to distribute the common shares and the determination of theterms of the distribution were made through arm’s length negotiations primarilybetween the Company and Dundee Securities Corporation as lead underwriter.Mr. Anderson had some involvement in such negotiations solely in hiscapacity as a director and officer of Dundee Securities Corporation. DundeeSecurities Corporation received an underwriters’ fee totaling $632,000 inconnection with the offering.

On June 6, 2005 the Company purchased139,396 shares of common stock from Stuart Doshi, the Company’s President andChief Executive officer,****at theestimated fair market value prices on that date of $4.25 per share for a totalof $592,433. The Company believes the purchase price of $4.25 per share was atleast as favorable to the Company as could have been obtained through arm’slength negotiations with unaffiliated third parties since the Company also sold939,194 shares of common stock for $4.25 per share in 2005. 

On August 27, 2004, Mr. Doshiexercised an option to purchase 500,000 shares of common stock at an exerciseprice of $1.00 per share. The option was granted to Mr. Doshi onAugust 30, 1999 pursuant to his services as Chief Executive Officer of theCompany. 

On May 31, 2005, David Creel, VicePresident of Exploration and a director, exercised options to purchase 200,000shares of common stock at an exercise price of $2.00 per share. The optionswere granted

F-21

----

to Mr. Creel pursuant to his services asVice President of Exploration as follows: (i) 100,000 options onJune 1, 1998 and (ii) 100,000 options on June 1, 2000.

On April 29, 2005, Thomas Cunningham, adirector, exercised an option to purchase 100,000 shares of common stock at anexercise price of $2.00 per share. The option was granted toMr. Cunningham on April 30, 2000 pursuant to his services as adirector.

On March 25, 2004, Kevin Delehanty, adirector, exercised an option to purchase 70,900 shares of common stock at anexercise price of $1.00 per share. The option was granted to Mr. Delehantyon August 30, 1999 pursuant to his services as a director.

On August 25, 2004, Mr. Delehantyexercised a warrant to purchase 100,000 shares of common stock at an exerciseprice of $1.00 per share. The warrant was granted to Mr. Delehanty onAugust 30, 1999 pursuant to his services as a director.

During 2004, the Company paid cash findersfees of $165,670 to Mr. Delehanty in connection with the Company’s equityand debt financings as follows: (i) $86,545 relating to the privateplacement issuances of 350,800 shares of common stock at $4.25 per share duringJuly, August and September of 2004, and (ii) $79,125 relating tothe conversion into common stock of certain promissory notes and warrants heldby a 5% shareholder as described below.

Effective March 22, 2004, the Companyissued 539,000 shares of common stock to G. Carter Sednaoui and Rolling HillInvestors, LLC, an entity owned by Mr. Sednaoui, a 5% shareholder,pursuant to the exercise of warrants. Concurrently, Mr. Sednaoui andRolling Hill Investors, LLC agreed to a $1,347,500 reduction in theprincipal balance of certain of the Company’s promissory notes payable asconsideration for the exercise of the warrants. The common stock warrants wereexercisable at a price of $2.50 and had an expiration date of December 31,2008. The largest aggregate amount of principal outstanding on these promissorynotes payable during 2004 was $5,130,180. A total of $2,508,948 in principalrepayments were made toward the promissory notes during 2004. A total of$334,358 of interest was paid toward the promissory notes during 2004 atinterest rates between 8% and 11%. The promissory notes have been repaid intheir entirety.

On June 7, 2006, the Company loaned$1,000,000 to G. Carter Sedanoui (“Borrower”), a shareholder, evidenced by ashort term promissory note payable to the Company with a maturity date on March31, 2007.  The note may be repaid at anytime without penalty.  In the event thenote isn’t repaid by the maturity date, the Company has full recourse againstthe Borrower.  In addition, the Borrowerhas granted a security interest in 564,120 shares of the Company’s commonstock.

Effective September 17, 2004, theCompany issued 62,500 shares of common stock to Mr. Sednaoui pursuant tothe conversion of a $250,000 convertible note payable. The convertible note wasissued on September 18, 2001 at an interest rate of 8% per annum for thepurposes of funding the Company’s capital expenditures in the MadisonvilleProject in Texas. The largest aggregate amount of principal outstanding of thisconvertible note payable during 2004 was

F-22

----

$250,000. A total of $14,262 of interest waspaid toward the promissory note during 2004 at an interest rate of 8%. Asindicated, the note was converted in 2004.

Effective September 30, 2004, theCompany issued 117,648 shares of common stock to Mr. Sednaoui in exchangefor a $500,000 reduction in the principal balance of a promissory note payabledated July 19, 2004 as consideration. The largest aggregate amount ofprincipal outstanding of this promissory note payable during 2004 was$2,000,000. A total of $500,000 in principal repayments were made toward thepromissory note during 2004. A total of $37,145 of interest was paid toward thepromissory note during 2004 at an interest rate of 8%.  The promissory note has been repaid in itsentirety.

During 2004, the Company sold 378,448 sharesof common stock at a price of $4.25 per share to Mr. Sednaoui and certainentities owned and controlled by him. The Company believes the purchase priceof $4.25 per share was at least as favorable to the Company as could have beenobtained through arm’s length negotiations with unaffiliated third partiessince the Company sold 939,194 shares of its common stock for $4.25 per sharein the first half of 2005.

Presently, Eric Doshi, Stuart Doshi’s son, isemployed as the Company’s Manager of Planning at an annual salary of $120,000per year. The Company paid Eric Doshi $37,500, $78,540 and $105,689 during2006, 2005 and 2004, respectively, for his services. Eric Doshi’s salary, basedon industry comparables, was at least as favorable to the Company as could havebeen obtained through arm’s length negotiations with unaffiliated thirdparties.

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

GeoPetro’s articles of incorporation allow for the issuance of100,000,000 shares of common stock, 1,000,000 shares of Series A preferredstock (“Series A Stock”), 5,000,000 shares of Series AA preferred stock (“SeriesAA Stock”), and an additional 44,000,000 shares of preferred stock which may beissued from time to time in one or more series.

*Common Stock —*The holders ofcommon stock are entitled to one vote per share. Subject to preferences onoutstanding preferred stock, the holders of common stock are entitled toreceive ratably such dividends as may be declared by the board of directors. Inthe 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.

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

*Preferred Stock*- Significant rights and preferences attaching to the Series AA Stock are asfollows:

*Dividends* — The holders of Series AA Stock are entitled to receive ratablysuch cash dividends, if any, as may be declared from time to time by the boardof directors out of funds legally available therefore and when declared,dividends shall be paid at the rate of $0.07 per

F-23

----

share each calendar quarter. Any quarterly dividends not paid when dueshall be accrued and shall accumulate until paid.

*Preference in Liquidation* — In the event of a liquidation, dissolutionor winding up of GeoPetro, the holders of Series AA Stock are entitled to receive,prior and in preference to any distribution of any assets or surplus funds tothe holders of Series A Stock and common stock, an amount equal to$3.50 per share plus any dividends declared but unpaid on such shares, butno more.

*Voting Rights* — The holders of Series AA Stock are entitled to the number ofvotes equal to the number of shares of common stock into which each share ofpreferred stock is convertible on the record date for the vote.

*Conversion* — Each share of Series AA Stock is convertible, at the option ofthe holder, into fully paid and nonassessable shares of common stock on aone-for-one basis, subject to certain adjustments. If GeoPetro’s common stockis listed on a national or regional exchange, including the NASDOver-the-Counter Bulletin Board, the Series AA Stock will automatically convertinto shares of GeoPetro common stock on a one-for-one share basis effective thefirst trading day after the reported high selling price for GeoPetro’s commonstock is at least $5.25 per share for any consecutive ten trading days. If anautomatic conversion occurs within one year after issuance of the Series AAStock, a holder will receive, on the one year anniversary date of the issuanceof the Series AA Stock, a final cash dividend equivalent to a full year ofdividends less any dividends paid before such conversion.

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

Effectiveas of September 10, 2001, the board of directors approved an incentivestock plan, providing for awards under the terms and provisions of such plan ofincentive stock options, stock appreciation rights and restricted stock awardsto officers, directors and employees of GeoPetro and its consultants (the “StockIncentive Plan”). The plan provides, among other provisions, the following:

Themaximum number of Common Shares which may be awarded, optioned and sold underthe plan is 5,000,000 (subject to adjustment for stock splits, stock dividendsand certain other adjustments to GeoPetro’s common stock); and the per shareexercise price for Common Shares to be issued pursuant to the exercise of anoption shall be no less than the fair market value of GeoPetro’s Common Sharesas of the date of grant.

TheStock Incentive Plan provides for the granting to employees of incentive stockoptions within the meaning of Section 422 of the United StatesInternal Revenue Code of 1986, as amended, and for the granting ofnon-statutory stock options to directors who are not employees and consultants.In the case of employees who receive incentive stock options which are first exercisablein a particular calendar year and the aggregate fair market value of whichexceeds $100,000, the excess of the $100,000 limitation shall be treated as anonstatutory stock option under the Stock Incentive Plan.

F-24

----

TheStock Incentive Plan is being administered by the Board of Directors. The Boardof Directors determines the terms of the options granted, including the numberof Common Shares subject to each option, the exercisability and vestingrequirements of each option, 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).

TheStock Incentive Plan will continue in effect for 10 years fromSeptember 10, 2001 (i.e., the date first adopted by the Board),unless sooner terminated by the board of directors. The Company has implementeda new 2004 Stock Option and Appreciation Rights Plan (the ”Stock OptionPlan”) for the issuance of options to purchase Common Shares and/or stockappreciation rights in 2004 or thereafter to directors, officers, employees andconsultants of the Company and its subsidiaries. The Stock Option Plan hasreplaced the Stock Incentive Plan. Outstanding options issued under the StockIncentive Plan will continue to be outstanding in accordance with their termsand the terms of the Stock Incentive Plan, but will count toward the limits inthe amount of Common Shares available to be issued under the Stock Option Plan.

During2004 no options were issued to employees or directors. No stock-basedcompensation was recognized for the years ended December 31, 2005.Effective January 1, 2006, the Company adopted SFAS 123 ( R ) resulting instock compensation expense for the twelve months period ended December 31, 2006of $201,335. During 2004, the Company issued 500,000 shares of our common stockfor cash proceeds of $500,000 in connection with the exercise of stock optionsby an officer and director. Concurred with the exercise of stock options, theofficer sold 117,647 shares of common stock to the Company at the estimatedfair market value prevailing at that time of $4.25 per share.  We recorded compensation expense of $500,000in connection with the purchase of stock. During 2006,    150,000 stock options were issued todirectors and during 2005, 20,000 stock options were issued to employeespursuant to the Stock Option Plan. 

Asummary of the status of GeoPetro’s stock option plan is as follows:
|                                   | ** ** | **Options** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Exercise Price** | ** ** |
|-----------------------------------|------------|-------------|------------|----------------------|------------|------------------------------------------------|------------|
|                              |       |        |       |                 |       |                                           |       |
| Outstanding at  December 31, 2003 |       | 4,839,750   |       | $0.50 to $3.00       |       | $                                              | 1.66       |   |
| Granted                           |       | —      |       | —               |       | —                                         |       |
| Exercised                         |       | (584,500    | )          | $1.00 to $1.25       |       | 1.00                                           |       |
| Expired                           |       | (100,000    | )          | $1.00                |       | 1.00                                           |       |
| 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       |   |

 

F-25

----

The weighted average fairvalue of options granted during the year ended December 31, 2005, as calculatedunder the Black-Scholes pricing model is $0.70 per share and for theweighted average fair value of options granted in 2006, as calculated under thesame method is $1.83 per share.

The fair value of each option grant is estimated on the date of grantusing the Black-Scholes option pricing model with the following weighted-averageassumptions used for grants in 2005 and 2006: risk-free, weighted-averageinterest rates ranging from 3.75 to 4.9 percent, expected dividend yieldof 0 percent, expected life of 5 years from the date of grant, andexpected volatility of 10 and 58 percent.

The options outstanding as of December 31, 2006 have the followingcontractual lives:
| Number of  Options  Outstanding | ** ** | **Number of  Options  Exercisable** | ** ** | **Exercise  Prices** | ** ** | **Weighted Average  Remaining  Contractual Life** |
|--------------------------------------|------------|------------------------------------------|------------|----------------------|------------|-------------------------------------------------------------|
|                                 |       |                                     |       |                 |       |                                                        |
| 750,000                              |       | 750,000                                  |       | 0.50                 |       | 1.33                                                        |
| 45,250                               |       | 45,250                                   |       | 1.25                 |       | 0.16                                                        |
| 1,290,000                            |       | 1,290,000                                |       | 2.00                 |       | 0.99                                                        |
| 1,750,000                            |       | 1,050,000                                |       | 2.10                 |       | 6.43                                                        |
| 150,000                              |       | 20,000                                   |       | 3.85                 |       | 4.29                                                        |
| 10,000                               |       | 4,000                                    |       | 4.25                 |       | 3.01                                                        |
| 10,000                               |       | 2,000                                    |       | 6.25                 |       | 3.44                                                        |
| 4,005,250                            |       | 3,161,250                                |       |                 |       |                                                        |

 

As of December 31, 2006, there are 3,161,250 options which areexercisable. The remaining 844,000 options will become exercisable ratably overthe next four years.

**9.         CommonStock Warrants**:

In conjunction with the finance with a short term note payable during2006, GeoPetro issued warrants to purchase 150,000 shares of GeoPetro’s commonstock at exercise prices of $3.50 per share. The purchase rights under thewarrants have expiration date of January 31, 2009 unless terminated earlier inaccordance with the stock warrant purchase agreement. The fair value of thewarrants issued on the date of the grant, $182,390, was recorded as a discountto notes payable and is being amortized as interest expense over the term ofthe note.  As of December 31, 2006, theunamortized amount is $17,966.

F-26

----

The following table summarizes the number of shares reserved for theexercise 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     |   |
| 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 equity securities during2005, GeoPetro issued warrants to purchase 37,000 shares of GeoPetro’s commonstock at exercise prices of $5.00 per share. The purchase rights under thewarrants have expiration dates from June 30, 2006 to February 28, 2008 unlessterminated earlier in accordance with the stock warrant purchase agreement. TheCompany agreed to extend the warrants by a period of one year for a total of143,334 shares. The fair value of the warrants on the date of extension,$32,404, was recorded as compensation expense and $2,927 was recorded asconsulting expense.

F-27

----

 

The following table summarizes the number of shares reserved for theexercise 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    |       |

 

In conjunction with the issuance of units of equity securities during2004, GeoPetro issued warrants to purchase 155,000 shares of GeoPetro’scommon stock at exercise prices ranging from $5.00 to $5.25 per share. Thepurchase rights under the warrants have expiration dates from December 31,2005 to March 31, 2009 unless terminated earlier in accordance with thestock warrant purchase agreement.

During 2004, in conjunction with the issuance of promissory notes,GeoPetro issued warrants to purchase 64,375 shares of GeoPetro’s commonstock at an exercise price of $5.00 per share. The purchase rights under thewarrants have expiration dates from July 19 to September 30, 2008,unless terminated earlier in accordance with the stock warrant purchaseagreement. The fair value of the warrants on the date of issuance, $31,729, wasrecorded as a debt discount and was being amortized over the life of thepromissory notes.

F-28

----

 

The following table summarizes the number of shares reserved for theexercise of common stock purchase warrants as of December 31, 2004:

 
|                | ** ** | ** **     | ** ** | ** **   | ** ** | ** **   | ** ** | ** **    | ** ** | ** **   | ** ** | **Warrants**   | ** ** | ** **   | ** ** |
|----------------|------------|----------------|------------|--------------|------------|--------------|------------|---------------|------------|--------------|------------|----------------|------------|--------------|------------|
| ** **     | ** ** | **Expiration** | ** ** | **Exercise** | ** ** | **12/31/03** | ** ** | **Warrants**  | ** ** | **Warrants** | ** ** | **Extended**   | ** ** | **12/31/04** | ** ** |
| ** **     | ** ** | **Date**       | ** ** | **Price**    | ** ** | **Shares**   | ** ** | **Exercised** | ** ** | **Granted**  | ** ** | **(canceled)** | ** ** | **Shares**   | ** ** |
|           |       |           |       |         |       |         |       |          |       |         |       |           |       |         |       |
| Common Stock   |       | 09/17/04       |       | $            | 2.50       |         | 100,000    |          | —     |         | —     |           | (100,000   | )            | —     |   |
| 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       |       | $            | 4.00       |         | 10,000     |          | —     |         | —     |           | —     |         | 10,000     |   |
| Common Stock   |       | 12/31/05       |       | $            | 5.00       |         | —     |          | —     |         | 50,000     |           | —     |         | 50,000     |   |
| Common Stock   |       | 11/01/06       |       | $            | 3.00       |         | 20,000     |          | —     |         | —     |           | —     |         | 20,000     |   |
| Common Stock   |       | 12/31/06       |       | $            | 2.00       |         | 75,000     |          | —     |         | —     |           | —     |         | 75,000     |   |
| Common Stock   |       | 05/01/07       |       | $            | 5.25       |         | —     |          | —     |         | 5,000      |           | —     |         | 5,000      |   |
| Common Stock   |       | 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  |          | —     |         | —     |           | —     |         | 1,161,356  |   |
| Common Stock   |       | 12/31/08       |       | $            | 2.50       |         | 439,000    |          | —     |         | —     |           | (439,000   | )            |       |   |
| Common Stock   |       | 03/31/09       |       | $            | 5.25       |         | 100,000    |          | —     |         | 100,000    |           | —     |         | 100,000    |   |
|           |       |           |       |         |       |         |       |          |       |         |       |           |       |         |       |
| Related Party: |       |           |       |         |       |         |       |          |       |         |       |           |       |         |       |
| Common Stock   |       | 08/30/04       |       | $            | 1.00       |         | 100,000    |          | (100,000   | )            | —     |           | —     |         | —     |   |
| 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    |   |
|           |       |           |       |         |       |         |       |          |       |         |       |           |       |         |       |
|           |       |           |       |         |       | 2,537,148    |       | (100,000      | )          | 219,375      |       | (539,000       | )          | 2,117,523    |       |

 

**10.       Commitmentsand Contingencies**:

*Employment Agreements* — The Company entered into a contract ofemployment with Stuart J. Doshi, Founder, President, Chief Executive Officerand Chairman of the Board of Directors, dated July 28, 1997 (effectiveJuly 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 a five-year term commencing May 1,2005 which term is automatically extended for successive two-year renewalterms unless: (a) the board of directors elects not to renew the contractand the Company provides notice to Mr. Doshi of such non-renewal atleast six months prior to the expiry of his employment term or any renewalterm, or (b) Mr. Doshi attains age 75, in which case the termends upon the completion of the calendar year in which he becomes 75 yearsold unless the Company and Mr. Doshi mutually agree to one-yearextensions. The contract of employment currently provides for an annual basesalary of $300,000 and further provides that in the event of a change ofcontrol of the Company or if Mr. Doshi is terminated without cause, he isentitled to receive (a) in exchange for all

F-29

----

of his vested stock options and vested restricted shares, such number ofCommon Shares having a market value equal to the difference between (x)the aggregate total market value of all vested restricted shares and Common Shareshe would receive 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 ofcontrol or termination without cause, all unvested options issued by theCompany to Mr. Doshi will vest.

GeoPetro has executed an employment contract dated April 28, 1998and amended on June 15, 2000, May 12, 2003 and January 1, 2005with its Vice President of Exploration, David V. Creel. The contract providesan annual salary of $150,000 and may be terminated by GeoPetro without causeupon the payment to Mr. Creel of cash payments equal to the lesser ofthree months’ base salary or base salary during the remainder of the employmentterm, and, in the event of termination without cause, all unvested optionsissued by GeoPetro to Mr. Creel will vest.

GeoPetro has executed an employment contract dated June 19, 2000and amended on December 12, 2002 and January 1, 2005 with its VicePresident of Finance and Chief Financial Officer, J. Chris Steinhauser. Thecontract provides for an annual salary of $150,000 and may be terminated byGeoPetro without cause upon the making of cash payments equal to the lesser ofthree months’ base salary or base salary during the remainder of the employmentterm, and, in the event of termination without cause, all unvested warrantsissued by GeoPetro to Mr. Steinhauser will vest.

*Office Lease —*EffectiveMarch 1, 2004, GeoPetro is committed under an office sublease whichprovides for a sixty month term. The sublease provides for minimum monthlylease payments of $5,788 during the first thirty-six months of the lease termand $6,527 per month from the thirty-seventh month to the sixtieth month.Minimum annual rentals due under this agreement are as follows:

F-30

----

 

| Year   | ** ** | **Amount** | ** ** |
|--------|------------|------------|------------|
|   |       |       |       |
| 2007   |       | 76,856     |       |
| 2008   |       | 78,334     |       |
| 2009   |       | 13,056     |       |

 

Rent expense for the years ended December 31, 2006, 2005 and 2004, wasapproximately $69,466, $69,466, and $67,138, respectively, and is included ingeneral and administrative expenses in the accompanying statements ofoperations.

*Madisonville MGP 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 MagnessNo. 1 well (originally drilled in 1994) and the drilling of additionalwell locations. The natural gas in the Rodessa formation contains 28%impurities which must be removed in order to meet pipeline qualityspecifications.

In this connection, GeoPetro entered into agreements with a subsidiaryof a NYSE listed company, Hanover Compressor Company (“Hanover”), that funded,constructed, installed and operated a dedicated gas treatment plant to processthe Rodessa gas. The gas treatment plant is presently capable of treating andbringing up to pipeline specifications approximately 18 million cubic feetof inlet gas per day. Gateway Processing Company (“Gateway”) has installedfield gathering pipelines and a sales pipeline with an estimated capacity of atleast70 million cubic feet of gas per day to transport the treated naturalgas to a major pipeline in the area.

Effective July 25, 2005, Madisonville Gas Processing, LP (“**MGP**”) purchased the natural gas treatmentplant from Hanover. Concurrent with MGP’s purchase of the gas treatment plant,the Company, Gateway and MGP terminated the Hanover/Gateway agreements andentered into a new agreement, (the “**MGPAgreement**”), to treat and transport the Company’s gas productionfrom the Madisonville Project. As a result of the MGP Agreement, MGP hascommitted 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 term of the MGP Agreement commenced August 1, 2005 andcontinues 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 Project to MGP. MGP purchases the untreated natural gas from theCompany at the well site point of delivery for a net price equal to theweighted average price per MMBTU that MGP receives for the natural gasdelivered to the sales pipeline less certain gathering, treatment andtransportation 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 the Company and MGP.

F-31

----

The MGP Agreement provides that certain gathering, treating andtransportation fees shall be paid to MGP from the escrow account. The MGPAgreement provides that MGP will receive a gathering and marketing fee of $0.07and $0.01 per Mcf, respectively, of gas measured and delivered to the naturalgas treatment plant. In addition, for the first 18,000 Mcf/d of gasmeasured and delivered to the inlet flange of the gas treatment plant, MGP willreceive 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) ofthe foregoing treating fees will be adjusted using the Producer Price Index forIndustrial Commodities (“PPI”) and one-quarter ( 1/4) usingthe Consumer Price Index (“CPI”) commencing January 1, 2006. One-half ( 1/2) ofthe foregoing gathering and marketing fees will be adjusted using the ConsumerPrice Index (“CPI”) commencing January 1, 2006. The Company has the right,upon giving 60 days’ notice, to terminate the marketing fee whereupon itshall assume the sole responsibility of marketing the natural gas sold.

For the first 18,000 Mcf/d of gas measured and delivered tothe inlet flange of the gas treatment plant, Gateway will receive atransportation fee of $0.10 per Mcf. This fee will remain in effect for36 months from the effective date of the MGP Agreement. Beginning in the37th month and terminating at the end of the 60th month from the effective date of the MGPAgreement, the fee shall be reduced to $0.08 per Mcf for the first18,000 Mcf/d of gas measured and delivered to the inlet flangeof the gas treatment plant. For any gas volumes in excess of 18,000 Mcf/dof gas measured and delivered to the inlet flange of the gastreatment plant, Gateway will receive a transportation fee of $0.12 per Mcfmeasured and delivered from the outlet flange of the plant. Thisfee will remain in effect 36 months from the effective date of the MGPAgreement 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 transportation price adjustmentsare inclusive of all costs and expenses to gather, separate, treat, dehydrateand transport natural gas produced and delivered from the Company’s well(s).

The Company has committed to a three-well drilling program tofacilitate the expansion of the gas treatment plant. The Company has drilledtwo of the three required wells to the Rodessa formation. The commitmentrequires the Company to commence the drilling of the third well sufficient totest the Smackover Formation (estimated to be encountered at approximately18,000 feet) on or before September 30, 2008. It is estimated that the18,000 foot well will cost $10 million to drill and complete. The Company hasgranted MGP a security interest in the Madisonville Field properties to securethe three well commitment. The security interest shall be subordinated to any thirdparty lender in the event the Company secures future debt against the property.MGP has granted the Company a similar security interest in the gas treatmentplant to secure its obligation to expand the treatment plant on a timely basis.

*Madisonville Net Profits Interest —*GeoPetro’s working interest is subject to a net profits interest infavor of an unrelated third party. The net profits interest is 12.5%(proportionately reduced) of the net operating profits until payout is achieved.After payout, the net

F-32

----

profits interest increases to 30% (proportionately reduced). Payout, forpurposes of the net profits interest, is defined and achieved at such time asGeoPetro has recouped from net operating cash flows its total net investment inthe project plus a 33% cash on cash return.

*TheCook Inlet Alaska CBM Project* — The Company enteredinto an agreement with Pioneer Oil Company, Inc. (“Pioneer”) datedApril 20, 2005, wherein it acquired a 100% working interest (81% netrevenue interest) in approximately 117,000 acres onshore in Cook Inlet,Alaska. The Company has subsequently acquired an additional 5,000 acres in thisproject. The terms provide for the Company to pay total consideration of $20per acre, or approximately $2.3 million, for the leases. The Optionprovides that the Company will pay the total lease consideration in twoinstallments. The Company paid the first installment totaling $1,068,063 onAugust 17, 2005 and has received assignment of the 100% working interestin the leases. Within three years from the date of receipt of legallysufficient assignment of the 100% working interest in the leases, the Companyhas the option to conduct a $2.5 million work program consisting of, butnot limited to, a multiple test well drilling program on the leases over athree-year period, and, after completion of the work program and an evaluationof the results, to remit the final additional acreage consideration of $10 peracre for the leases. The agreement provides that if the Company fails to paythe lease consideration when due, fails to perform the work program orotherwise defaults under the agreement, it shall forfeit its interest andreassign the leases to Pioneer with no further liability to GeoPetro.

**11.       SubsequentEvents**:

*Proceeds from Notes —*  The Company issued threepromissory notes in February 2007 as the following:

·                  The Company issued a $500,000 short term Notepayable on February 1, 2007 with a maturity date of October 31, 2007.  The note may be repaid at any time without penalty.  The principal plus accrued interest on thenote are due on the maturity date. In connection with the note, the Companypaid a loan origination fee of $15,000 and granted a three-year exercisablewarrant to purchase 25,000 Common Shares at $3.50 per share.

·                  The Company issued a $300,000 short term Notepayable on February 6, 2007 with a maturity date of October 31, 2007.  The note may be repaid at any time withoutpenalty. The principal plus accrued interest on the note are due on thematurity date. In connection with the note, the Company paid a loan originationfee of $9,000 and granted a three-year exercisable warrant to purchase 15,000Common Shares at $3.50 per share.

·                  The Company issued a $100,000 short term Notepayable on February 1, 2007 with a maturity date of October 31, 2007.  The note may be repaid at any time withoutpenalty. The principal plus accrued interest on the note are due on thematurity date. In connection with the note, the Company paid a loan originationfee of $3,000 and granted a three-year exercisable warrant to purchase 5,000Common Shares at $3.50 per share.

F-33

----

*Note Extension* — On February 1, 2007, the Company received an extension of its notepayable to Pine Hill Capital, LLC and the new maturity date is October 31,2007. Under the agreement, the Company agreed to repay the entire remainingprincipal balance plus accrued interest on October 31, 2007. In the event thisNote is not repaid by the maturity date, and unless an extension thereof ismutually agreed to, per the terms of the Note, the Company agreed that it shalldedicate 5% of its net cash flow from the Madisonville Project located inMadison County, Texas 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 shall mean gross revenues received by the Companyless royalties, production taxes and net profits interest expense. The Company has paid $80,000 accrued interestthru January 31, 2007. In connectionwith the extension, the Company paid a loan extension fee of $30,000 andgranted a three-year exercisable warrant to purchase 50,000 Common Shares at$3.50 per share.

*WarrantsIssued*— On February12, 2007, the Company issued a two-year exercisable no par voting common stockwarrant to Rincon Energy, LLC to purchase 20,000 Common Shares at $3.50 pershare. The purchase rights under the warrant has an expiration dates ofFebruary 12, 2009 unless terminated earlier in accordance with the stockwarrant purchase agreement.

On February 28,2007, the Company issued a two-year exercisable no par voting common stockwarrant to Rincon Energy, LLC to purchase 5,000 Common Shares at $4.51 pershare. The purchase rights under the warrant has an expiration date of February28, 2009 unless terminated earlier in accordance with the stock warrantpurchase agreement.

*Related Party Promissory Note –*OnFebruary 12, 2007, Stuart J. Doshi, President and CEO, loaned $100,000 to theCompany.  The note bears interest at 8%annually and is payable on demand.  Thenote plus accrued interest was repaid on March 28, 2007.

*Note Receivable Extension –*OnJune 7, 2006, the Company loaned $1,000,000 to G. Carter Sedanoui, a 5% shareholder,evidenced by a short term promissory note payable to the Company with anoriginal maturity date of March 31, 2007. On March 30, 2007, the Companyextended the maturity date of the note to June 30, 2007.

*Salary Increases –*OnDecember 18, 2006, the independent members of the board of directors, acting onthe recommendations of Stuart J. Doshi, the President and CEO, voted toincrease the salaries of Messrs. Creel and Steinhauser, officers of theCompany, to $163,200 annually effective January 1, 2007.

*Conversion of Series AA Preferred Stock–*On March 28, 2007, all 1,890,710 of the Company’s outstanding sharesof Series AA Stock automatically converted into 1,890,710 shares of ourcommon stock, no par value per share. Under the Company’s Amended and Restated Articles of Incorporation, andas more fully described in Note 7, the Series AA stock automaticallyconverts into common shares on a one-for-one share basis effective the firsttrading day after the reported high selling price for our common shares is atleast $5.25 per share for any consecutive ten trading days, which condition wasmet on March 27, 2007.  Dividendsaccrued on the Series AA Stock at a rate of $0.28 per annum, per share, whilethe Series AA Stock was outstanding.  In2006, dividends paid on the Series AA Stock totaled $529,400. Pursuant to theterms of the Series AA Stock, no dividends are payable for the first quarter of2007.

**12.      ****UNAUDITED SUPPLEMENTARY OIL AND GAS RESERVE INFORMATION:**

The following supplementary information is presented in compliance withUnited States Securities and Exchange Commission regulations and is not coveredby the report of GeoPetro’s independent registered public accountants. Theinformation required to be disclosed for the years ended 2006, 2005 and 2004 inaccordance with FASB Statement No. 69, “Disclosures about Oil and GasProducing Activities,” is discussed below and is further detailed in thefollowing tables.

The reserve quantities and valuations for fiscal 2006 are based uponestimates by MHA Petroleum Consultants. The reserve quantities and valuations for fiscal 2005 and 2004 are basedupon estimates by Sproule Associates Inc. The proved reserves presentedherein are located entirely within the United States. Proved reserves arethe estimated quantities of crude oil, natural gas and natural gas liquidswhich geological and engineering data demonstrate with reasonable certainty tobe recoverable in future years from known reservoirs under existing economicand operating conditions, i.e. prices and costs as of the date the estimate ismade. Prices include consideration of changes in existing prices provided onlyby contractual arrangements, but not on escalations based upon futureconditions. Reservoirs are considered proved if economic productivity issupported by 

F-34

----

either actual production or a conclusive formation test. The area of areservoir considered proved includes (A) that portion delineated bydrilling and defined by gas-oil and/or oil-water contacts, if any, and(B) the immediately adjoining portions not yet drilled, but which canreasonably be judged as economically productive on the basis of available geologicaland engineering data. In the absence of information on fluid contacts thelowest known structural occurrence of hydrocarbons controls the lower provedlimit of the reservoir.

Proved developed reserves are reserves that can be expected to be recoveredthrough existing wells with existing equipment and operating methods.Additional oil and gas reserves expected to be obtained through the applicationof fluid injection or other improved recovery techniques for supplementing thenatural forces 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.

The estimates included in the following tables are by their natureinexact and are subject to changing economic, operating and contractualconditions. At December 31, 2006, all of GeoPetro’s reserves areattributable to two producing wells and two shut-in wells. Other than the oneproducing well which has been on production since May 2003 and another wellwhich was placed on production in March 2006, there is no other productionhistory as of or subsequent to that date. Reserve estimates for these wells aresubject to substantial upward or downward revisions after production commencesand a production history is obtained. Accordingly, reserve estimates of futurenet revenues from production may be subject to substantial revision from yearto year. Reserve information presented herein is based on reports prepared byindependent petroleum engineers.

The assumptions used to compute the standardized measure are thoseprescribed by the Financial Accounting Standards Board and, as such, do notnecessarily reflect GeoPetro’s expectations for actual revenues to be derivedfrom those reserves nor their present worth. The limitations inherent in thereserve quantity estimation process, as discussed previously, are equallyapplicable to the standardized measure computations since these are the basisfor the valuation process.

The Company’sproved reserves increased during 2006 due to revisions of previous estimates.This occurred due to the drilling of additional wells in the Company’s MadisonvilleProject. The drilling and testing resulted in lowering the lowest knownstructural occurrence of hydrocarbons, thus extending the lower proved limit ofthe reservoir.

F-35

----

**CHANGESIN QUANTITIES OF PROVED PETROLEUM AND NATURAL GAS RESERVESFOR THE YEARS ENDED DECEMBER 31  (UNAUDITED)**
| ** **                  | ** ** | **December 31,** | ** ** | **December 31,** | ** ** | **December 31,** | ** ** |
|-----------------------------|------------|-----------------------|------------|-----------------------|------------|-----------------------|------------|
| **FACTORS**                 | ** ** | **2006**              | ** ** | **2005**              | ** ** | **2004**              | ** ** |
| ** **                  | ** ** | **(MMcf)**            | ** ** | **(MMcf)**            | ** ** | **(MMcf)**            | ** ** |
| **Beginning of period**     |       | 21,428                |       | 18,408                |       | 25,238                |       |
| Extensions                  |       | —                |       | —                |       | —                |       |
| Improved  Recovery          |       | —                |       | —                |       | —                |       |
| Technical  Revisions        |       | 5,122                 |       | 4,763                 |       | (4,803                | )          |
| Discoveries                 |       | —                |       | —                |       | —                |       |
| Acquisitions                |       | —                |       | —                |       | —                |       |
| Dispositions                |       | —                |       | —                |       | —                |       |
| Economic Factors            |       | —                |       | —                |       | —                |       |
| Production                  |       | (1,950                | )          | (1,742                | )          | (2,027                | )          |
| **Year ended December 31,** |       | 24,600                |       | 21,428                |       | 18,408                |       |

** **

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

|                                 | ** ** | **AS OF DECEMBER 31,** | ** ** |
|---------------------------------|------------|---------------------------------------|------------|
| ** **                      | ** ** | **2006**                              | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                      | ** ** | **(MMcf)**                            | ** ** | **(MMcf)** | ** ** | **(MMcf)** | ** ** |
| Proved developed                |       | 12,235                                |       | 4,645 |   | 4,448 |   |
| Proved developed  non-producing |       | 12,365                                |       | 8,903 |   | 7,037 |   |
| Proved undeveloped              |       | —                                |       | 7,881 |   | 6,923 |   |
|                            |       |                                  |       |   |   |   |   |
| Total                           |       | 24,600                                |       | 21,428 |   | 18,408 |   |

 

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 and production costs were computed by applyingyear-end costs to be incurred in producing and further developing the provedreserves. Future income tax expenses were computed by applying, generally,year-end statutory tax rates (adjusted for permanent differences, tax creditsand allowances) to the estimated net future pre-tax cash flows. The discountwas computed by application of a 10% discount factor. The calculations assumethe continuation of existing economic, operating and contractual conditions.However, such arbitrary assumptions have not proven to be the case in the past.Other assumptions of equal validity could give rise to substantially differentresults.

F-36

----

**STANDARDIZEDMEASURE OF DISCOUNTED FUTURE NET CASH FLOWSRELATING TO PROVED PETROLEUM AND NATURAL GAS RESERVES (UNAUDITED)**
|                                                          | ** ** | **YEAR ENDED DECEMBER 31,** | ** ** |
|----------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                               | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                               | ** ** | **(in thousands)**                    | ** ** |
| Future cash inflows                                      |       | 101,867                                    |       | $ | 162,459 |   | $ | 90,815 |   |
| Future production costs                                  |       | (37,783                                    | )          | (60,176 | ) | (30,240 | ) |
| Future development costs                                 |       | (1,075                                     | )          | (6,560 | ) | (4,860 | ) |
| Future income taxes                                      |       | (8,128                                     | )          | (18,941 | ) | (9,609 | ) |
| Future net cash flows                                    |       | 54,882                                     |       | 76,782 |   | 46,106 |   |
| 10% annual discount                                      |       | (8,341                                     | )          | (13,293 | ) | (8,455 | ) |
| Standardized measure of discounted future net cash flows |       | $                                          | 46,541     |   | $ | 63,489 |   | $ | 37,651 |   |
|                                                          |            |                                            |            |  |  |  |  |  |  |  |

 

**AVERAGE YEAR-END PRICE**
| 2006 REPORT       | ** ** | **2005 REPORT**   | ** ** | **2004 REPORT**   | ** ** |
|------------------------|------------|------------------------|------------|------------------------|------------|
| **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** | **Gas ($/MMBtu)** | ** ** |
| $                      | 5.40       |                   | $          | 7.80                   |       | $ | 5.82 |   |
|                        |            |                        |            |                        |            |  |  |  |

 

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

**CHANGESIN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASHFLOWS FROM PROVED PETROLEUM AND NATURAL GAS RESERVEQUANTITIES (Unaudited)PROVED RESERVES ARE LOCATED ENTIRELY WITHIN THE UNITED STATES**
| ** **                                                                                    | ** ** | **2006**                       | ** ** | **2005** | ** ** | **2004** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|--------------------------------|------------|----------|------------|----------|------------|
| ** **                                                                                    | ** ** | **(in $ thousands)** | ** ** |
| Standardized measure of  discounted future net cash flows, beginning of period                |       | $                              | 63,489     |     | $          | 37,651   |       | $ | 41,031 |   |
| Sales of Oil and  Natural Gas and NGLs Produced, Net of Production Costs, Taxes and Royalties |       | (4,480                         | )          | (6,228   | )          | (4,454   | )          |
| Net Change in  Prices, Production Costs and Royalties Related to Future Production            |       | (39,067                        | )          | 20,399   |       | 6,335    |       |
| Changes in  Previously Estimated Development Costs Incurred During the Period                 |       | 6,545                          |       | 2,800    |       | 7,187    |       |
| Changes in  Estimated Future Development Costs                                                |       | (1,075                         | )          | (4,410   | )          | (4,382   | )          |
| Net Change  Resulting from Revisions in Quantity Estimates                                    |       | 1,074                          |       | 18,524   |       | (12,535  | )          |
| Extensions                                                                                    |       | 6,740                          |       | —   |       | —   |       |
| Accretion of  discount                                                                        |       | 8,019                          |       | 3,765    |       | 4,103    |       |
| Other                                                                                         |       | (4,656                         | )          | (1,296   | )          | (2,868   | )          |
| Net Change in  Income Taxes                                                                   |       | 9,952                          |       | (7,716   | )          | 3,234    |       |
| Standardized measure of discounted future net cash flows, end of  period                      |       | $                              | 46,541     |     | $          | 63,489   |       | $ | 37,651 |   |

** **

 

F-37

----

**EXHIBIT INDEX**

 
| Exhibit  Number   | ** ** | **Description**                                                                                                                                                                                              |
|-------------------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   3.1** |       | Amended and Restated Articles of Incorporation of  GeoPetro Resources Company                                                                                                                                |
|   3.2*  |       | Amended and Restated Bylaws of the GeoPetro  Resources Company                                                                                                                                               |
|   4.1** |       | Form of Warrant issued by GeoPetro Resources  Company to various investors on various dates.                                                                                                            |
|   4.2** |       | Specimen Common  Stock Certificate                                                                                                                                                                           |
| 10.1**            |       | Joint Venture Agreement Bengara II, Dated  January 1, 2000                                                                                                                                              |
| 10.2**            |       | Production Sharing Contract Bengara II, Dated  December 4, 1997                                                                                                                                         |
| 10.3**            |       | Joint Venture Agreement—Whicher Range, Dated  October 28, 1996                                                                                                                                     |
| 10.4**            |       | Exploration Permit #408, Dated July 2, 1997                                                                                                                                                             |
| 10.5**            |       | Madisonville Field Development Agreement Dated August 1,  2005                                                                                                                                          |
| 10.6**            |       | Alaska Cook Inlet Option dated April 20, 2005                                                                                                                                                           |
| 10.7**†      |       | The 2001 Stock Incentive Plan                                                                                                                                                                                |
| 10.8**†      |       | The 2004 Stock Option and Appreciation Rights Plan                                                                                                                                                           |
| 10.9**†      |       | 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**†     |       | David Creel Employment Agreement, Dated April 28,  1998 and amendments dated  June 15, 2000, May 12, 2003 and  January 1, 2005                                                                |
| 10.11**†     |       | J. Chris Steinhauser Employment Agreement, Dated  June 19, 2000 and amendments datedDecember 12, 2002 and January 1,  2005                                                                    |
| 10.12**           |       | Office Lease Agreement, Dated effective  March 1, 2004                                                                                                                                                  |
| 10.13**           |       | Promissory Note to Pinehill Capital Inc., Dated January 31,  2006                                                                                                                                       |
| 10.14**           |       | Form of Subscription Agreement for GeoPetro  Resources Company stock executed by various investors on various dates.                                                                                    |
| 10.15**           |       | Promissory Note between GeoPetro Resources Company  and G. Carter Sednaoui, Dated June 7, 2006                                                                                                          |
| 10.16**           |       | Flow-Through Share Agreement between GeoPetro  Resources Company and GeoPetro Canada Ltd., Dated March 30, 2006                                                                                         |
| 10.17**           |       | Form of Flow-Through Share Agreement between  GeoPetro Resources Company and various investors, Dated March 30, 2006                                                                               |
| 10.18**           |       | Promissory Notes between GeoPetro Resources Company  and Stuart J. Doshi, various dates                                                                                                                      |
| 10.19**           |       | Shares Sale & Purchase Agreement Dated September  29, 2006                                                                                                                                               |
| 21.1*             |       | List of Subsidiaries of GeoPetro                                                                                                                                                                             |
| 23.3*             |       | Consent of MHA Petroleum Consultants                                                                                                                                                                         |
| 31.1*             |       | Rule 13a-14(a)/15d-14(a) Certification of Chief  Executive Officer.                                                                                                                                          |
| 31.2*             |       | Rule 13a-14(a)/15d-14(a) Certification of Chief  Financial Officer.                                                                                                                                          |
| 32.1*             |       | Certification of Chief Executive Officer and Chief  Financial Officer of GeoPetro Resources Company pursuant to 18 U.S.C. § 1350.                                                                       |

 

----

*                    Filedherewith

**             Filedas the identically numbered exhibit to the Registration Statement onForm S-1, as amended (No. 333-135485), as filed with the Securitiesand Exchange Commission on June 30, 2006, and incorporated herein by reference.

†       Indicatesa management contract or compensatory plan or arrangement.

65

----