ex99-1.htm

EXHIBIT 99.1

Securities and Exchange Commission Evaluation

of the Natural Gas Reserves of

Madisonville Field, Madison County, Texas

GeoPetro Resources Company

(As of December 31, 2012)

Prepared for

GeoPetro Resources Company

March 2013

MHA Petroleum Consultants LLC

730 17th Street, Suite 410

Denver, Colorado 80202 USA

Telephone: 303-277-0270

Fax: 303-277-0267

March 25, 2013

Mr. Stuart Doshi

GeoPetro Resources Company

150 California Street, Suite 600

San Francisco, CA 94111

Dear Mr. Doshi:

Pursuant to your request, MHA Petroleum Consultants LLC (MHA) has prepared an estimate of the reserves and income attributable to the Madisonville Field owned by GeoPetro Resources Company (GeoPetro) as of December 31, 2012. It is MHA’s understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by GeoPetro. The subject property is located in the state of Texas. This report has been prepared for GeoPetro’s use in filing with the Securities and Exchange Commission (“SEC”).

The reserve and income data have been estimated using the Securities and Exchange Commission (SEC) technical guidelines, as modified at year end 2009. Forecast oil and gas prices and all operating costs remain constant for the life of the wells. Hydrocarbon prices used in the preparation of the report were based on the average price from the first day of the month of each month in 2012. Reserve estimates and cash flow estimates are dependent on the pricing and cost parameters used in the report. Future variations in the pricing and cost parameters will cause variations in the reserve and cash flow estimates reported in the evaluation. The results of this study are summarized below.

	Gross Oil MBBLS		Gross Gas* MMCF		Net Oil MBBLS		Net Gas* MMCF		BFIT Net Income M$		Disc Net Income M$ @ 10%
Proved Developed Producing		—		—		—		—		—		—
Proved Developed Non-Producing		—		14,778.2		—		9,125.9		16,021.2		12,853.7
Proved Undeveloped		—		14,143.3		—		8,662.7		6,552.9		3,294.8
Total Proved		—		28,921.5		—		17,788.7		22,574.1		16,148.5

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

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

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

Reserve Estimates

Reserve estimates included in this study were assigned on the basis of the SEC definitions (as of year-end 2009), included under the tab “Reserve Definitions”. All reserve categories assigned in this report follow the guidelines of the SEC reserve definitions. The reserve estimates included in this study were estimated by performance methods, volumetric methods and comparisons with analogous wells, where applicable. These methods were deemed appropriate for the purpose of the report.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or 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 in recovering such reserves may vary from assumptions made while preparing this report. Estimates of reserves may increase or decrease as a result of future operations, market conditions, or changes in regulations.

The Company’s Natural Gas reserves for the Madisonville Field are located in Madison County, Texas, in the United States. As of the effective date of this report, there are two wells capable of current production (the Ruby Magness #1, and Angela Farris Fannin #1), which are completed in the Rodessa “A” and Rodessa “C” limestones. These two wells have been shut in since early 2012 at the companies election, due to low gas prices. The Mitchell #1 well has produced, but currently needs a downhole pump. One other well (the Wilson #1) has been drilled and is slated to begin production about September 2013. The Rodessa zones generally contain significant natural fractures. Additionally, at least one of the two sub-zones of the Rodessa “C” is vuggy. The production from these zones is sour gas containing approximately 28% impurities, including a percentage of H2S. Because of this, a plant was built near the field to strip out the impurities. The plant was initially completed in April 2003 and is currently capable of normal operation, and can treat approximately 20 MMcfpd of raw gas. The plant is slated to undergo a modification to increase the processing capacity to 30 MMcfpd. This modification is projected to be completed by July 2013. Historical fuel use for the plant has been approximately 10-12% of the produced gas, and this fuel use percentage has been projected for the time period from January 2013 through June 2013. Following the planned modification to the plant (and due to higher throughput), there will be a reduced need for fuel gas due to operating efficiencies. Therefore, as of July 2013, the fuel use has been reduced to approximately 7% of the produced gas.

In order to capitalize on the Madisonville Field Rodessa gas reserves, the Company has developed a plan to treat the Madisonville Project natural gas and has purchased the gas plant which treats the produced gas. Following treatment, 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, and a 100% working interest in all existing and future wells has been used for the economic projections. The net revenue interest (NRI) to the Company is 75.13% in the Ruby Magness #1 well, 69.9% in the Fannin well, and 70.0% in the remaining wells, the Mitchell #1, the Wilson #1, and PUD #1. There is a net profits interest (NPI) of 12.5% burdening the field, which increases to 30% when the Company has recouped all capital costs plus a 33% cash on cash return.

The natural gas reserves for the Madisonville field were estimated volumetrically, based upon seismic data and well log information. Volumetric reserves were estimated using the net pay encountered in the existing wellbores along with the structure of the formation from the seismic data. Reservoir thickness was estimated using log data. Reservoir rock and fluid property data were obtained from well logs, PVT data, gas analyses, and published information. Reservoir pressures were derived from pressure surveys, daily flowing tubing pressure measurements and published reports. Additionally, the Ruby 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 into consideration well depths, deliverability characteristics, product prices, assumed abandonment pressures, and operating cost information. The natural gas reserves are presented in millions of cubic feet at standard conditions of 14.65 psia and 60 degrees Fahrenheit.

Forecasts of net revenue were prepared by predicting annual production from the reserves and product prices. Annual production was forecasted taking into account historical production trends, planned equipment upgrades, applicable regulatory conditions, and existing or anticipated contract rates.

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

Prices and Costs

The hydrocarbon prices used in the report were based on the average prices from the first day of the twelve calendar months in 2012, per SEC regulations. Adjustments were made to this price based on differentials to the posted prices due to hydrocarbon quality, transportation fees, contract terms, etc. All hydrocarbon prices were held constant for the life of the properties with no future escalation.

Oil and condensate prices were not relevant to the report, as there is no oil production from the Rodessa Formation in the Madisonville Field.

Natural gas prices were based on the actual average Houston Ship Channel price received by GeoPetro on the first day of each month of 2012, which was $2.46 per MMBTU. This price has been adjusted for gas quality, contractual agreements, transportation and marketing fees, shrinkage and regional price variations. The gas being produced has a heating value of approximately 1000 BTU per cubic foot.

Operating costs used in the report were provided by GeoPetro and were estimated at approximately $7,660 per producing well per month going forward. All operating costs were held constant over the life of the properties with no future escalation. Plant operating expenses were applied in accordance with average values over the past 12 months, adjusted for known treatment modifications. Gas treatment fees are collected from the royalty owners in accordance with recently executed contractual agreements. Transportation fees are also paid to Gateway. The methodology is approximately summarized as follows:

· Gathering, Processing and Marketing Fees (paid to GeoPetro by the royalty owners):

All gas

$1.31 per Mcf inlet gas

· Transportation Fees

All gas

$0.10 per Mcf outlet gas

· Plant Costs

Approx. fixed monthly base costs	$207,250 (volumes up to 18 MMcfpd)
	$250,000 (volumes between 18-20 MMcfpd)
	$275,000 (volumes over 20 MMcfpd)

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

Development costs for the PUD well have been estimated at approximately $4.2 million. GeoPetro does have plans to fracture treat the Wilson #1 well in 2013 and lay gathering lines to the plant. These costs have been estimated at $1,445,000. Additionally, a cost of $650,000 was included to install a submersible pump into the Mitchell #1 well. The cost to modify the plant to increase the throughput was estimated at $4,000,000 and included in July 2013. Abandonment costs for the wells have been forecast at $15,000 each, including the waste disposal well on the property. An additional $500,000 was added for the cost of abandoning the gas plant. These costs were not independently verified by MHA, but were checked for reasonableness.

No deductions were made for indirect costs such as loan repayments, interest expenses, and exploration and development prepayments.

Following is the procedure used in calculating the economics for the production streams:

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.

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.

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.

Operating expenses (including ad valorem tax) were deducted at the rates stated above.

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.

Capital expenditures are applied and net cash flow determined.

A one line summary showing each of the cases is included under the tab “One Line Summary”, and a detailed output by year is included under the tab titled “Summary Economics and Plots”. Plots for each case are also presented under the same tab.

Statement of Risk

The accuracy of reserve and economic evaluations is always subject to uncertainty. The magnitude of this uncertainty is generally proportional to the quantity and quality of data available for analysis. As a well matures and new information becomes available, revisions may be required which may either increase or decrease the previous reserve assignments. Sometimes these revisions may result not only in a significant change to the reserves and value assigned to a property, but also may impact the total company reserve and economic status. The reserves and forecasts contained in this report were based upon a technical analysis of the available data using accepted engineering principles. However, they must be accepted with the understanding that further information and future reservoir performance subsequent to the date of the estimate may justify their revision. It is also possible that current or future regulation may have an impact on the reserves, or the company’s ability to produce these reserves.

It is MHA’s opinion that the estimated proven reserves and other reserve information as specified in this report are reasonable, and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles, as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information, promulgated by the Society of Petroleum Engineers. Notwithstanding the aforementioned opinion, MHA makes no warranties concerning the data and interpretations of such data. In no event shall MHA be liable for any special or consequential damages arising from GeoPetro’s use of MHA’s interpretation, reports, or services produced as a result of its work for GeoPetro.

Neither MHA, nor any of our employees have any interest in the subject properties and neither the employment to do this work, nor the compensation, is contingent on our estimates of reserves for the properties in this report.

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

It was a pleasure performing this work for GeoPetro. If you have any questions regarding this evaluation or if additional information is needed, please contact the undersigned at this office.

Sincerely,

/s/ John W. Arsenault
John W. Arsenault
Vice President

/s/ Dennis P. Holler
Dennis P. Holler
Senior Geological Associate