Overview
GeoGlobal Resources Inc. is engaged, through our subsidiaries and ventures in which we are a participant, in the exploration for and development of oil and natural gas reserves. We initiated these activities in 2003. We and our joint participants have been granted exploration rights pursuant to PSCs we have entered into with the Government of India. At present, these activities are being undertaken in four geological basins offshore and onshore in locations where reserves of oil or natural gas are believed by our management to exist. These areas are as follows:

· The Krishna Godavari Basin offshore and onshore in the State of Andhra Pradesh in eastern India;

· The Cambay Basin onshore in the State of Gujarat in western India;

· The Deccan Syneclise Basin onshore in the State of Maharashtra in west central India; and

· The Rajasthan Basin onshore in the State of Rajasthan in north western India.

To date, we have not earned significant revenue from these activities and are considered to be in the development stage under Financial Accounting Standards Board Statement of Accounting Standards No. 7. The recoverability of the costs we have incurred to date is uncertain and dependent upon us achieving commercial production and sale of hydrocarbons, our ability to obtain sufficient financing to fulfill our obligations under the PSCs in India and upon future profitable operations.

All of the exploration activities in which we are a participant should be considered highly speculative.

All dollar amounts stated in this Quarterly Report are stated in United States dollars.

All meterage of drilled wells referred to in this Quarterly Report are measured depths unless otherwise stated.

The following discussion and analysis of our financial condition and results of operation should be read in conjunction with, and is qualified in its entirety by, the more detailed information including our Condensed Consolidated Financial Statements and the related Notes appearing elsewhere in this Quarterly Report. This Quarterly Report contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from the results and business plans discussed in the forward-looking statements. Factors that may cause or contribute to such differences include those discussed in "Risk Factors" in our Annual Report on Form 10-K for the year ended December 31, 2008 as well as those discussed elsewhere in this Quarterly Report. For further information, refer to the Consolidated Financial Statements and related Notes and the Management's Discussion and Analysis thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Glossary of Certain Defined Terms:
GSPC - means Gujarat State Petroleum Corporation Limited, a company organized under the laws of India.
PSC - means Production Sharing Contract. NELP - means National Exploration Licensing Policy. MMscfd - million standard cubic feet per day.

Results of Operations for the Three and Six months ended June 30, 2009 and 2008 For the quarter ended June 30, 2009, we incurred a net loss of $1,146,000 compared with a net loss of $4,784,000 for the quarter ended June 30, 2008. The $3.7 million decrease was due to an impairment of our oil and gas properties under full cost accounting guidelines that was charged to the statements of operations in the second quarter of 2008.

For the six months ended June 30, 2009, we incurred a net loss of $2,313,000 compared with a net loss of $5,288,000 for the six months ended June 30, 2008.

                                              Three months        Three months          Six months          Six months
                                                     ended               ended               ended               ended
                                             June 30, 2009       June 30, 2008       June 30, 2009       June 30, 2008
Oil Production (barrels)                             3,098                  --               3,098                  --
Oil Sales (barrels)                                  3,024                  --               3,024                  --
Average Oil Price                          $         62.85                  --     $         62.85                  --
Oil Revenues                               $       190,000                  --     $       190,000                  --
Operating Costs per Barrel                 $         27.54                  --     $         27.54                  --
Depletion per Barrel                       $         14.14                  --     $         14.14                  --

Oil Sales
All of our revenues are derived from the production of crude oil in India. With the approval of the Tarapur 1 field development plan by the Management Committee, three wells began production in mid May 2009. There are eleven additional wells which are drilled, tested and awaiting tie-in to the oil tank storage facilities. We are currently receiving the spot price based on the Nigeria Bonny Light Crude bench mark. To date, none of our production has been hedged. In addition to the crude oil production, a minimal amount of natural gas was produced and flared off. Upon the tie-in and production from additional wells, it is the intention that the natural gas will be contained and sold.

Interest Income
Interest income during the three months ended June 30, 2009 was $84,000 compared with $243,000 for the same period in 2008. This decrease is primarily attributed to a lower interest rate earned on our short term investments as well as lower cash balances available for investment. The average cash balance during the second quarter was $30.1 million compared with $44.8 million in the second quarter of 2008.

Interest income during the six months ended June 30, 2009 was $198,000 compared with $692,000 for the same period in 2008. Interest rates earned on our short-term investments declined significantly during the six months ended June 30, 2008. In addition to lower interest rates, the average cash balance during the six months was $32.8 million compared with 46.5 million in the six months ended June, 30, 2008.

Operating
Operating costs for the three months ended June 30, 2009 were $83,000 or $27.54 per barrel, as a result of our first production in the Tarapur 1 field.
Operating costs include handling and processing charges, transportation costs and utilities. During the three months ended June 30, 2008, we did not incur any operating costs.

Operating costs for the six months ended June 30, 2009 were $83,000 or $27.54 per barrel, as a result of our first production in the Tarapur 1 field. During the six months ended June 30, 2008, we did not incur any operating costs.

General and Administrative
For the three months ended June 30, 2009, our general and administrative expenses increased to $887,000 from $665,000. Significant items included in general and administrative expenses include administrative salaries and related stock-based compensation costs, rental and office costs, insurance and public company costs including shareholder relations, listing and filing fees and transfer agent fees and services.

During the three months ended June 30, 2009, our Board of Directors approved a two year extension to compensation options and compensation warrants that were set to expire on June 22, 2009. A fair value of $264,000 relating to the extension of compensation options and compensation warrants was charged to the statement of operations. Stock-based compensation costs increased to $216,000 compared with $185,000 for the three months ended June 30, 2008. The increased stock-based compensation costs are primarily related to the stock options granted in December 2008.

For the six months ended June 30, 2009, our general and administrative expenses increased to $1,720,000 from $1,170,000. Along with the compensation options and compensation warrants extension costs of $264,000, stock-based compensation costs of $579,000 compared with $366,000 for the six months ended June 30, 2008 account for the majority of the change. Other significant costs, including salaries, travel and bank guarantee fees remained consistent with the six months ended June 30, 2008.

Consulting Fees
Consulting fees for the three months ended June 30, 2009, were $169,000, an increase of $7,000 from $162,000 when compared to the three months ended June 30, 2008. Significant items included in consulting fee expenses include a portion of costs paid to Roy Group (Barbados) Inc. for Chief Executive Officer services, costs paid to D.I. Investments Inc. for Chief Financial Officer services and the related health care costs and other consulting costs as incurred.

In the second quarter of 2009, we incurred costs of $66,000 to Roy Group (Barbados) Inc. compared with $44,000 in the second quarter of 2008. We expensed 75% (2008 - 50%) of the costs paid to Roy Group (Barbados) Inc. for CEO related duties and other general corporate affairs. The remaining 25% (2008 - 50%) was capitalized for technical geological services. We evaluate the payment of these costs annually to determine the appropriate allocation. Costs paid to D.I. Investments Inc. remained consistent at $53,000.

Consulting fees for the six months ended June 30, 2009, were $352,000, a decrease of $112,000 from $464,000 when compared to the six months ended June 30, 2008. In the six months ended 2008, we incurred a onetime cost of $75,000 paid to a broker in an effort to market and sell our Egypt blocks.

In the six months ended June 30, 2009, we incurred costs of $131,000 to Roy Group (Barbados) Inc. compared with $88,000 in the six months ended June 30, 2008. We expensed 75% (2008 - 50%) of the costs paid to Roy Group (Barbados) Inc. for CEO related duties and other general corporate affairs. The remaining 25% (2008 - 50%) was capitalized for technical geological services. We evaluate the payment of these costs annually to determine the appropriate allocation. Costs paid to D.I. Investments Inc. remained consistent at $106,000.

Professional Fees
Professional fees for the three months ended June 30, 2009 were $217,000, a decrease of $187,000 from $404,000 when compared to the three months ended June 30, 2008. Professional fees include general council, audit and review costs and tax advisors to assist with compliance. During the three months ended June 30, 2008, we completed a multiyear financial restatement and recorded costs of $238,000.

Professional fees for the six months ended June 30, 2009 were $448,000 compared with $519,000 for the six months ended June 30, 2008. During the six months ended June 30, 2009, we engaged various tax advisors to complete a review of our corporate structure with a goal to ensure tax strategy and efficiency across all jurisdictions. These tax related costs have partially offset the saving from the prior years' restatement of our previously filed annual reports. We continue to incur costs relating to a review of our corporate structure.

Impairment
There were no impairment charges during the three or six months ended June 30, 2009. During the three and six months ended June 30, 2008, an impairment charge of $3,765,000 was charged to the statements of operations relating to Egyptian, Oman and Yemen operations.

Other
We capitalized certain overhead costs directly related to our exploration activities in India. During the three months ended June 30, 2009, we capitalized overhead costs totaling $202,000 as compared to $365,000 during the three months ended June 30, 2008. Included in the amounts above are stock-based compensation costs of $97,000 for the three months ended June 30, 2009 compared with $134,000 for the three months ended June 30, 2008.

During the six months ended June 30, 2009, these capitalized overhead costs were $651,000 as compared to $659,000 during the six months ended June 30, 2008. Included in the amounts above are stock-based compensation costs of $379,000 for the six months ended June 30, 2009 compared with $304,000 for the six months ended June 30, 2008.

The treatment of capitalized overhead costs remained consistent with the comparable quarter and includes costs relating to personnel, consultants, their travel, necessary resources and stock-based compensation directly associated with the advancement of our oil and gas interests. The total stock-based compensation capitalized during the six months ended June 30, 2009 was $379,000 compared with $304,000 for the six months ended June 30, 2008.

New Reserve Report
As a result of the approval of the Tarapur 1 field development plan by the Management Committee and the completion of an independent reserve study by Chapman Petroleum Engineering Ltd. out of Calgary, Alberta, Canada, we claimed our proved reserves in the Tarapur 1 field as at June 30, 2009 of 245,000 net barrels of crude oil compared to nil at December 31, 2008.

Liquidity
Liquidity is a measure of a company's ability to meet potential cash requirements. We have historically met our capital requirements through the issuance of common stock as well as proceeds from the exercise of warrants and options to purchase common equity.

Our ability to continue as a going concern is dependent upon obtaining the necessary financing to complete further exploration and development activities and generate profitable operations from our oil and natural gas interests in the future. Our condensed consolidated financial statements as at and for the six months ended June 30, 2009 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business. We have incurred a history of operating losses and negative cash flows from operations. These matters may raise doubt about our ability to continue as a going concern.

At June 30, 2009, our cash and cash equivalents were $22.38 million (December 31, 2008 - $25.43 million). The majority of this balance is being held in US funds. Approximately $22.15 million is held in term deposits earning interest that will contribute towards covering a portion of our administrative costs and overhead throughout the next fiscal year. We have working capital of approximately $15.61 million which is available for our future operations. In addition, we have $6.92 million in restricted deposits pledged as security against the minimum work program on our exploration blocks, which will be released upon completion of the minimum work program.

We expect to incur expenditures to further our exploration programs. Our existing cash balance and any cash flow to be generated from operating activities may not be sufficient to satisfy our current obligations and meet our exploration commitments of $31.02 million over the next three years.

We are considering various alternatives with respect to raising additional capital to remedy any future shortfall in capital but to date have made no specific plans or arrangements. We may deem it necessary to raise capital through equity markets, debt markets or other financing arrangements, including participation arrangements that may be available for continued exploration expenditures. Because of the early stage of our operations, our absence of any material quantities of oil and natural gas reserves and also as a result of the current global financial crisis, there can be no assurance this capital will be available and if it is not, we may be forced to substantially curtail or cease exploration block acquisition and/or exploration expenditures. We believe that our available cash resources will be sufficient to maintain our current level of activities through the next fiscal year.

Should the going concern assumption not be appropriate and we are not able to realize our assets and settle our liabilities, commitments and contingencies, as more fully described in these condensed consolidated financial statements in the normal course of operations, our consolidated financial statements would require adjustments to the amounts and classifications of assets and liabilities, and these adjustments could be significant. These condensed consolidated financial statements do not reflect the adjustments or reclassifications of assets and liabilities that would be necessary if we are unable to continue as a going concern.

We believe at this time that the outcome of the GSPC Carried Interest dispute will not have a material effect on our liquidity.

Our cash and cash equivalents decreased by $3.06 million to $22.38 million from $25.43 million at December 31, 2008. The primarily result of the decrease in funds can be attributed to the following activities:

Our net cash used in operating activities during the six months ended June 30, 2009 was $1.49 million as compared to $1.75 million for the six months ended June 30, 2008. The use of cash is mainly related to general and administrative costs, consulting fees and professional fees combined with lower interest income earned on our short-term investments during the six months ended June 30, 2009.

Cash used by investing activities during the six months ended June 30, 2009 was $1.57 million as compared to $14.64 million during the six months ended June 30, 2008. This decrease is a result of cash payments of approximately $3.48 million primarily to our joint venture partners which was then off-set by a reduction of our restricted deposits totaling $3.87 million. The restricted deposits were returned to cash and cash equivalents which are now available for general corporate purposes.

No cash was provided by financing activities for the six months ended June 30, 2009 or June 30, 2008.

Capital Resources
We expect our exploration and development activities pursuant to the PSCs we are a party to, and the related drilling activities in the 10 exploration blocks that we hold an interest in, will continue through 2009 in accordance with the terms of those agreements. During the period July 1, 2009 to June 30, 2010, based on the estimated current budgets, we anticipate drilling approximately three exploratory wells in the KG Offshore Block, two exploratory and five appraisal wells in Sanand/Miroli, six exploration and two appraisal wells in Ankleshwar and one appraisal and four development wells on our Tarapur Block.

In addition, we may seek to participate in joint ventures bidding for the award of further PSCs for exploration blocks expected to be awarded by the Government of India in the future. As of August 5, 2009, we have no specific plans to bid or join with others in bidding for any specific PSCs in India and elsewhere. We expect that our interest in any such ventures would involve a minority participating interest in the venture. In addition, as opportunities arise, we may seek to acquire minority participating interests in exploration blocks where PSCs have been heretofore awarded. The acquisition of any such interests would be subject to the execution of a definitive agreement and obtaining the requisite government consents and other approvals.

In addition, we may require additional funds for the possible acquisition of further minority participating interests in PSCs in drilling blocks heretofore awarded and that we may hereafter propose to enter into in India and possibly elsewhere. We believe it can be expected that our interest in further or additional PSCs would be a participating interest. As the holder of a participating interest in any such activities, it can be expected that we will be required to contribute capital to any such ventures in proportion to our percentage interest.

As of August 5, 2009, the scope of any possible such activities has not been definitively established and, accordingly, we are unable to state the amount of any funds that may be required for these purposes. As a result, no specific plans or arrangements have been made to raise additional capital and we have not entered into any agreements in that regard. We expect that if we seek to raise additional capital it will be through the sale of equity securities, debt or other financing arrangements. We are unable to estimate the terms on which any such capital may be raised, the price per share or possible number of shares involved.

Off-balance Sheet Arrangements
None.

Contractual Obligations
Our minimum exploration commitments under our production sharing contracts and other future lease payments at June 30, 2009 were not substantially different than at December 31, 2008.

Critical Accounting Estimates
The preparation of financial statements under generally accepted accounting principles (GAAP) in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. On a regular basis we evaluate our assumptions, judgments and estimates. We also discuss our critical accounting estimates with the Audit Committee of the Board of Directors.

We believe that the assumptions, judgments and estimates involved in the accounting for oil and gas accounting and impairment, asset retirement obligation and share-based payment arrangements have the greatest potential impact on our condensed consolidated financial statements. These areas are key components of our results of operations and are based on complex rules which require us to make judgments and estimates, so we consider these to be our critical accounting estimates. Historically, our assumptions, judgments and estimates relative to our critical accounting estimates have not differed materially from actual results.

Our critical accounting estimates are disclosed in Item 7 of our 2008 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 27, 2009, and have not changed materially since the filing of that document.

Recent Exploration Activities
Below is a summary description of information relating to certain material developments to our exploration activities subsequent to our last update. For additional information and a more complete description of the PSCs to which we are a party, reference should be made to our Annual Report on Form 10-K and our Quarterly Reports on Form 10-Q as well as our Current Reports on Form 8-K.

Krishna Godavari Offshore Block
Exploration activities on the KG Offshore Block are as follows:

KG#21Well
The KG#21 exploratory well commenced drilling on September 22, 2008 using the Perro Negro 3 (PN-3) jack-up drilling rig. The well is located approximately 1.36 kilometers northwest of the KG#8 discovery in approximately 60 meters of water depth in the southwestern portion of the KG Offshore Block in the Deen Dayal North-west fault block. The well was slightly deviated and was drilled to a depth of 5,656 meters being a total vertical depth of 5,467 meters. The objective of the KG#21 location is two main targets with the primary target being the Lower Cretaceous sequence which was unable to be tested in the KG#31 exploratory well due to mechanical problems and the secondary target being the Upper Cretaceous fan deposits.

As at August 5, four drill stem tests (DST) have been completed on the well, and the fifth drill stem is currently being conducted.

DST-1, the first drill stem test was conducted by perforating 37.5 net meters over the gross interval 5,593.7 to 5,642 meters. This successful DST-1flowed during clean-up, on a 36/64 inch choke at a stabilised rate of 20 MMscfd gas and 2,600 barrels per day water with 4,670 psi (pounds per square inch) flowing well head pressure. During the main flow, on a 20/64 inch choke, the well flowed at a stabilised rate of 10 MMscfd gas and 1,200 barrels per day water with 7,220 pounds per square inch flowing well head pressure.

DST-2, the second drill stem test was conducted by perforating 25 net meters over the gross interval 5,517 to 5,567 meters. DST-2 flowed during clean-up, on a 24/64 inch choke at a stabilised rate of 1.5 MMscfd gas and 500 barrels per day water with 1,000 psi flowing well head pressure.

DST-3 was conducted by perforating 20 net meters over the gross interval 5,425 to 5,474 meters. DST-3 flowed during clean-up at a stabilised rate of 0.65 MMscfd of gas with 270 psi flowing well head pressure.

DST-4 was conducted by perforating 56 net meters over the gross interval 5,193 to 5,321 meters. DST-4 flowed during clean-up at a stabilised rate of 1.0 MMscfd of gas with 530 psi flowing well head pressure.

DST-5 is currently being conducted in the Upper Cretaceous by perforating 15 net meters over the gross interval 3,592.5 to 3,630 meters. DST-5 flowed during clean-up at a stabilised rate of 6.5 MMscfd gas and 600 barrels per day condensate with 2,530 psi flowing well head pressure.

GSPC as operator originally planned a total of seven drill stem tests on the KG#21 well in the Lower Cretaceous sequence over the 722 gross meter interval of 4,920.5 to 5,642.5 meters. GSPC has subsequently settled on four drill stem tests over the sequence in the Lower Cretaceous and one drill stem test over the interval 3,592.5 to 3,630 meters in the Upper Cretaceous.

KG#33Well
The KG#33 appraisal well commenced drilling on November 4, 2008 using the Atwood Beacon jack-up drilling rig. The well is located approximately 6.5 kilometers northeast of the KG#8 discovery in approximately 109 meters of water depth in the southeastern portion of the KG Offshore Block in the Deen Dayal East fault block. The well was directionally drilled to a total depth of 5,126 meters being a total vertical depth of 4,596 meters. The objective of the KG#33 location is to explore the hydrocarbon potential of the Lower Cretaceous sequence in the Deen Dayal East fault block and correlate to the KG#16 discovery well.

GSPC as operator planned three drill stem tests on the KG#33 well over the 313 gross meter interval of 4,555 to 4,868 meters.

DST-1, the first drill stem test was conducted by perforating 5.0 net meters over the gross interval 4,828 to 4,868 meters. This DST-1 flowed during clean-up, on a 20/64 inch choke, at a stabilised rate of 0.7 MMscfd gas with 800 pounds per square inch flowing well head pressure. DST-1 was subsequently stopped and the operator performed a hydraulic fracture over the same 5 meter interval. The result was DST-1A which had an increase in flow through a 16/64 inch choke to a stabilized rate of 6.3 MMscfd gas with 5,500 psi flowing will head pressure.

DST-2 was conducted by perforating a net interval of 34.5 meters over a gross interval from 4,692 to 4,752 meters. DST-2 recorded flow during clean-up, on a 16/64 inch choke at a stabilised rate of 0.9 MMscfd with a 700 psi flowing well head pressure.

DST-3 was conducted by perforating a 5 meter interval from 4,596 to 4,601 meters. A hydraulic fracture job was conducted over this interval resulting in a stabilised flow during clean-up through a 24/64 inch choke of 4.8 MMscfd with a 1,730 flowing well head pressure.

With the successful completion of the drill stem tests on the KG-33, the well has been suspended and we anticipate GSPC as operator will de-hire the Atwood Beacon jack-up drilling rig.

KG#19Well
The KG#19 exploratory well is located approximately 11 kilometers northeast of the KG#8 discovery in approximately 198 meters of water depth in the southeastern portion of the KG Offshore Block in the Deen Dayal East fault block. The KG#19 well commenced drilling on May 2, 2008 using the Essar Wildcat self propelled semi-submersible drilling rig. The well was suspended after setting the casing at 889 meters so that the Essar Wildcat rig could be repaired . . .