**Exhibit99.1**

 

MHA Petroleum Consultants LLC       

 

**Securities and Exchange Commission Evaluation**

**of the Natural Gas Reserves of**

**Madisonville Field, Madison County, Texas**

**GeoPetro Resources Company**

 

**(As of December 31, 2009)**

 

**Prepared for**

**GeoPetro Resources Company**

 

March 2010

 

MHA Petroleum Consultants LLC

 

143Union Bld., Suite 200       Lakewood,Colorado  80228  USA      Telephone: 303-277-0270      Fax:303-277-0276

 

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March 25,2010

 

Mr. StuartDoshi

GeoPetroResources Company

OneMaritime Plaza, Suite 700

SanFrancisco, CA  94111

 

DearMr. Doshi:

 

Pursuantto your request, MHA Petroleum Consultants LLC (MHA) has prepared an estimateof the reserves and income attributable to the Madisonville Field owned byGeoPetro Resources Company (GeoPetro) as of December 31, 2009.  It is MHA’s understanding that the provedreserves estimated in this report constitute all of the proved reserves ownedby GeoPetro.  The subject property islocated in the state of Texas.  Thisreport has been prepared for GeoPetro’s use in filing with the Securities andExchange Commission (SEC).

 

Thereserve and income data have been estimated using the SEC technical guidelines,as modified at year end 2009.  Forecastoil and gas prices and all operating costs remain constant for the life of thewells.  Hydrocarbon prices used in thepreparation of the report were based on the average price from the first day ofthe month of each month in 2009.  Reserveestimates and cash flow estimates are dependent on the pricing and costparameters used in the report.  Futurevariations in the pricing and cost parameters will cause variations in thereserve and cash flow estimates reported in the evaluation.  The results of this study are summarizedbelow.

 
| ** **                     | ** ** | **Gross  Oil  MBBLS** | ** ** | **Gross  Gas*  MMCF** | ** ** | **Net Oil  MBBLS** | ** ** | **Net Gas*  MMCF** | ** ** | **BFIT Net  Income  M$** | ** ** | **Disc Net  Income  M$ @ 10%** | ** ** |
|--------------------------------|------------|-----------------------|------------|-----------------------|------------|--------------------|------------|--------------------|------------|--------------------------|------------|-------------------------------------|------------|
| Proved Developed Producing     |       | 0.0                   |       | 5,734.2               |       | 0.0                |       | 3,650.6            |       | 4,719.4                  |       | 4,254.5                             |       |
| Proved Developed Non-Producing |       | 0.0                   |       | 10,793.4              |       | 0.0                |       | 6,611.0            |       | 12,036.3                 |       | 9,394.6                             |       |
| Proved Undeveloped             |       | 0.0                   |       | 13,666.2              |       | 0.0                |       | 8,370.6            |       | 8,890.2                  |       | 5,991.8                             |       |
| Total Proved                   |       | 0.0                   |       | 30,193.9              |       | 0.0                |       | 18,632.2           |       | 25,645.9                 |       | 19,640.9                            |       |

 

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*Gasvolumes shown in the above table represent processed, pipeline ready gas.  Net gas volumes specifically excludevolumes associated with the net profits interest (NPI) which burdens the field.

 

Note:Numbers in the above table may not exactly match economic output due torounding.

 

Thefuture net revenue in this report was based on net hydrocarbon volume soldmultiplied by the appropriate price.  Expensesinclude severance and ad valorem taxes, and the normal cost of operating thewells.  Future net cash flow is futurenet revenue minus expenses and any development costs.  The future net cash flow has not beenadjusted for outstanding loans, which may exist, nor does it include anyadjustments for cash on hand or undistributed income.  No attempt has been made to quantify orotherwise account for any accumulated gas production imbalances that may exist.

 

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**Reserve Estimates**

 

## **Reserve estimatesincluded in this study were assigned on the basis of the SEC definitions (as ofyear-end 2009).  All reserve categoriesassigned in this report follow the guidelines of the SEC reserve definitions.The reserve estimates included in this study were estimated by performancemethods, volumetric methods and comparisons with analogous wells, whereapplicable. These methods were deemed appropriate for the purpose of thereport.**

 

## **The reserves shownin this report are estimates only and should not be construed as exactquantities.  Proved reserves are thosequantities of oil and gas which, by analysis of engineering and geosciencedata, can be estimated with reasonable certainty to be economicallyproducible.  If the reserves arerecovered, the revenues therefrom and the costs related thereto could be moreor less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand,the sales rates, prices received for the reserves, and costs incurred inrecovering such reserves may vary from assumptions made while preparing thisreport.  Estimates of reserves mayincrease or decrease as a result of future operations, market conditions, orchanges in regulations.**

 

The Company’s Natural Gas reservesfor the Madisonville Field are located in Madison County, Texas, in the UnitedStates.  As of the effective date of thisreport, there are three producing wells in the field (the Ruby Magness #1,Angela Farris Fannin #1 and Mitchell #1), which produce from the Rodessa “A”and Rodessa “C” limestones.  One otherwell (the Wilson #1) has been drilled and is slated to begin production about July 2010.  The Rodessa zones generally containsignificant natural fractures. Additionally, at least one of the two sub-zones of the Rodessa “C” isvuggy.  The production from these zonesis sour gas containing approximately 28% impurities, including a percentage ofH2S.  Because of this, a plant was built near thefield to strip out the impurities.  Theplant was initially completed in April 2003 and is currentlyoperational.  It is presently capable oftreating approximately 68 MMcfpd of raw gas. The plant is slated to undergo a modification to one of the twoprocessing trains to assist with the removal of diamondoids from the processingstream.  This modification is scheduledto be completed by July 2010.  Historical fuel use for the plant hasbeen approximately 10-12% of the produced gas, and this fuel use percentage hasbeen projected for the time period from January 2010 through June 2010.  Following the planned modification to theplant, there will be a reduced need for fuel gas, as most of the plant will runon electrical power.  Therefore, as of July 2010,the fuel use has been reduced to approximately 7% of the produced gas.

 

In order to capitalize onthe Madisonville Field Rodessa gas reserves, the Company has developed a planto treat the Madisonville Project natural gas and has purchased the gas plantwhich treats the produced gas.  Followingtreatment, the gas is transported by Gateway Processing Company (“Gateway”)approximately nine miles west to the Atmos pipeline or the ETC Katy pipeline.

 

The Company has a 100%working interest in approximately 56% (areally) of the Madisonville Field, anda 100% working interest in all existing and future wells has been used for theeconomic projections.  The net revenueinterest (NRI) to the Company is 75.13% in the Ruby Magness #1 well, 69.9% inthe Fannin well, and 70.0% in the remaining wells, the Mitchell #1, 

 

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the Wilson #1, and PUD #1.  There is a net profits interest (NPI) of12.5% burdening the field, which increases to 30% when the Company has recoupedall capital costs plus a 33% cash on cash return.

 

Thenatural gas reserves for the Madisonville field were estimated volumetrically,based upon seismic data and well log information.  Volumetric reserves were estimated using thenet pay encountered in the existing wellbores along with the structure of theformation from the seismic data. Reservoir thickness was estimated using log data.  Reservoir rock and fluid property data wereobtained from well logs, PVT data, gas analyses, and publishedinformation.  Reservoir pressures werederived from pressure surveys, daily flowing tubing pressure measurements andpublished reports.  Additionally, theRuby Magness #1 well has a capillary string for the injection of chemicals —this string is also used to monitor pressure. Recovery factors for gas reserves were estimated by taking intoconsideration well depths, deliverability characteristics, product prices,assumed abandonment pressures, and operating cost information.  The natural gas reserves are presented inmillions of cubic feet at standard conditions of 14.65 psia and 60 degrees Fahrenheit.

 

Forecasts of net revenuewere prepared by predicting annual production from the reserves and productprices. Annual production was forecasted taking into account historicalproduction trends, planned equipment upgrades, applicable regulatoryconditions, and existing or anticipated contract rates.

 

Note that reserves wereassigned only to those lands directly under GeoPetro owned leases.

 

## **Prices and Costs**

 

Thehydrocarbon prices used in the report were based on the average prices from thefirst day of the twelve calendar months in 2009, per SEC regulations.  Adjustments were made to this price based ondifferentials to the posted prices due to hydrocarbon quality, transportationfees, contract terms, etc.  Allhydrocarbon prices were held constant for the life of the properties with nofuture escalation.

 

Oiland condensate prices were not relevant to the report, as there is no oilproduction from the Madisonville Field.

 

Naturalgas prices were based on the actual average Houston Ship Channel price receivedby GeoPetro on the first day of each month of 2009, which was $3.11 perMMBTU.  This price has been adjusted forgas quality, contractual agreements, transportation and marketing fees,shrinkage and regional price variations. The gas being produced has a heating value of approximately 1000 BTU percubic foot.

 

Operating costs used in thereport were provided by GeoPetro and were estimated at approximately $15,000 to$20,000 per producing well per month going forward.  All operating costs were held constant overthe life of the properties with no future escalation.  Plant operating expenses were applied inaccordance with average values over the past 12 months, adjusted for knowntreatment modifications.  Gas treatmentfees are collected from the royalty owners in accordance with recently executedcontractual agreements.  Transportationfees are also paid to Gateway.  Themethodology is approximately summarized as follows:

 

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| · | Gathering,  Processing and Marketing Fees (paid to GeoPetro by the royalty owners): |
|--------|-------------------------------------------------------------------------------------|
|   |                                                                                |   |   |
|   | Prior  to September 30, 2010:                                                  |   |   |
|   |                                                                                |   |   |
|   | First  18 MMSCFD Raw gas                                                            |   | $1.68  per Mcf inlet gas |
|   | Over  18 MMSCFD Raw gas                                                             |   | $1.26  per Mcf inlet gas |
|   |                                                                                |   |   |
|   | After  September 2010:                                                         |   |   |
|   |                                                                                |   |   |
|   | All  gas                                                                            |   | $1.26  per Mcf inlet gas |
|   |                                                                                |   |   |
| · | Transportation  Fees                                                                |   |   |
|   |                                                                                |   |
|   | Prior  to July 31, 2010:                                                       |   |   |
|   |                                                                                |   |   |
|   | First  18 MMSCFD Raw gas                                                            |   | $0.08  per Mcf inlet gas |
|   | Over  18 MMSCFD Raw gas                                                             |   | $0.10  per Mcf outlet gas |
|   |                                                                                |   |   |
|   | After  July 31, 2010:                                                          |   |   |
|   |                                                                                |   |   |
|   | All  gas                                                                            |   | $0.10  per Mcf outlet gas |
|   |                                                                                |   |   |
| · | Plant  Costs                                                                        |   |   |
|   |                                                                                |   |   |
|   | Approx.  fixed monthly base costs                                                   |   | $351,500  (prior to modification) |
|   |                                                                                |   | $247,700  (after modification) |
|   |                                                                                |   |   |
|   | Variable  costs (after modification)                                                |   | $0.22  per Mcf inlet gas |
|        |                                                                                     |  |  |  |

 

Thesecosts were not independently verified by MHA, but were checked for reasonableness.

 

Developmentcosts for the PUD #1 well have been estimated at approximately $4.2 million.  GeoPetro does have plans to fracture treat theWilson #1 well in 2010 and lay gathering lines to the plant. These costs havebeen estimated at $945,000 based on an internal authority for expenditures(AFE).  Additionally, a cost of $635,000was included to install a submersible pump into the Mitchell #1 well.  The cost to modify the plant to remove thediamondoids from the processed gas stream was estimated at $1,283,000 andincluded in the second half of 2010.  Abandonmentcosts for the wells have been forecast at US$15,000 each, including the wastedisposal well on the property.  Anadditional $500,000 was added for the cost of abandoning the gas plant.  These costs were not independently verifiedby MHA, but were checked for reasonableness.

 

Nodeductions were made for indirect costs such as loan repayments, interestexpenses, and exploration and development prepayments.

 

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Following is the procedureused in calculating the economics for the production streams:

 
| 1) | Gas  production streams from rate analysis were adjusted for GeoPetro lease  ownership and then adjusted for shrinkage. A shrinkage factor of approximately  40% was applied to future gas production prior to the plant modification (28%  impurities plus 12% fuel use). Subsequent to the plant upgrade, the shrinkage  factor used was 35% (28% impurities, 7% fuel). Gross revenue was calculated  based on this adjusted stream, using the constant gas price. |
|----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2) | Net  revenue was calculated based on a 100% working interest to the Company, and a  75.13% net revenue interest (NRI) in the Ruby Magness #1 well, a 69.9% NRI in  the Angela Farris Fannin #1 well, and a 70.0% NRI in the Wilson #1, Mitchell  #1 and PUD#1 wells.                                                                                                                                                                                                 |
| 3) | Severance  taxes were applied at 7.5% of the gas revenue net of gas treatment costs.  Note that the Company has a 10 year moratorium on severance taxes for the  Ruby Magness #1 well.                                                                                                                                                                                                                                                                               |
| 4) | Ad  Valorem taxes were applied at 4% of the net revenue less severance taxes.                                                                                                                                                                                                                                                                                                                                                                                        |
| 5) | Operating  expenses were deducted at the rates stated above.                                                                                                                                                                                                                                                                                                                                                                                                         |
| 6) | A  net profits interest (NPI) was deducted from the revenue stream. The amount  of the NPI is 12.5% of the net operating profits until payout is achieved.  After payout, the NPI increases to 30%. Payout is defined and achieved at  such time as the Company has recouped from net operating cash flows its total  net investment in the project plus a 33% cash on cash return.                                                                                  |
| 7) | Capital expenditures are  applied and net cash flow determined.                                                                                                                                                                                                                                                                                                                                                                                                      |

 

## **Statement of Risk**

 

Theaccuracy of reserve and economic evaluations is always subject touncertainty.  The magnitude of thisuncertainty is generally proportional to the quantity and quality of dataavailable for analysis.  As a wellmatures and new information becomes available, revisions may be required whichmay either increase or decrease the previous reserve assignments.  Sometimes these revisions may result not onlyin a significant change to the reserves and value assigned to a property, butalso may impact the total company reserve and economic status.  The reserves and forecasts contained in thisreport were based upon a technical analysis of the available data usingaccepted engineering principles. However, they must be accepted with the understanding that furtherinformation and future reservoir performance subsequent to the date of theestimate may justify their revision.  Itis MHA’s opinion that the estimated proven reserves and other reserve informationas specified in this report are reasonable, and have been prepared inaccordance with generally accepted petroleum engineering and evaluationprinciples, as set forth in the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserve Information, promulgated by the Society ofPetroleum Engineers.  Notwithstanding theaforementioned opinion, MHA makes no warranties concerning the data andinterpretations of such data.  In noevent shall MHA be liable for any special or consequential damages arising fromGeoPetro’s use of MHA’s interpretation, reports, or services produced as aresult of its work for GeoPetro.

 

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NeitherMHA, nor any of our employees have any interest in the subject properties andneither the employment to do this work, nor the compensation, is contingent onour estimates of reserves for the properties in this report.

 

Thisreport was prepared for the exclusive use of GeoPetro and will not be releasedby MHA to any other parties without GeoPetro’s written permission.  The data and work papers used in thepreparation of this report are available for examination by authorized partiesin our offices.

 

Itwas a pleasure performing this work for GeoPetro.  If you have any questions regarding thisevaluation or if additional information is needed, please contact theundersigned at this office.

 

 
| Sincerely,                   |   |
|------------------------------|--------|
|                         |   |
| /s/  John W. Arsenault       |   |
|                         |   |
| John  W. Arsenault           |   |
| Vice  President              |   |
|                         |   |
| /s/  Dennis P. Holler        |   |
|                         |   |
| Dennis  P. Holler            |   |
| Senior Geological  Associate |   |

 

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