10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549

FORM 10-K

(Mark One)

þ      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010;

OR

¨   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ________________________________ to _________________________________.

Commission File No.:   1-32158

GEOGLOBAL RESOURCES INC.

(Exact name of registrant as specified in its charter)
Delaware	33-0464753
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
Suite 200, 625 – 4 Avenue SW,  Calgary, Alberta, Canada                                        T2P 0K2
(Address of principal executive offices)                                                                                (Zip Code)
Registrant’s telephone number, including area code:        +1 (403) 777-9250
Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Name of each exchange on which registered
Common Stock, par value $.001 per share	NYSE Amex
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act

¨ Yes                       þ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act

¨ Yes                       þ No

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 for such 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.þ Yes¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes     ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	þ	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

¨Yes                       þ No

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter was $42,057,494.

The number of shares outstanding of the registrant’s common stock as of March 30, 2011 was 82,746,933.

DOCUMENTS INCORPORATED BY REFERENCE

None

Table of Contents

		Page
	Part I
Item 1.	Business	3
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Submission of Matters to a Vote of Security Holders	25
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8.	Financial Statements and Supplementary Data	38
Item 9.	Changes In and Disagreements With Accountants On Accounting and Financial Disclosure	38
Item 9A.	Controls and Procedures	38
Item 9B.	Other Information	39
	Part III
Item 10.	Directors, Executive Officers and Corporate Governance	39
Item 11.	Executive Compensation	44
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13.	Certain Relationships and Related Transactions, and Director Independence	51
Item 14.	Principal Accountant Fees and Services	52
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	52

Available Information

The Company maintains a website at www.geoglobal.com, on which we make available, free of charge, all of the Company’s filings with the Security and Exchange Commission (“SEC” or “Commission”); including Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934.  These filings are available as soon as reasonably practicable after we electronically file such material with, or furnish it to the SEC.

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PART I

Item 1.                 Business

Glossary of Certain Defined Terms:

All dollar amounts are stated in United States dollars

All meterage of drilled wells are measured depths unless otherwise stated

MBbls          – thousand barrels

MMcf          – million cubic feet

GSPC           – means Gujarat State Petroleum Corporation Limited of India

OIL               – means Oil India Limited of India

ONGC          – means Oil & Natural Gas Corporation Limited of India

PSC              – means Production Sharing Contract

NELP           – means New Exploration Licensing Policy

Our Oil and Gas Activities

The Company is engaged in the pursuit of petroleum and natural gas through exploration and development in India, Israel and Colombia.  Since inception, our efforts have primarily been devoted to the pursuit of PSCs with GSPC, OIL and the Government of India.  At December 31, 2010, we have not yet achieved our planned principal operations and are considered to be a development stage enterprise.  We initiated these activities in 2003.  The recoverability of the costs we have incurred to date is uncertain and dependent upon achieving commercial production and sale of hydrocarbons, our ability to obtain sufficient financing to fulfill our obligations under the production sharing or other contracts we are a party to with respect to oil and natural gas exploration and development activities in India, Israel and Colombia and upon future profitable operations.  At present, our activities are being undertaken in four geological basins located offshore and onshore in India, one geological basin located offshore in Israel and one geological basin located onshore in Colombia where reserves of oil or natural gas are believed by our management to exist.

The exploration rights pursuant to PSCs we have entered into with the Government of India are located in the following areas:

·   The Krishna Godavari Basin offshore and onshore in the State of Andhra Pradesh in south 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 Bikaner-Nagaur Basin onshore in the State of Rajasthan in north western India.

As of March 30, 2011 we have entered into PSCs with respect to ten exploration blocks as follows:

·   KG-OSN-2001/3 (KG Offshore Block) - This was our first agreement entered into in February 2003 under NELP-III, which grants exploration rights in an area offshore in south eastern India in the Krishna Godavari Basin in the State of Andhra Pradesh.  GSPC is the operator of this block and holds an 80% participating interest.  We have a 10% participating interest (net 5% carried interest) under this agreement and Jubilant Offshore Drilling Pvt. Ltd. holds a 10% participating interest.

·   CB-ONN-2002/2 (Mehsana Block) - We entered into this agreement in February 2004 under NELP-IV, which grants exploration rights in an area onshore in the Cambay Basin in the State of Gujarat in western India.  Jubilant Offshore Drilling Pvt. Ltd. is the operator of this block and we have a 10% participating interest under this agreement.

·   CB-ONN-2002/3 (Sanand/Miroli Block) - We entered into this agreement in February 2004 under NELP-IV, which grants exploration rights in an area onshore in the Cambay Basin in the State of Gujarat in western India.  GSPC is the operator of this block and we have a 10% participating interest under this agreement.

·   CB-ON/2 (Tarapur Block) - Pursuant to an agreement entered into in April 2005, we purchased from GSPC a 20% participating interest in an agreement granting exploration rights granted under the pre-NELP rounds to an onshore exploration block in the Cambay Basin in the State of Gujarat in western India.  ONGC has the right to participate in the development of any commercial discovery on the Tarapur Block by acquiring a 30% participating interest as provided under the PSC.  GSPC is the operator of this block.

·   CB-ONN-2003/2 (Ankleshwar Block) - We entered into this agreement in September 2005 under NELP-V, which grants exploration rights in an area onshore in the Cambay Basin in the State of Gujarat in western India.  GSPC is the operator of this block and we have a 10% participating interest under this agreement.

·   DS-ONN-2003/1 (DS 03 Block) - We entered into this agreement in September 2005 under NELP-V, which grants exploration rights in an area onshore in the Deccan Syneclise Basin located in the northern portion of the State of Maharashtra in west-central India.  We are the operator of this block and have a 100% participating interest under this agreement.

·   KG-ONN-2004/1 (KG Onshore Block) - We entered into this agreement in March 2007 under NELP-VI, which grants exploration rights in an area onshore in the Krishna Godavari Basin in the State of Andhra Pradesh adjacent to our KG Offshore Block in south eastern India.  OIL is the operator of this block and we currently have a 10% participating interest under this agreement with an option to increase our participating interest to 25%.

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·   RJ-ONN-2004/2 (RJ Block 20) - We entered into this agreement in March 2007 under NELP-VI, which grants exploration rights in an area onshore in  north-west India in the Bikaner-Nagaur Basin in the State of Rajasthan.  OIL is the operator of this block and we have a 25% participating interest under this agreement.

·   RJ-ONN-2004/3 (RJ Block 21) - We entered into this agreement in March 2007 under NELP-VI, which grants exploration rights in an area onshore in  north-west India in the Bikaner-Nagaur Basin in the State of Rajasthan.  OIL is the operator of this block and we have a 25% participating interest under this agreement.

·   DS-ONN-2004/1 (DS 04 Block) - We entered into this agreement in March 2007 under NELP-VI, which grants exploration rights in an area onshore in the Deccan Syneclise Basin located in the northern portion of the State of Maharashtra in west-central India.  We are the operator of this block and have a 100% participating interest under this agreement.

The exploration rights pursuant to licenses we have been granted in Israel are located in the following areas:

·   347/Sara License – We entered into a Joint Operating Agreement on October 6, 2010 which grants exploration rights in an area of the Levantine Basin located approximately 35 miles off the coast of Israel in approximately 1,350 meters of water depth.  We are the operator of this license and currently have a 5% participating interest under this agreement.

·   348/Myra License – We entered into a Joint Operating Agreement on October 6, 2010 which grants exploration rights in an area of the Levantine Basin located approximately 52 miles off the coast of Israel in approximately 1,450 meters of water depth.  We are the operator of this license and currently have a 5% participating interest under this agreement.

·   388/Samuel License – We were awarded an interest in June 2010 from the Israel Petroleum Commissioner which grants exploration rights in an area of the Levantine Basin located in shallow water of 140 meters or less off the coast of Israel.  Adira Geo Global is the operator of the license and we hold an effective 45% interest in this license.

The exploration rights pursuant to licenses we have been granted in Colombia are located in the following areas:

·   Putumayo 6 License - We have entered into a Memorandum of Understanding (MOU) which grants us a 10% carried interest in exploration rights in the Putumayo Basin onshore in southwest Colombia.

·   Putumayo 7 License - We have entered into a Memorandum of Understanding (MOU) which grants us a 10% carried interest in exploration rights in the Putumayo Basin onshore in southwest Colombia.

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

Unless the context should otherwise require, references to “we,” “us” and “our” in this annual report refer to GeoGlobal Resources Inc. and our wholly-owned consolidated subsidiaries.  GeoGlobal Resources (Barbados) Inc. is our wholly-owned subsidiary incorporated under the Companies Act of Barbados that is the contracting party under our four PSCs covering four blocks in the Cambay Basin, our two PSCs covering two blocks in the Deccan Syneclise Basin, our two PSCs covering two blocks in the Bikaner-Nagaur Basin and our PSC covering the KG Onshore Block in the Krishna Godavari Basin.  GeoGlobal Resources (India) Inc. is our wholly-owned subsidiary continued under the Companies Act of Barbados that is the contracting party under our PSC covering our one KG Offshore Block in the Krishna Godavari Basin and the Sara, Myra and Samuel licenses in the Levantine Basin in Israel.

Our Production Sharing Contracts in India

Our Krishna Godavari Basin Agreements

KG Offshore Block PSC

Completion of Minimum Work Program

We, together with our joint venture partners GSPC and Jubilant Offshore Drilling Pvt. Ltd., are parties to a PSC dated February 4, 2003 which grants to the three parties the right to conduct exploratory drilling activities in the offshore waters of the Krishna Godavari Basin.  The PSC covers an area of approximately 1,850 square kilometers (457,145 acres) and was awarded under the third NELP round.  We have a net 5% carried interest in this exploration block.  Under the original terms, this PSC was for a term of up to 6.5 years commencing March 12, 2003 with three exploration phases and a prescribed minimum work program.  In June 2007, the Government of India issued two new policy guidelines which, among other things, permitted the substitution of additional meterage drilled in deeper wells against the total meterage of the wells committed as part of the minimum work program.  GSPC, on behalf of the contracting parties, exercised these rights.  By September 30, 2008, the consortium completed the minimum work program for all Phases on this block under the terms of the PSC as entered into.

Declaration of Commerciality

The PSC sets forth procedures whereby the operator can obtain the review of the Management Committee under the PSC as to whether a discovery on the exploration block should be declared a Commercial Discovery under the PSC.  GSPC, as operator on behalf of the consortium submitted to the Management Committee approval, the proposal for a Declaration of Commerciality on the KG#8 and KG#15 discoveries (referred to as the Deen Dayal West Structure) under the terms of the PSC.

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Field Development Plan Approval

With the completion of a review by the Management Committee of a proposal for Declaration of Commerciality of the Deen Dayal West Structure, on June 18, 2009, GSPC submitted the Deen Dayal West field development plan in accordance with the provisions of the PSC to the Management Committee for approval.  On November 11, 2009, the Field Development Plan was approved as follows:

·   Includes fifteen wells; four existing wells (KG#8, KG#15, KG#17 and KG#28) and eleven new development wells including three slant wells and eight multilateral wells to be drilled.

·   Production facilities to include:

o   Two offshore platforms (one well head and one central processing);

o   20 kilometer long pipeline of 24 inch diameter up to landfall point; and

o   One onshore gas terminal to include a gas sweetening unit, gas dehydration unit, dew point depression unit, condensate stabilization unit, sulphur recovery unit and a captive power unit.

·   Delivery point for gas will be the outlet flange of a delivery facility located at the onshore terminal at Mallavaram Village, near Yanam, Kakinada in Andhra Pradesh.

·   First gas production to commence December 2011 (subsequent to approval, amended to April 2013 or later).

·   GSPC as operator will apply for a 17 square kilometer mineral lease to cover this area.

GSPC estimated in the Field Development Plan that on a preliminary basis the gross costs for the production facilities will be approximately US$941 million and US$860 million for future development drilling costs.

Carried Interest Agreement

On August 27, 2002 we entered into a Carried Interest Agreement with GSPC granting us a 10% carried interest in the KG Offshore Block.  The Carried Interest Agreement provides that GSPC is responsible for our entire share of any and all costs incurred during the Exploration Phase prior to the date of initial commercial production.

Under the terms of the Carried Interest Agreement, all of our proportionate share of capital costs for exploration and development activities, including the share of Roy Group (Mauritius) Inc., a related party (see “Item 1 – Business – Our Production Sharing Contracts in India – Our Krishna Godavari Basin Agreements – KG Offshore Block PSC - Participating Interest Agreement”), will be recovered by GSPC without interest over the projected production life or ten years, whichever is less, from oil and natural gas produced on the exploration block.  We are not entitled to any share of production until GSPC has recovered our share of the costs and expenses that were paid by GSPC on behalf of us and Roy Group (Mauritius) Inc.

Our net 5% carried interest in the KG Offshore Block reflects our agreement to prospectively assign half of the original 10% interest under the PSC to Roy Group (Mauritius) Inc. pursuant to a Participating Interest Agreement we entered into on March 27, 2003, which assignment is subject to Government of India consent which has not yet been approved.  Absent such consent, the assignment will not occur and we are to provide Roy Group (Mauritius) Inc. with an economic benefit equivalent to the interest to be assigned.  At March 30, 2011, we have not obtained the consent of the Government of India to this assignment.

Carried Interest Agreement Dispute

GSPC has advised us that it is seeking from us payment of our pro rata portion of the amount by which the sums expended by GSPC under all phases for the minimum work program as set forth in the PSC for the KG Offshore Block in carrying out exploration activities on the block exceeds the amount that GSPC deems to be our pro rata portion of a financial commitment under all phases included in the parties’ joint bid for the award of the KG Offshore Block by the Government of India.

GSPC contends that this excess amount is not within the terms of the Carried Interest Agreement and that we are required to pay 10% of the exploration expenses over and above gross costs of $109.7 million (10% being $10.97 million) (including the net 5% interest of Roy Group (Mauritius) Inc.) plus interest.

GSPC advised us on November 5, 2008 that the minimum work program for the KG Offshore Block had been completed in September 2008.  Further, GSPC elected to undertake an additional work program over and above the minimum work program as either Joint Operations or as Exclusive Operations under the terms of the PSC and advised us that we must elect whether to participate in these additional exploration activities as a Joint Operation or alternatively, GSPC would conduct these drilling activities as Exclusive Operations, as defined in the PSC.

On November 13, 2008 we advised GSPC that we exercised our right to participate in the drilling operations proposed in the November 5, 2008 GSPC letter as a Joint Operation under the terms of the PSC and Joint Operating Agreement and pursuant to the terms of our Carried Interest Agreement with GSPC.  As such, we claim that we are carried for 100% of our entire share of any and all costs during the additional exploration phase prior to the start of initial commercial production and that the Carried Interest Agreement extends through the exploration period of the PSC.

In August 2010 GSPC advised us that it is of the view that the technical and other advice provided by us in the preparation of the parties’ original bid document submitted to the Government of India in 2002 under NELP-III has proven to be incorrect causing GSPC’s costs in the project to exceed its estimate.  GSPC asserts that by reason of the foregoing the Carried Interest Agreement between the parties is void and consequently the PSC to which the Government of India is party and the Joint Operating Agreement are also void.

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We have advised GSPC that under the terms of the Carried Interest Agreement (the terms of which are also incorporated into the PSC and the Joint Operating Agreement), it has no right to such payment under the Carried Interest Agreement.  We have advised GSPC that we have fulfilled our obligations under the Carried Interest Agreement to provide extensive technical assistance without any further remuneration other than the carried interest, all in accordance with the terms of the Carried Interest Agreement.  In furtherance of our position, we have obtained the opinion of prominent Indian legal counsel who has advised us that, among other things, under the terms of the agreements between the parties, and in particular the Carried Interest Agreement, we are not liable to pay any amount to GSPC for either costs and expenses incurred or otherwise before reaching the stage of commercial production.

We dispute these positions of GSPC and the conclusions reached by GSPC and continue to state that we hold a gross 10% interest in the KG Offshore Block (including the 5% interest of Roy Group (Mauritius) Inc.).  In a KG Offshore Block Management Committee meeting held in October, 2010, the Management Committee (of which the Government of India is a member) advised GSPC to resolve these issues with us at the earliest and requested GSPC to maintain status quo until the issues are resolved.

Based upon the audited accounts of the joint venture for the KG Offshore Block the total costs incurred to March 31, 2010 amounted to $1.447 billion (10% being $144.7 million of which 50% is for the account of Roy Group (Mauritius) Inc.).  Further, based upon the budget for the fiscal year April 1, 2010 to March 31, 2011, total costs projected were $601 million with approximately $446 million spent by December 31, 2010 (10% being $60.1 million and $44.6 million respectively).  Therefore, we estimate that the amount of GSPC’s claim as of December 31, 2010 to be approximately $189 million plus interest of which 50% is for the account of Roy Group (Mauritius) Inc.  We dispute this assertion of GSPC.

We intend to vigorously protect our contractual rights in accordance with the dispute resolution process under the Carried Interest Agreement, the PSC and the Joint Operating Agreement as may be appropriate.  In September 2007, we commenced discussions with GSPC in an effort to reach an amicable resolution.  A number of draft settlement proposals have been put forward by us to GSPC seeking to settle this dispute amicably.  Subsequent to the October 2010 Management Committee meeting we have again met with senior management of GSPC to continue our effort to reach an amicable resolution.  However, no settlement agreement has been reached as of March 30, 2011 and there can be no assurance that this matter will be settled amicably.

Participating Interest Agreement

On March 27, 2003 prior to our acquisition of all of its outstanding capital stock, GeoGlobal Resources (India) Inc. entered into a Participating Interest Agreement with Roy Group (Mauritius) Inc.  Pursuant to this agreement, GeoGlobal Resources (India) Inc. assigned and currently holds in trust for Roy Group (Mauritius) Inc. 50% of the benefits and obligations of the PSC covering the KG Offshore Block and the Carried Interest Agreement.  GeoGlobal Resources (India) Inc. effectively retains a net 5% participating interest in the KG Offshore Block and a net 5% carried interest in the Carried Interest Agreement.  Under the terms of the Participating Interest Agreement, until the Government of India consents to the assignment to Roy Group (Mauritius) Inc., we retain the exclusive right to deal with the other parties to the KG Offshore Block and the Carried Interest Agreement and are entitled to make all decisions regarding the interest assigned to Roy Group (Mauritius) Inc.  Roy Group (Mauritius) Inc. has agreed to be bound by and be responsible for the actions taken by, obligations undertaken and costs incurred by us in regard to Roy Group (Mauritius) Inc.’s interest and to be liable to us for its share of all costs, interests, liabilities and obligations arising out of or relating to the Roy Group (Mauritius) Inc. interest.  Roy Group (Mauritius) Inc. has agreed to indemnify us against any and all costs, expenses, losses, damages or liabilities incurred by reason of Roy Group (Mauritius) Inc.’s failure to pay the same.  Subject to obtaining Government of India consent to the assignment, Roy Group (Mauritius) Inc. is entitled to all income, receipts, credits, reimbursements, monies receivable, rebates and other benefits in respect of its 5% interest which relate to the KG Offshore Block. We have a right of set-off against sums owing to us by Roy Group (Mauritius) Inc.  In the event that the Government of India consent is delayed or denied, resulting in either Roy Group (Mauritius) Inc. or us being denied an economic benefit either would have realized under the Participating Interest Agreement, the parties agreed to amend the agreement or take other reasonable steps to assure that an equitable result is achieved consistent with the parties’ intentions contained in the Participating Interest Agreement.  As a consequence of this transaction we report our holdings under the KG Offshore Block and the Carried Interest Agreement as a net 5% participating interest.  Inasmuch as the assignment of the 5% interest to Roy Group (Mauritius) Inc. occurred prior to our acquisition of GeoGlobal Resources (India) Inc. and we were not a party to that assignment, we received no consideration for the assignment.

KG Onshore Block PSC

We, together with our joint venture partner OIL, are parties to a PSC dated March 2, 2007 awarded under NELP-VI.  The PSC covers an area of approximately 549 square kilometers (135,660 acres) onshore in the Krishna Godavari Basin and is located directly adjacent to and south-west of our KG Offshore Block.  The two exploration phases for this PSC are for a term of up to 7.0 years commencing February 18, 2008.  The Phase I covers a period of 4.0 years of which the minimum work program consists of reprocessing 564 line kilometers of 2D seismic data, conducting a gravity and magnetic and geochemical survey, as well as a seismic acquisition program consisting of 548 square kilometers of 3D seismic data.  This Phase I minimum work program further consists of drilling twelve exploration wells to various depths between 2,000 and 5,000 meters.  If the parties elect to enter Phase II which covers a period of 3.0 years, a minimum work program applies to drill one exploration well to a depth of 4,600 meters.

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We currently hold a 10% participating interest in this exploration block, while OIL, as operator, holds the remaining 90% participating interest   On June 29, 2010 we agreed with OIL to increase our participating interest on the KG Onshore Block to 20%, such increase being subject to Government of India approval.  Upon such approval we will hold a 20% participating interest in the KG Onshore Block and will become responsible to pay our 20% share of the costs of exploration activities on the block.

Our Cambay Basin Agreements

Tarapur Block Agreement

Pursuant to an agreement entered into with GSPC in April, 2005 we purchased a 20% participating interest in the onshore Tarapur Block in the Cambay Basin.  GSPC as operator owns the remaining 80% participating interest. 

ONGC has the right under the PSC to participate in the development of any commercial discovery on the Tarapur Block by acquiring a 30% participating interest exercisable under the PSC which expired on November 22, 2007.  ONGC exercised this right with respect to a western portion of the Block referred to as the Tarapur 1 Discovery Area.  The effect of the ONGC exercise is a reduction in the participating interests of GSPC and us in the Tarapur 1 Discovery Area to 56% and 14% respectively.

As to the remaining areas of the Tarapur Block, based on current negotiations between GSPC and ONGC, we expect that the latter will be granted a right to a 10% participation in all future wells drilled on the remaining areas of the Tarapur Block during extensions of the exploration period of the PSC.  This would result in the reduction of the participating interests of GSPC and us on these remaining areas to 62% and 18% respectively.

After our relinquishment of 25% (approximately 407 square kilometers) of the exploration block to the Government of India, the block now includes approximately 1,213 square kilometers.  At the expiration of the exploration period of the PSC on November 22, 2007, GSPC submitted an application to the Government of India for an extension of the PSC for an additional twelve months to November 22, 2008 which was granted.  During this extension period, the consortium drilled an additional eleven exploratory wells. 

GSPC as operator submitted a further application on February 19, 2009 for an additional extension of the exploration phase for eighteen months to May 22, 2010.  On November 11, 2010, GSPC as operator submitted a further application for this additional eighteen month extension of the exploratory phase.  This additional extension was submitted to enable a further exploration program of drilling five exploratory wells and the acquisition of 330 square kilometers of 3D seismic in a section of the block to the east of the Tarapur 1 Discovery Area which we refer to as Tarapur East.  Approval from the Government of India for this additional extension is pending. 

Sanand/Miroli Block PSC

On February 6, 2004, we, together with our joint venture partners GSPC, Jubilant Offshore Drilling Pvt. Ltd. and Prize Petroleum Company Limited signed a PSC with respect to the onshore Sanand/Miroli Block.  We hold a 10% participating interest; GSPC as operator holds a 55% participating interest; Jubilant Offshore Drilling Pvt. Ltd. holds a 20% participating interest; and the remaining 15% is held by Prize Petroleum Company Limited.  The PSC provides that the exploration activities are to be conducted in three phases commencing July 29, 2004 with the first phase covering a period of 2.5 years, the second phase covering 2.0 years and the last phase covering 1.5 years, for a maximum duration of 6.0 years.  All three phases were completed as of July 27, 2010 and as such, pursuant to the terms of the PSC, the contractor shall retain only Development and Discovery areas and must relinquish the remainder to the Government of India.  It has been agreed that we, together with our joint venture partners, shall retain the discovery areas of approximately 39.8 square kilometers (9,835 acres) in the form of three geometrical shapes; two in Sanand and one in Miroli, subject to Government of India approval.

During the three exploration phases on the Sanand/Miroli Block, the parties acquired 200 square kilometers of 3D seismic data, reprocessed 1,000 line kilometers of 2D seismic data, conducted a geochemical survey and drilled seventeen exploratory wells between 1,500 to 3,000 meters, thereby completing all phases of the minimum work program.

Ankleshwar Block PSC

On September 23, 2005, we, together with our joint venture participants GSPC, Jubilant Offshore Drilling Pvt. Ltd. and GAIL (India) Ltd. signed a PSC with respect to the onshore Ankleshwar Block.  We hold a 10% participating interest; GSPC as operator holds a 50% participating interest; Jubilant Offshore Drilling Pvt. Ltd. holds a 20% participating interest; and the remaining 20% is held by GAIL (India) Ltd.  The PSC provides that the exploration activities are to be conducted in three phases commencing April 1, 2006 with the first phase covering 3.0 years, the second phase covering 3.0 years and the last phase covering 1.0 year, for a maximum duration of 7.0 years.

The minimum work program under Phase I is to acquire, process and interpret 448 square kilometers of 3D seismic data and reprocess 650 line kilometers of 2D seismic data.  Fourteen exploratory wells are to be drilled between 1,500 to 2,500 meters.  All commitments under the Phase I minimum work program have been met and the parties have elected not to proceed to the second phase but rather to appraise and develop the existing discoveries.

After relinquishment of the exploration block to the Government of India as required by the terms of the PSC, the block now includes approximately 172 square kilometers (42,502 acres) for future appraisal and development activities, subject to Government of India approval.

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Mehsana Block PSC

On February 6, 2004, we, together with our joint venture partners GSPC and Jubilant Offshore Drilling Pvt. Ltd. signed a PSC with respect to the onshore Mehsana Block.  We hold a 10% participating interest; GSPC holds a 60% participating interest; and Jubilant Offshore Drilling Pvt. Ltd. as operator holds the remaining 30%.  The PSC provides that exploration activities are to be conducted in three phases commencing May 21, 2004 with the first phase covering 2.5 years, the second phase covering 2.0 years and the last phase covering 1.5 years, for a maximum duration of 6.0 years.

During the first exploration phase on this exploration block, the parties were to acquire 75 square kilometers of 3D seismic data, reprocess 650 line kilometers of 2D seismic data, conduct a geochemical survey and drill seven exploratory wells between 1,000 to 2,200 meters, all of which has been completed.  The consortium also relinquished 25% of the Mehsana Block as required pursuant to the terms of the PSC guidelines leaving an area of approximately 93 square kilometers (22,981 acres) of the original 125 square kilometers.

The consortium has elected not to proceed into Phase II on this block but rather requested on August 28, 2008 a six month extension to Phase I in order to complete a testing and stimulation program on existing wells and to complete the appraisal of the block.  On February 8, 2010 the Directorate General of Hydrocarbons approved the extension of Phase I until July 13, 2010.

Our Deccan Syneclise Basin Agreements

DS 03 Block PSC

On September 23, 2005 we signed a PSC with respect to the onshore DS 03 Block.  We hold a 100% participating interest in this block and are the operator.  The PSC provides that exploration activities are to be conducted in three phases commencing September 4, 2006 with the first phase covering 3.0 years, the second phase covering 2.0 years and the third phase covering 2.0 years, for a maximum duration of 7.0 years.

During 2010, we elected to proceed to Phase II, whereupon we relinquished 25% (approximately 789 square kilometers) of the exploration block to the Government of India as required by the terms of the PSC, leaving approximately 2,366 square kilometers (584,651 acres).

The minimum work program under the first phase called for a gravity magnetic and geochemical survey, which has since been completed.  In addition we are to acquire an aero magnetic survey of 12,000 line kilometers which has been combined with the Phase II commitments.  Under the minimum work program for Phase II we are to acquire 500 line kilometers of 2D seismic data and drill one exploration well.  Further, if we elect to proceed to the third phase, we are to acquire 250 square kilometers of 3D seismic data and drill two exploratory wells.

DS 04 Block PSC

On March 2, 2007 we signed a PSC with respect to the onshore DS 04 Block.  The PSC covers an area of approximately 2,649 square kilometers (654,582 acres).  We hold a 100% participating interest in this block and are the operator.  The PSC provides that exploration activities are to be conducted in two phases commencing June 7, 2007 with the first phase covering 5.0 years and the second phase covering 3.0 years, for a maximum duration of 8.0 years.

The Phase I mandatory and minimum work program consists of conducting a gravity and magnetic and geochemical survey, as well as a seismic acquisition program consisting of 535 line kilometers of 2D seismic data.  We are further committed to drill ten core holes to a depth of approximately 500 meters.  If we elect to proceed to Phase II, the minimum work program consists of a seismic acquisition program consisting of 500 line kilometers of 2D seismic data and 200 square kilometers of 3D seismic data and the drilling of one exploratory well to a depth of 2,000 meters.

Our Bikaner-Nagaur Basin Agreements

RJ Block 20 PSC

On March 2, 2007 we, together with our joint venture partner OIL signed a PSC with respect to the onshore RJ Block 20.  The PSC covers an area of approximately 2,196 square kilometers (542,643 acres).  We hold a 25% participating interest in this block with OIL as operator holding the remaining 75%.  The PSC provides that exploration activities are to be conducted in two phases commencing January 21, 2008 with the first phase covering 4.0 years and the second phase covering 3.0 years, for a maximum duration of 7.0 years.

The Phase I mandatory and minimum work program is to reprocess 463 line kilometers of 2D seismic data; conduct a gravity, magnetic and geochemical survey; acquire, process and interpret 820 line kilometers of 2D seismic data; acquire 700 square kilometers of 3D seismic data; and drill a total of twelve exploratory wells between 2,000 and 2,500 meters.  The Phase II minimum work program, if we elect to continue into Phase II, is to drill one well to 2,500 meters.

RJ Block 21 PSC

On March 2, 2007 we, together with our joint venture partners OIL and Hindustan Petroleum Corporation Limited signed a PSC with respect to the onshore RJ Block 21.  The PSC covers an area of approximately 1,330 square kilometers (328,650 acres).  We hold a 25% participating interest in this block; OIL as operator holds a 60% participating interest and; Hindustan Petroleum Corporation Limited holds the remaining 15%.  The PSC provides that exploration activities are to be conducted in two phases commencing January 21, 2008 with the first phase covering 4.0 years and the second phase covering 3.0 years, for a maximum duration of 7.0 years.

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The Phase I mandatory and minimum work program is to reprocess 463 line kilometers of 2D seismic data; conduct a gravity, magnetic and geochemical survey; acquire, process and interpret 660 line kilometers of 2D seismic data and 611 square kilometers of 3D seismic data; and drill a total of eight exploratory wells between 2,000 and 2,500 meters.  The Phase II minimum work program, if we elect to continue into Phase II, is to drill one well to 2,000 meters.

Certain Terms of Our PSCs

General

Except for the size and location of the exploration blocks and the work programs to be conducted, the PSCs contain substantially similar terms.  Under the PSCs, the Government of India has granted to the parties the right to engage in oil and natural gas exploration activities on the exploration blocks for specified terms of years with each contract setting forth the exploration activities to be conducted over periods of years in two or three phases.

The contracts contain restrictions on the assignment of a participating interest without the consent of the Government of India, including on a change in control of a party, subject to certain exceptions which include, among others, a party encumbering its interest subject to certain limitations.

Each of the joint ventures is managed by a Management Committee representing the parties to the agreement, including the Government of India.  The contracts contain various other provisions, including, among other things, obligations of the parties to maintain insurance, maintain the books and records, confidentiality, the protection of the environment, arbitration of disputes, matters relating to income taxes, royalty payments, and the valuation of hydrocarbons produced.  The Indian domestic market has the first call on natural gas produced.  These contracts are interpreted under the laws of India.

Relinquishment on our Blocks Prior to NELP-VI Blocks

Under each of these contracts, if the parties elect to continue into the second exploratory phase, the parties retain up to 75% of the original contract area, including any developed areas and areas of discoveries of hydrocarbons, and must relinquish the remainder.  Similarly, if the parties elect to continue into the third exploration phase, the contracts provide that the parties retain up to 50% of the original contract area, including any developed areas and areas of discovery of hydrocarbons, and must relinquish the remainder.  At the end of the final exploration phase, only developed areas and areas of discoveries are to be retained.

Relinquishment on our NELP-VI Blocks

Under each of these contracts, if the parties elect to continue into the second exploratory phase, the contracts provide that the parties have the option to relinquish a part of area in simple geometrical shape not less than 25% of the original contract area.  At the end of the second exploration phase, the parties retain the balance which includes any developed areas and areas of discoveries.

Procedure for Allocation of Costs After a Discovery

The PSCs contain procedures to be followed once a discovery of hydrocarbons is determined to have been made within the exploration block and for the further development of that discovery.  Following the completion of a development plan for a discovery, the parties are to apply to the relevant government entity for a lease with respect to the area to be developed with an initial term of 20 years.  The Government of India and the other parties to the PSC are allocated the percentages of any remaining production, after deduction of the costs of exploration, development, and production to be recovered.  The percentages allocated to the Government of India are between 20% to 40% of the production from the KG Offshore Block and Ankleshwar Block, 30% to 55% of the production from the Mehsana Block and Sanand/Miroli Block and 10% to 30% of the production from the DS 03 Block.  The newly awarded blocks under NELP-VI are allocated between 91% to 9% of the production from the KG Onshore Block, the RJ Block 20 and RJ Block 21 and between 85% to 15% for the DS 04 Block.  This percentage split is based upon pre-determined production levels with the balance of the production to be allocated to the other joint venture participants in proportion to their participating interests.

Bank Guarantees

The PSCs contain provisions whereby the joint venture participants must provide the Government of India a bank guarantee in the amount of 35% of the participant’s share of the minimum work program for a particular Phase to be undertaken during the year.  The work program is presented annually to the Management Committee for approval for the period April 1 through March 31.  The work programs for the year April 1, 2011 through March 31, 2012 and their related budgets have yet to be approved for our existing PSCs to which we are a party.  Accordingly, our estimates as to capital expenditures for these budgeted years as well as the year ending December 31, 2011 and beyond are subject to revision when the budgets are approved.

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Our Licenses in Israel

Our Levantine Basin Agreements

Sara & Myra Licenses

On June 18, 2010, the Israel Ministry of National Infrastructure approved the transfer and registration of deepwater offshore licenses known as the 348/Sara and the 347/Myra Licenses to a consortium in which we have a 5% participating interest and have been designated as Operator. The licenses each cover an area of approximately 400 square kilometers (98,842 acres).  The remaining participating interest is held by a consortium that consists of Emanuelle Energy Ltd. (30.013%), Emmanuelle Energy – Gas and Oil Explorations Limited Partnership (19.161%), Modiin Energy – Limited Partnership (21.612%), I.P.C. Oil and Gas (Israel) Limited Partnership (13.609%), Israel Land Development Company Ltd. (5%), and IDB Development Corporation Ltd. (5.605%).  On October 6, 2010 we entered into a Joint Operating Agreement with the other members of the consortium.

The license provides that exploration activities be conducted over a three year period commencing July 14, 2008 and expiring July 13, 2011.  During that period, certain milestones and commitments are to be met, subject to extension by the Ministry of National Infrastructure.  With respect to each of these licenses, the milestones are as follows:

Jun 1, 2010	Commence Prospect geological review
Jul 15, 2010	Complete the 3D seismic survey acquisition and processing
Aug 1, 2010	Complete first stage of 3D seismic survey interpretation results and submit a report
Sep 15, 2010	Complete Prospect geological review and submit a report
Oct 15, 2010	Complete Hydrocarbon system analysis and submit a report
Dec 31, 2010	Final drilling Prospect submission including drilling plans
Mar 31, 2011	Presentation of a contract with drilling contractor to perform drilling services on identified Prospect
Jul 13, 2011	Commencement of drilling

Samuel License

On June 16, 2010, the Israel Petroleum Commissioner’s office notified a consortium of which we are a member of the award of a petroleum license to one shallow water offshore license known as the 388/Samuel License.  The license covers an area of approximately 361 square kilometers (89,205 acres).  We hold a 45% effective participating interest in this license comprised as follows: a 30% participating interest held by GeoGlobal Resources (India) Inc. plus our 50% ownership of Adira Geo Global Ltd. which holds a 30% participating interest.  Adira Geo Global has been designated as Operator (we currently hold 40% of Adira Geo Global and are awaiting the transfer of an additional 10% shareholding).  The remaining balance is held as to Adira Technologies Ltd. (23.25%), Brownstone Venture Inc. (6.75%) and Pinetree Capital Ltd. (10%).

The license provides that exploration activities are to be conducted as follows:

Nov 1, 2010	Submit summary report of seismic and geological data
Nov 1, 2010	Sign 3D seismic acquisition contract
Feb 1, 2011	Commence 3D seismic acquisition survey
May 1, 2011	Complete acquisition and processing of 3D seismic survey and submit preliminary report
July 1, 2011	Complete 3D seismic interpretation and submit report
Sept 1, 2011	Preparation of geological prospect for drilling
Oct 1, 2011	Sign contract with drilling contractor
Feb 1, 2012	Commencement of drilling
Oct 1, 2012	Submit drilling summary report

Our Contracts in Colombia

Our Putumayo Basin Agreements

PUT 6 and PUT 7 Licenses

On September 14, 2010 we entered into a Memorandum of Understanding with Petro Caribbean Resources Ltd. relating to oil and natural gas exploration and development activities in Colombia, subject to execution by Petro Caribbean Resources Ltd. of definitive agreements with the Colombian National Agency of Hydrocarbons.  The exploration activities are to be conducted on two onshore exploration blocks located in the Putumayo basin in southwest Colombia known as the Putumayo 6 (PUT 6) and Putumayo 7 (PUT 7) licenses.  The PUT 6 license covers an area of approximately 574 square kilometers (141,838 acres) and the PUT 7 license covers an area of approximately 167 square kilometers (41,267 acres).  Subject to the execution of a Joint Operating Agreement, we will be carried for a 10% participating interest in both licenses through the minimum and additional work programs as bid in return for us providing to Petro Caribbean Resources Ltd. technical assistance through the exploration phase.

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Our Oil and Gas Exploration and Drilling Activities

As at December 31, 2010, we have participated since inception through joint ventures in the drilling of ninety-nine wells.  Further, we acquired three wells originally drilled by ONGC in the Tarapur Block.  Of the total ninety-nine wells drilled, sixteen have been drilled in the Krishna Godavari Basin within the KG Offshore Block, eighty-one have been drilled in the Cambay Basin and two have been drilled in the Bikaner-Nagaur Basin.  A total of forty-three wells have been abandoned or will be abandoned because of the absence of economic quantities of hydrocarbons or because the well characteristics would make the production of hydrocarbons problematic and non-commercial.

Field development plans have been filed by GSPC with the Government of India and Director General of Hydrocarbons for a portion of the KG Offshore Block and the Tarapur Block under the provisions of the PSC.  The Government of India has provided approval for these plans subject to certain terms and conditions.

While we have discoveries in the Ankleshwar Block, the Mehsana Block and the Sanand/Miroli Block along with additional discoveries in the Tarapur Block and the KG Offshore Block, field development plans have not yet been submitted on those blocks for those specific discoveries.

Our Krishna Godavari Basin Activities

KG Offshore Activities

Deen Dayal West Field Development Plan

A Field Development Plan has been approved as follows:

·   Includes fifteen wells; four existing wells (KG#8, KG#15, KG#17 and KG#28) and eleven new development wells including three slant wells and eight multilateral wells to be drilled.

·   Production facilities to be constructed include:

o   Two offshore platforms (one well head and one central processing facility);

o   20 kilometer long pipeline of 24 inch diameter pipe extending to a landfall point; and

o   One onshore gas terminal to include a gas sweetening unit, gas dehydration unit, dew point depression unit, condensate stabilization unit, sulphur recovery unit and a captive power unit.

·   Delivery point for gas will be the outlet flange of a delivery facility to be located at the onshore terminal near Yanam, Kakinada, Andhra Pradesh.

·   First gas production to commence December 2011 (subsequent to approval, amended to April 2013 or later).

·   GSPC as operator is expected to apply for a 17 square kilometer mining lease to cover this area.

GSPC estimated in the Field Development Plan that on a preliminary basis, gross costs for the production facilities will be approximately US$941 million and US$860 million for future development drilling costs. GSPC is currently in the process of commissioning an offshore platform and jack-up drilling rig to commence the drilling of the new development wells.

KG Onshore Activities

During the first half of 2010, OIL as operator of the KG Onshore Block commenced a 3D seismic acquisition program. The acquisition program is planned to acquire approximately 400 square kilometers of data out of an area of approximately 548 square kilometers as a result of seismic acquisition restrictions in the reserve forest. As at December 31, 2010 approximately 141.4 square kilometers of 3D seismic data had been acquired. It is anticipated that the seismic acquisition and part of the processing will be completed on or before September 30, 2011.

Three priority locations as proposed have been reviewed and agreed to by the Operating Committee.  All of these locations have multiple prospects in both the shallower (Eocene – Miocene) and deeper (Cretaceous – Jurassic) zones.

In February 2011, a contract was awarded to RPS Energy, Canada (RPS) to provide the well engineering and wellsite supervision work associated with the planned drilling campaign on the KG Onshore Block in an effort to commence drilling 12 exploration wells to various depths between 2,000-5,000 meters before the end of 2011.

Our Cambay Basin Exploration Activities

Tarapur Block

Tarapur 1 Discovery Area

Currently there is an approved field development plan which covers an area of approximately 2.14 square kilometers within the Tarapur 1 Discovery Area of approximately 9.7 square kilometers, and includes three existing discovery wells (Tarapur 1, Tarapur P and Tarapur 5) and three development wells (TD-1, TD-2 and TD-3).

All six wells are tied into the oil tank storage facilities by way of a gathering system and are on production.  Throughout 2009, associated natural gas was being produced and flared off. GSPC as operator built a small gas line in order to collect and sell this gas. Effective January 2010, this associated natural gas is being sold into the local market.

There are ten additional wells in the Tarapur 1 Discovery Area which are drilled, tested and awaiting tie-in to the oil tank storage facilities. Further, there is one gas well (Tarapur G), whose declaration of commerciality has been reviewed and declared as a commercial discovery.  Production from Tarapur G will commence upon approval of a field development plan. GSPC is currently in the process of preparing and filing the necessary declarations of commerciality and/or field development plans pursuant to the provisions of the PSC to bring these additional discoveries onto production.

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Sanand/Miroli Block

In an Operating Committee Meeting held in December 2010, it was agreed that the consortium would apply for a Petroleum Mining Lease to cover three geometrical shapes surrounding the discoveries SE-8 (11.2 square kilometers), SE-4 cluster (18.2 square kilometers) and M1M6 (10.4 square kilometers).  GSPC is currently in the process of preparing and filing the necessary declarations of commerciality and field development plans pursuant to the provisions of the PSC in order to put these wells on production.

Ankleshwar Block

During 2010, GSPC as operator drilled the remaining three exploratory wells (ANK-39S, ANK-40S and ANK-41S) to complete the Phase I Minimum Work commitment.  The consortium elected not to proceed to Phase II but rather develop the existing discoveries.

Pursuant to the Operating Committee Resolution of December 7, 2010, the consortium elected to retain a 172 square kilometer area around the two discoveries ANK-21 and ANK-40S.  Recently, a gas discovery (ANK-21S) has been notified within this 172 square kilometer area.  GSPC is currently in the process of preparing and filing the necessary declarations of commerciality and field development plans pursuant to the provisions of the PSC in order to put these wells on production.

Mehsana Block

On February 8, 2010 the Directorate General of Hydrocarbons approved the extension of the Phase I minimum work program to July 13, 2010.  This extension allowed the consortium time to complete a four well testing and stimulation program in order to complete the appraisal of the block, the results of which are not yet known.  After completion of the test results, all areas not defined as a Commercial Discovery will be relinquished under the terms of the PSC.  The consortium has elected not to proceed to Phase II of the work program.

Our Deccan Syneclise Basin Exploration Activities

DS 03 Block

On February 6, 2010 we applied for a six month extension of Phase I to September 3, 2010 in order to complete a 12,000 line kilometer aeromagnetic survey.  The extension has been granted and we have further elected to proceed into Phase II of the exploratory work program.  The Management Committee, pursuant to the PSC, approved a relinquishment of 789.25 square kilometers, or 25% of the original contract area of 3,155 square kilometers at the beginning of the second extension of Phase I.  Our commitment to the end of Phase II is now to complete this survey (currently awaiting approval from the Government of India), complete a 500 line kilometers 2D seismic survey and drill one exploratory well to a depth of approximately 1,500 meters.

DS 04 Block

It is our intention as operator of this block to drill two core holes to a depth of 500 meters and complete a 500 line kilometer 2D seismic survey by March 2012.

Our Bikaner-Nagaur Basin Exploration Activities

RJ20 and RJ21 Blocks

The consortium completed the acquisition, processing and interpretation of a 3D seismic program of approximately 1,393 square kilometers.  On April 21, 2010, the first well on the Rajasthan blocks, the Rachan-1 well, commenced drilling on the RJ 21 Block.  Oil India Limited as operator has completed drilling to a total depth of 1,550 meters and the well has been suspended awaiting further testing.  The Madasar-1 well, commenced drilling on August 6, 2010 and has been drilled to a depth of 1,402 meters.  Test results were not positive and as a result, the well was plugged and abandoned in November 2010.  The Madasar-1 well is the second of twenty exploration wells to be drilled over the two blocks.

Our Israel Exploration Activities

Sara and Myra

On October 6, 2010 we commenced exploration activities in Israel by entering into a Joint Operating Agreement with a consortium involved in two existing oil and gas licenses in deep water off the coast of Israel.  We became the operator of both the Sara and Myra licences which commenced with the processing and interpretation of 1,360 square kilometers of previously acquired 3D seismic data with the intention to commence drilling on one of these licenses before the end of the 2011 year.

Samuel

On August 1, 2010 we were granted a license from the state of Israel covering the Samuel license.  We became the co-operator of this license through our partnership with Adira Energy through a commonly owned Israeli company, Adira Geo Global Ltd.

No significant exploration activities were carried out on this license in 2010.

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Our Colombia Exploration Activities

PUT 6 and PUT 7

On September 14, 2010 we entered into a Memorandum of Understanding with Petro Caribbean Resources Ltd. relating to oil and natural gas exploration and development activities in Colombia, subject to execution by Petro Caribbean Resources Ltd. of definitive agreements with the Colombian National Agency of Hydrocarbons.  Subject to the execution of a Joint Operating Agreement, we will be carried for a 10% participating interest in both the PUT 6 and PUT 7 licenses through the minimum and additional work programs as bid in return for us providing to Petro Caribbean Resources Ltd. technical assistance through the exploration phase.  No significant exploration activities were carried out on these licenses in 2010.

Our 2011 Anticipated Oil and Gas Activities

We expect our exploration and development activities pursuant to our PSCs in India will continue through 2011 in accordance with the terms of those agreements.  During 2011 and up to March 31, 2012, based on current budgets, we anticipate drilling seven exploratory wells; two core wells; acquiring, processing and interpreting 2,480 line kilometers of  2D seismic data ; and acquiring, processing and interpreting 350 square kilometers of 3D seismic data as well as processing and interpreting an additional 400 square kilometers of 3D seismic data.  We further expect to tie-in additional oil wells in Tarapur along with the construction of a gas pipeline for the Tarapur G gas discovery and to continue with the construction of the gas gathering and production facilities together with further development drilling on the KG Offshore Block in which we have a carried interest.  Additional expenditures may be incurred in connection with additional exploratory, appraisal and development wells we may participate in.  If the Government of India approves the increase to our participating interest in the KG Onshore Block to 20%, our obligations to fund the 3D seismic acquisition and the exploratory drilling on the block will increase.

We expect our exploration activities pursuant to our other licenses in Israel will continue through 2011 in accordance with the terms of those agreements.  During 2011, we expect to complete the acquisition, processing and interpretation of 43 square kilometers of 3D seismic data in our Samuel license as well as complete the processing and interpretation of 1, 360 square kilometers of 3D seismic data covering our Sara and Myra licenses and also commence drilling our first deepwater exploration well before the end of the year.

We may during 2011 seek to participate in joint ventures bidding for the acquisition of oil and gas interests in India and other countries.  As of March 30, 2011 we have no specific plans regarding such activities and have not entered into any binding agreements with respect to such activities.  We expect that our interest in any such ventures would involve a minority participating interest in the venture.  In addition, although there are no present plans to do so, 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 requisite government consents and other approvals.

As of March 30, 2011, 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 will 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 when 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 such capital will be raised, the price per share or possible number of shares involved or the terms of any agreements to raise capital under other arrangements.

During the first quarter of 2010, we hired a new Senior Executive.  We do not expect to have any further significant change in 2011 in our number of employees.

Reserve Report

As a result of the approval of the Tarapur 1 field development plan by the Management Committee in April 2009 and the completion of an independent reserve study dated January 1, 2011 by Chapman Petroleum Engineering Ltd. of Calgary, Alberta, Canada, we claim reserves in the Tarapur 1 field as at December 31, 2010 as follows:

Summary of Oil and Gas Reserves as of December 31, 2010

Reserves Category	Oil (MBbls)	Natural Gas (MMcf)
PROVED
Developed	55	155
Undeveloped	--	--
TOTAL PROVED	55	155
Probable
Developed	53	143
Undeveloped	356	452
Possible
Developed	--	--
Undeveloped	--	--

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Proved Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinable or probabilistic methods are used for the estimates.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

Development and Exploration Expenditures

The following table sets forth information regarding net costs, after impairment and depletion, we incurred in our development and exploration activities by basin block areas as at December 31 for each of the last three years.

Millions	2010 $	2009 $	2008 $
Development Costs
Cambay Basin Blocks	2.852	4.020	-
	2.852	4.020	--
Exploration Costs
India
Krishna Godavari Basin Blocks	6.455	5.577	5.257
Cambay Basin Blocks	20.859	31.039	24.026
Deccan Syneclise Basin Blocks	2.285	1.054	0.717
Bikaner-Nagaur Basin Blocks	6.424	4.123	4.085
Colombia	0.135	--	--
Israel	1.459	--	--
	37.617	41.793	34.085
Total	40.469	45.813	34.085

As at December 31, 2010 GSPC incurred costs of approximately $189 million (December 31, 2009 - approximately $150 million) for exploration activities on the KG Offshore Block attributable to us under our Carried Interest Agreement with GSPC (of which 50% is for the account of Roy Group (Mauritius) Inc.).  We will not realize cash flow from the KG Offshore Block until such time as the expenditures attributed to us (including those expenditures made for the account of Roy Group (Mauritius) Inc.) under the Carried Interest Agreement have been recovered by GSPC from future production revenue.  Under the terms of the Carried Interest Agreement, all of our proportionate share of capital costs for exploration and development activities must be repaid to GSPC without interest over the projected production life or ten years, whichever is less.  However, we are presently involved in a dispute with GSPC:  see “Item 1 - Business - Our Production Sharing Contracts in India – Our Krishna Godavari Basin Agreements - KG Offshore Block PSC - Carried Interest Agreement Dispute”.

The following table presents the amount of suspended exploratory drilling costs relating to continuing operations at December 31 for each of the last three years, and changes in those amounts during the years then ended and prior.

Millions	$	2010		$	2009		2008 and prior $
Balance at January 1		41.793			34.085			26.093
Additions pending the determination of proved reserves		9.213			12.021			18.090
Reclassification to proved properties		(13.389	)		(4.313	)		--
Charge to impairment expense		--			--			(10.098	)
Balance at December 31		37.617			41.793			34.085

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The following table presents the total amount of suspended exploratory drilling costs as of December 31, 2010 by geographical area, including the year the costs were originally incurred.  The table excludes amounts capitalized and subsequently reclassified to proved oil and gas properties or charged to expense as impairment.

			Year Costs Incurred
Millions	$                            Total		$	2010		$	2009	$              2008 and prior
India
KG Basin		6.455		0.878			0.320		5.257
Cambay Basin		20.859		(10.180	)		7.014		24.025
Bikaner-Nagaur Basin		6.424		2.301			0.037		4.086
Deccan Syncline Basin		2.285		1.231			0.337		0.717
Israel		1.459		1.459			--		--
Colombia		0.135		0.135			--		--
Total		37.617		(4.176	)		7.708		34.085
Suspended exploratory drilling costs capitalized for a period greater than one year after completion of drilling at December 31, 2010 (included in the table above)		28.404

Well costs that have been suspended for longer than one year are associated with ten exploration blocks within four geological basins in India.  The exploration phase for a PSC in India generally covers a period of seven to eight years.  The majority of these costs are suspended pending the completion of an economic evaluation including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data and approval of a Field Development Plan pursuant to the related PSC.  Management believes these projects with suspended exploratory drilling costs exhibit the potential for sufficient quantities of hydrocarbons to justify potential development and is actively pursuing efforts to assess whether reserves can be attributed to these geological basins.  If additional information becomes available that raises doubt as to the economic or operational viability of any of these projects, the associated costs will be evaluated at that time.

Drilling Activity

During the 2010 drilling program, exploratory drilling activity consisted of seven gross completed wells (twenty in 2009; thirty-four in 2008) and development drilling activity consisted of zero gross completed wells (zero in 2009 and 2008).  The following table sets forth information as to wells completed under the terms of our PSCs in India during the periods indicated.

	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total	Total
2010	0.50	0.45	0.95	0	0	0	0.95
2009	1.14	1.00	2.14	0	0	0	2.14
2008	2.29	1.90	4.19	0	0	0	4.19
2007 and prior	2.17	1.95	4.12	0.84	0	0.84	4.96
Total	6.10	5.30	11.4	0.84	0	0.84	12.24

A gathering system and oil tank storage facilities exist within the Tarapur 1 Discovery Area which encompasses six oil wells.

Productive Wells

Productive wells are defined as producing wells and wells mechanically capable of production.  As of December 31, 2010 the Company had an ownership in productive wells completed under the terms of our PSCs as follows:

	Oil Wells	Gas Wells	Total
Gross	45	12	57
Net	6.25	0.69	6.94

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Acreage

At December 31, 2010 we have an interest in approximately 3,736,165 gross acres (1,635,240 net acres) in both developed and undeveloped acreage covering the production sharing and other contracts we are party to.

Contract Interest in Developed Acreage

At December 31, 2010 we hold an interest in one lease within our Tarapur Block consisting of approximately 2.14 square kilometers (529 gross acres and 74 net acres) that is deemed developed or acreage within an approved Field Development Plan assignable to productive wells.  For purposes of the acreage tables as set out below, one square kilometer is converted to approximately 247.105 acres.

	Gross acres	Net acres
Contract Interest in Developed Acreage
Cambay Basin Blocks
Tarapur	529	74
Total Developed Acreage	529	74

Contract Interests in Undeveloped Acreage

Under the terms of the ten PSCs in India, the three licenses in Israel and the two licenses in Colombia to which we are a party, we have an interest in approximately 3,735,636 gross acres (1,635,166 net acres) of undeveloped acreage as of December 31, 2010 after reflecting relinquishment of acreage as required under the production sharing and other contracts.  Undeveloped acreage encompasses those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.  Substantial work commitments must be performed pursuant to each of these production sharing or other contracts before we have any leasehold, concession or other interest in such acreage and there can be no assurance that our exploration activities will result in leases being granted.  Failure to fulfill work commitments or the relinquishment of acreage upon the election to proceed to the next phase of exploration could result in the loss of acreage pursuant to the relinquishment provisions of the PSC.  See “Item 1 – Business - Certain Terms of Our PSCs”.  No leases to any of the undeveloped acreage have been granted and there can be no assurance that we will be granted a leasehold or other interest in this acreage in the future.  Under the terms of the production sharing and other contracts, following the completion of a development plan for a discovery the parties are to apply for a lease from the relevant government authority for the area to be developed.

	Gross acres		Net acres
Contract Interests in Undeveloped Acreage
India
KG Offshore	457,145	(1)		22,857
KG Onshore	135,660	(2)		13,566
Mehsana	22,981	(3)		2,298
Sanand/Miroli	9,835	(3)		983
Ankleshwar	42,502	(3)		4,250
Tarapur	213,993	(3)		38,519
DS 03	584,651	(3)		584,651
DS 04	654,582		654,582
RJ Block 20	542,643		135,661
RJ Block 21	328,650		82,162
Total India Acreage	2,992,642		1,539,529
Israel
Myra	98,842		4,942
Sara	98,842		4,942
Samuel	89,205		40,142
Total Israel Acreage	286,889		50,026
Colombia
PUT 6	414,838		41,484
PUT 7	41,267		4,127
Total Colombia Acreage	456,105		45,611
TOTAL UNDEVELOPED ACREAGE	3,735,636		1,635,166

(1) Excludes acreage that is subject to the Participating Interest Agreement with Roy Group (Mauritius) Inc.

(2) Based on a 10% participating interest

(3) Remaining acreage after relinquishment

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Hedging Activities

At December 31, 2010 we had not entered into any market risk sensitive instruments (as such term is defined in Item 305 of Regulation S-K), relating to our operations.

Marketing

Under the terms of our PSCs, until India’s total production of crude oil and condensate meets the Indian national demand, we are required to sell in the Indian domestic market our entitlement to crude oil and condensate.  When and for so long as India attains self-sufficiency in the production of crude oil and condensate, our domestic sale obligation is suspended and we will have the right to export our entitlement.

The PSCs provide that the Indian domestic market will have the first call on natural gas produced from the areas that are the subject of the contracts.

The PSCs provide that the parties are to agree monthly on a price for crude oil which is intended to be on an import parity basis.  Prices of natural gas are intended to be based on Indian domestic market prices.

Our ability to market any production of crude oil and natural gas will be dependent upon the existence and availability of pipelines or other gathering systems, storage facilities and an ability to transport the hydrocarbons to market.  Except for the Tarapur 1 Development Area where there exists a gathering system and oil tank storage facilities, there are yet to be constructed any facilities as mentioned above on our remaining blocks.

We are not a party to any agreements providing for the delivery of fixed quantities of hydrocarbons.

Competition

We experience competition from others seeking to participate in joint ventures and other arrangements to participate in exploratory drilling ventures.  In addition, the joint ventures in which we participate experience competition from other ventures and persons in seeking from governmental bodies and, possibly others, agreements to grant and enter into production sharing and other contracts.  Management of our company believes that competition in entering into such agreements with governmental bodies is based on the extent and magnitude of exploratory activities that the applicants propose to undertake on the exploration blocks and licenses under consideration as well as the applicants’ available capital and technical ability.

Employees

The services of our President and Chief Executive Officer, Paul B. Miller and our Chief Financial Officer, Sunil S. Karkera and our Vice President of Finance, Allan J. Kent are provided pursuant to Employment Agreements.  As such, the services of Messrs. Miller, Karkera and Kent are provided to us in their capacity as employees of GeoGlobal and each devote substantially all of their time to our affairs.

In addition to Messrs. Miller, Karkera and Kent, as at December 31, 2010 we employ four full time persons and five consultants in Calgary, Alberta, Canada and seven full time persons and two consultants in Gandhinagar, Gujarat, India.

Incorporation and Organization

On August 29, 2003, we acquired all of the issued and outstanding shares of GeoGlobal India, a corporation then wholly-owned by Mr. Jean Paul Roy.  The completion of the acquisition resulted in the issuance and delivery by us of 34,000,000 common shares and delivery of a $2.0 million promissory note to Mr. Roy.  Of such shares, we issued and delivered 14.5 million shares at the closing of the acquisition and 14.5 million shares were released from escrow on August 27, 2004 upon the commencement of a drilling program.  The remaining 5.0 million shares were released from escrow on December 11, 2009 upon confirmation from the GeoGlobal Resources Inc. Board of Directors that the conditions for their release under the terms of the Escrow Agreement had been met.  As a result of this transaction, Mr. Roy held as of the closing of the transaction approximately 69.3% of our issued and outstanding shares.  Mr. Roy was also elected our President and a Director on August 29, 2003.  This transaction is considered an acquisition of GeoGlobal Resources Inc. (the accounting subsidiary and legal parent) by GeoGlobal India (the accounting parent and legal subsidiary) and has been accounted for as a purchase of the net assets of GeoGlobal Resources Inc. by GeoGlobal India.  Accordingly, this transaction represents a recapitalization of GeoGlobal India, the legal subsidiary, effective August 29, 2003.

Through late 2001, we were engaged in the creation, operation and maintenance of a World Wide Web-based community, known as Suite101.com, Inc.  At the end of 2001, management at that time determined to redirect activities and by mid 2002, the company was no longer engaged in the former Web-based activities.

We are a corporation organized under the laws of the State of Delaware in December 1993.  From December 1998 to January 2004, our corporate name was Suite101.com, Inc.  At a meeting held January 8, 2004 our stockholders approved an amendment to our Certificate of Incorporation to change our corporate name to GeoGlobal Resources Inc.

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Item 1A.                 Risk Factors

An investment in shares of our common stock involves a high degree of risk.  You should consider the following factors in addition to the other information contained in this Annual Report in evaluating our business and current and proposed activities before you purchase any shares of our common stock.  You should also see “Item 1A – Risk Factors - Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995” regarding risks and uncertainties relating to us and to forward-looking statements in this Annual Report.

There can be no assurance that the exploratory drilling to be conducted on the exploration blocks and licenses in which we hold an interest will result in any discovery of reserves of hydrocarbons or that any hydrocarbons that are discovered will be in commercially recoverable quantities.  In addition, the realization of any revenues from commercially recoverable hydrocarbons is dependent upon the ability to deliver, store and market any hydrocarbons that are discovered.

Risks Relating to Our Oil and Gas Activities

We Have A History Of Losses And Our Liquidity Position Imposes Risk To Our Operations

To date, we have not achieved our planned principal operations and we are considered to be in the development stage of our operations.  We have incurred negative cash flows from our operations, and at this time all exploration activities and overhead expenses are primarily financed by way of the issue and sale of equity securities with a small portion being financed from oil sales and interest income on our cash balances.  The recoverability of the costs we have incurred to date is uncertain and is dependent upon achieving commercial production or sale.  Our prospects must be considered in light of the risks, expenses and difficulties which are frequently encountered by companies in their early stage of operations, particularly companies in the oil and gas exploration industry.

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 oil and natural gas interests in the future.  Our financial statements as at and for the year ended December 31, 2010 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 incurred a net loss of $18.789 million, and used $4.067 million of cash flow in our operating activities and $12.463 million in our investing activities for the year ended December 31, 2010.  As at December 31, 2010 we had an accumulated deficit of $47.559 million.  These matters raise doubt about our ability to continue as a going concern.

We expect to incur substantial expenditures to further our exploration and development programs.  The existing cash balance and any cash flow from operating activities may not be sufficient to satisfy current obligations and meet our exploration and development commitments.  Development activities within our blocks and licenses that are unable to achieve production in the short term may need to be deferred or curtailed.  We are considering various alternatives to remedy any future shortfall in capital.  We may deem it necessary to raise capital through equity markets, debt markets or other financing arrangements, including participation arrangements that may be available.  Because of the early stage of our operations and our absence of any material oil and natural gas reserves and revenues, 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 expenditures which could lead to our inability to meet all of our commitments.

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 our consolidated financial statements) in the normal course of operations, adjustments would be required to our consolidated financial statements to the amounts and classifications of assets and liabilities, and these adjustments could be significant.  Our 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.

GSPC Is Seeking a Substantial Payment From Us On Account Of GSPC’s Exploration Costs On the KG Offshore Block

GSPC has advised us that it is seeking from us payment of our pro rata portion of the amount by which the sums expended by GSPC under all phases for the minimum work program as set forth in the PSC for the KG Offshore Block in carrying out exploration activities on the block exceeds the amount that GSPC deems to be our pro rata portion of a financial commitment under all phases included in the parties’ joint bid for the award of the KG Offshore Block by the Government of India.

GSPC contends that this excess amount is not within the terms of the Carried Interest Agreement and that we are required to pay 10% of the exploration expenses over and above gross costs of $109.7 million (10% being $10.97 million) (including the net 5% interest of Roy Group (Mauritius) Inc.) plus interest.

For a full description of this matter, see “Item 1 - Business – Our Production Sharing Contracts in India – Our Krishna Godavari Basin Agreements - KG Offshore Block PSC – Carried Interest Agreement Dispute”.

We estimate that the amount of GSPC’s claim as of December 31, 2010 to be approximately $189 million plus interest of which 50% is for the account of Roy Group (Mauritius) Inc.

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We dispute these positions of GSPC and the conclusions reached by GSPC and we intend to vigorously protect our contractual rights in accordance with the dispute resolution process under the Carried Interest Agreement, the PSC and the Joint Operating Agreement as may be appropriate.  However, there can be no assurance that we will not by operation of law or through the dispute resolution process be required to pay GSPC the full amount it alleges to be owed, nor that adequate capital will be available to us to pay any such amounts, with consequent impact on our ability to continue as a going concern.

Our Activities Have Only Recently Commenced And We Have a Very Limited Operating History. Our Reserves Of Oil And Gas Are Not Material. We Anticipate Future Losses and There Is No Assurance Of Our Success.

We are in the early stage of developing our operations.  We have a very limited operating history and we have realized very limited revenues from our activities.  We do not have material reserves of oil and gas as at December 31, 2010.

Our activities in the oil and natural gas exploration and production industry have primarily involved entering into ten PSCs with the Government of India.  We also have exploration activities in Israel and Colombia however those activities are in the very early stages of development.  Our exploration opportunities are highly speculative and should any of these opportunities not result in the discovery of commercial quantities of oil and gas reserves, our investment in the venture could be lost.  Our current plans are to conduct the exploration and development activities on the areas offshore and onshore in accordance with the terms of the production sharing and other contracts we are a party to.  There can be no assurance that the exploratory drilling to be conducted on the exploration blocks in which we hold an interest will result in any discovery of hydrocarbons or that any hydrocarbons that are discovered will be in commercially recoverable quantities.  Further, the realization of any revenues from commercially recoverable hydrocarbons is substantially dependent upon the ability to deliver, store and market any hydrocarbons discovered.  As of March 30, 2011 there are no or limited facilities for the delivery and storage of hydrocarbons in the areas covered by our PSCs and licenses.

As a company engaged in exploratory oil and gas activities we are exposed to a number of special risks including, among others;

·   We may experience failures to discover oil and gas in commercial quantities;

·   There are uncertainties as to the costs to be incurred in our exploratory drilling activities, cost overruns are possible and we may encounter mechanical difficulties and failures in completing wells;

·   There are uncertain costs inherent in drilling into unknown formations, such as over-pressured zones, high temperatures and tools lost in the hole; and

·   We may make changes in our drilling plans and locations as a result of prior exploratory drilling.

There can be no assurance that the ventures in which we are a participant or hold an interest will be successful in addressing these risks, and any failure to do so could have a material adverse effect on our prospects for the future.

We Expect to Have Substantial Requirements Under the Terms of Our Production Sharing And Other Contracts For Additional Capital That May Be Unavailable To Us Which Could Limit Our Ability To Participate In Our Existing Ventures.  Our Available Capital is Limited

In order to participate under the terms of our production sharing or other contracts in future exploration, appraisal or development programs, we will be required to contribute or have available to us material amounts of capital.  Under the terms of our Carried Interest Agreement relating to the KG Offshore Block, after the start date of initial commercial production on the KG Offshore Block, and under the terms of the nine other PSCs we are parties to in India, we are required to bear our proportionate share of costs during the exploration and development phases of those agreements.  Under the terms of the three licenses we are a party to in Israel we are required to bear our proportionate share of costs during the exploration and development phases of those agreements.  There can be no assurance that our currently available capital will be sufficient for these purposes or that any additional capital that is required will be available to us in the amounts and at the times required.  Such capital also may be required to secure bank guarantees in connection with the grant of exploration rights, to conduct or participate in exploration activities or be engaged in drilling, completion and development activities.  We intend to seek additional capital to meet our requirements from equity markets, debt markets or other financing arrangements, including participation arrangements that may be available for continued exploration and development expenditures.  Our ability to access additional capital will depend in part on the success of the ventures in which we are a participant in locating reserves of oil and gas and developing producing wells on the exploration blocks and licenses, the results of our management in locating, negotiating and entering into joint venture or other arrangements on terms considered acceptable, as well as the status of the capital markets at the time such capital is sought.

Should we be unable to access the capital markets or should sufficient capital not be available, our activities could be delayed or reduced and, accordingly, any future exploration opportunities, revenues and operating activities may be adversely affected and could also result in our breach of the terms of a production sharing or other contract which could result in the loss of our rights or a portion thereof under the contract.

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As of December 31, 2010 we had cash and cash equivalents of approximately $7.751 million.  We believe that our available cash resources together with amounts we intend to seek from equity markets, debt markets or other financing arrangements will be sufficient to meet all our expenses and cash requirements during the year ending December 31, 2011 for our present level of operations on the exploration blocks and licenses in which we are currently a participant in.  Although exploration activity budgets are subject to ongoing review and revision, our present estimate of commitments of capital pursuant to the terms of our production sharing contracts relating to our ten exploration blocks in India and our three licenses in Israel totals approximately $13.152 million during the year ending December 31, 2011.  Upon receipt of approval from the Government of India for the increase to a 20% participating interest on the KG Onshore Block, these expenditures will increase by $1.804 million.  Any further production sharing or other contracts we may seek to enter into or any expanded scope of operations or other transactions that we may enter into may require us to fund our participation or capital expenditures with amounts of capital not currently available to us.  We may be unsuccessful in raising the capital necessary to meet these capital requirements.

Possible Inability Of Contracting Parties To Fulfill The Minimum Work Programs For Certain Of Our PSCs

Our PSCs relating to our exploration blocks in India provide that by the end of each exploration phase the contracting parties shall have drilled a certain number of wells or performed certain exploration activities.  The PSCs have provisions for termination of the PSCs on account of various reasons specified therein including material breach of the contract.  This failure to timely complete the minimum work program may be deemed to constitute such a breach.  Termination rights can be exercised after giving ninety days written notice.  The termination of a PSCby the Government of India would result in the loss of our interest in the PSC other than contract areas of the PSC determined to encompass Commercial Discoveries.

In the event the minimum work program is not fulfilled by the end of the relevant exploration phase, the PSC provides that each party to the PSC is to pay to the Government of India its participating interest share of an amount which is equal to the amount that would be required to complete the minimum work program for that phase.

Risks Associated With Our Holding A Carried Interest

Under the terms of our KG Offshore Carried Interest Agreement, we are carried by GSPC for all our share of any costs and expenses during the exploration phase on the KG Offshore Block prior to the start date of initial commercial production.  Under the terms of our Carried Interest Agreement, after deducting all royalties payable, GSPC is entitled to recover all such costs and expenses out of production from wells drilled by GSPC on the block before we are entitled to receive any share of the production.  Accordingly, we will not be entitled to receive any production of hydrocarbons or revenues from wells drilled on the block until such time as GSPC has recovered the costs and expenses GSPC paid during the exploration phase on our behalf.

As operator of the KG Offshore Block, GSPC is required to conduct exploration and drilling operations on the block in accordance with generally accepted oil and gas industry standards, subject to the terms of a Joint Operating Agreement, and is entitled to make all decisions and take all actions necessary in fulfilling the minimum work program commitments and future development commitments made relating to the KG Offshore Block.  Through December 31, 2010, GSPC had expended approximately $189 million on our behalf under the terms of the Carried Interest Agreement of which 50% is for the account of Roy Group (Mauritius) Inc. and it is expected that those expenses will increase materially thereafter.  There can be no assurance as to when, if ever, GSPC will recover our share of exploration costs and expenses.  Until such time, we will realize no revenues from our interest in the KG Offshore Block.  Accordingly, our ability to receive revenues from hydrocarbon production from the KG Offshore Block, notwithstanding our carried interest, is dependent upon future production and price realized being sufficient to enable GSPC to recover the costs and expenses it incurs on our behalf.

India’s Regulatory Regime May Increase Our Risks And Expenses In Doing Business

All phases of the oil and gas exploration, development and production activities in which we are participating are regulated in varying degrees by the Indian government, either directly or through one or more governmental entities.  The areas of government regulation include matters relating to restrictions on production, price controls, export controls, income taxes, expropriation of property, environmental protection and rig safety.  In addition, the award of a PSC is subject to Government of India consent and matters relating to the implementation and conduct of operations under the PSC are subject, under certain circumstances, to Government of India consent.  As a consequence, all future drilling and production programs and operations we undertake or undertaken by the ventures in which we participate in India must be approved by the Indian government.  Shifts in political conditions in India could adversely affect our business in India and the ability to obtain requisite government approvals in a timely fashion or at all.  We and our joint venture participants must maintain satisfactory working relationships with the Indian government.  This regulatory environment and possible delays inherent in that environment may increase the risks associated with our exploration and production activities and increase our costs of doing business.

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We Are Dependent On The Operators Of Our Ventures And Their Failure Or Inability To Operate An Exploration Block

We have contractual rights under terms of ten PSCs with the Government of India.  We are not the operator of eight of these ten exploration blocks.  On the DS 03 Block and the DS 04 Block we hold a 100% interest and are the operator.  The realization of success in the non-operated exploration blocks is substantially dependent upon the success of the operators in exploring for and developing reserves of oil and gas and their ability to market those reserves at prices that will yield a return to us.

The minimum work programs required to be conducted by the contracting parties under certain of the PSCs to which we are a party have not been completed by the operators within the time frames required by the PSCs.  This circumstance could lead to the assessment of damages against the contracting parties and the loss of our investments under the PSCs.  We are dependent upon the operators to timely complete these minimum work programs.

In addition, we are presently involved in a dispute with the operator of the KG Offshore Block.  For a full description of this matter, see “Item 1 - Business – Our Production Sharing Contracts in India – Our Krishna Godavari Basin Agreements - KG Offshore Block PSC – Carried Interest Dispute”.

Certain Terms Of The PSCs May Create Additional Expenses And Risks That Could Adversely Affect Our Revenues And Profitability

The PSCs contain certain terms that may affect the revenues of the joint venture participants to the agreements and create additional risks for us.  These terms include, among others, the following:

·   The venture participants are required to complete certain minimum work programs during the two or three phases of the terms of the PSCs.  In the event the venture participants fail to fulfill any of these minimum work programs, the parties to the venture must pay to the Government of India their proportionate share of the amount that would be required to complete the minimum work program.  Accordingly, we could be called upon to pay our proportionate share of the estimated costs of any incomplete work programs;

·   Until such time as the Government of India attains self sufficiency in the production of crude oil and condensate and is able to meet its national demand, the parties to the venture are required to sell in the Indian domestic market their entitlement under the PSCs to crude oil and condensate produced from the exploration blocks.  In addition, the Indian domestic market has the first call on natural gas produced from the exploration blocks and the discovery and production of natural gas must be made in the context of the government’s policy of utilization of natural gas and take into account the objectives of the government to develop its resources in the most efficient manner and promote conservation measures.  Accordingly, this provision could interfere with our ability to realize the maximum price for our share of production of hydrocarbons;

·   The parties to each agreement that are not Indian companies, which includes us, are required to negotiate technical assistance agreements with the Government of India or its nominee whereby such foreign company can render technical assistance and make available commercially available technical information of a proprietary nature for use in India by the government or its nominee, subject, among other things, to confidentiality restrictions.  Although not intended, this could increase each venture’s and our cost of operations; and

·   The parties to each venture are required to give preference, including the use of tender procedures, to the purchase and use of goods manufactured, produced or supplied in India provided that such goods are available on equal or better terms than imported goods, and to employ Indian subcontractors having the required skills insofar as their services are available on comparable standards and at competitive prices and terms.  Although not intended, this could increase the ventures and our cost of operations.

These provisions of the PSCs, among others, may increase our costs of participating in the ventures and thereby affect our profitability.  Failure to fully comply with the terms of the PSCs creates additional risks for us.

Our International Operations May Be Adversely Affected By War, Terrorist Acts, Or Civil Disturbances That May Occur In Regions That Encompass Our Operations

We conduct exploration and development activities in Israel.  These areas have historically been less politically stable than other areas in which we conduct business.

In recent weeks civil unrest has resulted in changes to the Tunisian and Egyptian governments.  There have been numerous demonstrations and some of the demonstrations have been marked by violence.

Civil unrest could continue to spread throughout the region.  Such unrest, if it continues to grow in intensity, could lead to civil war; regime change resulting in governments that are hostile to the US and/or Israel, or other regional conflict.

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At this time we are uncertain of the outcome of these events. However, prolonged and/or widespread regional conflict in the Middle East could have the following results, among others:

·   volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;

·   negative impact on the world crude oil supply if transportation avenues are disrupted, leading to further commodity price volatility;

·   capital market reassessment of risk and subsequent redeployment of capital to more stable areas making it more difficult for partners to obtain financing for potential development projects;

·   security concerns in Israel, making it more difficult for our personnel or supplies to enter or exit the country;

·   reduced market demand in Israel for natural gas due to efforts to conserve domestic resources;

·   security concerns leading to evacuation of our personnel;

·   damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;

·   inability of our service and equipment providers to deliver items necessary for us to conduct  our operations in Israel, resulting in delayed start-up of our Samuel or Sara and Myra projects; and

·   lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region.

Loss of property and/or interruption of our business plans resulting from hostile acts could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.

Our Control By Certain Directors And Executive Officers May Result In Those Persons Having Interests Divergent From Our Other Stockholders

As of March 30, 2011, our Directors and executive officers and their respective affiliates in the aggregate, beneficially hold 32,696,000 shares or approximately 39.5% of our outstanding Common Stock.  As a result, these persons possess significant influence over us, which may give them the ability, among other things, to elect a majority of our Board of Directors and approve significant corporate transactions.  These persons may retain significant control over our present and future activities and our other stockholders and investors may be unable to meaningfully influence the course of our actions.  These persons may have interests regarding future activities and transactions in which we engage which may diverge from the interests of our other stockholders.  Such share ownership and control may also have the effect of delaying or preventing a change in control of us, impeding a merger, consolidation, takeover or other business combination involving us, or discourage a potential acquiror from making a tender offer or otherwise attempting to obtain control of us which could have a material adverse effect on the market price of our common stock.  Although management has no intention of engaging in such activities, there is also a risk that the existing management will be viewed as pursuing an agenda which is beneficial to themselves at the expense of other stockholders.

Oil And Gas Prices Fluctuate Widely And Low Oil And Gas Prices Could Adversely Affect Our Financial Results

There is no assurance that there will be any market for oil or gas produced from the exploration blocks in which we hold an interest and the ability to deliver production from any wells may be constrained by the absence of or limitations on collector systems and pipelines.  Future price fluctuations could have a major impact on future revenue from any oil and gas produced on these exploration blocks and could materially affect the return from and the financial viability of any reserves claimed.  Historically, oil and gas prices have been volatile, and they are likely to continue to be volatile in the future.  A significant decrease in oil and gas prices could have a material adverse effect on our cash flow and profitability and would adversely affect our financial condition and results of operations.  Prices for oil and gas fluctuate in response to relatively minor changes in the supply and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control, including:

·   political conditions and civil unrest in oil producing regions, including the Middle East and elsewhere;

·   the domestic and foreign supply of oil and gas;

·   quotas imposed by the Organization of Petroleum Exporting Countries upon its members;

·   the level of consumer demand;

·   weather conditions;

·   domestic and foreign government regulations;

·   the price and availability of alternative fuels;

·   overall economic conditions; and

·   international political conditions.

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In addition, various factors may adversely affect the ability to market oil and gas production from our exploration blocks, including:

·   the capacity and availability of oil and gas gathering systems and pipelines;

·   the ability to produce oil and gas in commercial quantities and to enhance and maintain production from existing wells and wells proposed to be drilled;

·   the proximity of future hydrocarbon discoveries to oil and gas transmission facilities and processing equipment (as well as the capacity of such facilities);

·   the effect of governmental regulation of production and transportation (including regulations relating to prices, taxes, royalties, land tenure, allowable production, importing and exporting of oil and condensate and matters associated with the protection of the environment);

·   the imposition of trade sanctions or embargoes by other countries;

·   the availability and frequency of delivery vessels;

·   changes in supply due to drilling by others;

·   the availability of drilling rigs and qualified personnel; and

·   changes in demand.

Our Future Performance Depends Upon Our Ability And The Ability Of The Ventures In Which We Participate To Find Or Acquire Oil And Gas Reserves That Are Economically Producible

Our success in developing our oil and gas exploration and development activities will be dependent upon establishing, through our participation with others in joint ventures and other similar activities, reserves of oil and gas and maintaining and possibly expanding the levels of those reserves.  We and the joint ventures in which we may participate may not be able to locate and thereafter replace reserves from exploration and development activities at acceptable costs.  Lower prices of oil and gas may further limit the kinds of reserves that can be developed at an acceptable cost.  The business of exploring for, developing or acquiring reserves is capital intensive.  We may not be able to make the necessary capital investment to enter into joint ventures or similar arrangements to maintain or expand our oil and gas reserves if capital is unavailable to us and the ventures in which we participate.  In addition, exploration and development activities involve numerous risks that may result in dry holes, the failure to produce oil and gas in commercial quantities, the inability to fully produce discovered reserves and the inability to enhance production from existing wells.

We expect that we will continually seek to identify and evaluate joint venture and other exploration opportunities for our participation as a joint venture participant or through some other arrangement.  Our ability to enter into additional exploration activities will be dependent to a large extent on our ability to negotiate arrangements with others and with various governments and governmental entities whereby we can be granted a participation in such ventures.  There can be no assurance that we will be able to locate and negotiate such arrangements, have sufficient capital to meet the costs involved in entering into such arrangements or that, once entered into, that such exploration activities will be successful.  Successful acquisition of exploration opportunities can be expected to require, among other things, accurate assessments of potential recoverable reserves, future oil and gas prices, projected operating costs, potential environmental and other liabilities and other factors.  Such assessments are necessarily inexact, and as estimates, their accuracy is inherently uncertain.  We cannot assure you that we will successfully consummate any further exploration opportunities or joint venture or other arrangements leading to such opportunities.

Estimating Reserves And Future Net Revenues Involves Uncertainties And Oil And Gas Price Declines May Lead To Impairment Of Oil And Gas Assets

We do not claim any material proved or probable reserves of oil or natural gas as at December 31, 2010.  Any reserve information that we may provide in the future will represent estimates based on reports prepared by independent petroleum engineers, as well as internally generated reports.  Petroleum engineering is not an exact science.  Information relating to proved oil and gas reserves is based upon engineering estimates derived after analysis of information we furnish or furnished by the operator of the property.  Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, capital expenditures and work-over and remedial costs, all of which may in fact vary considerably from actual results.  Oil and gas prices, which fluctuate over time, may also affect proved reserve estimates.  For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially.  Actual production, revenues and expenditures with respect to reserves we may claim will likely vary from estimates, and such variances may be material.  Inaccuracies in estimates of proved undeveloped reserves or the inability to fund development could result in substantially reduced reserves.  In addition, the timing of receipt of estimated future net revenues from proved undeveloped reserves will be dependent upon the timing and implementation of drilling and development activities estimated by us for purposes of the reserve report.

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Quantities of proved reserves are estimated based on economic conditions in existence in the period of assessment.  Lower oil and gas prices may shorten economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates.  If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense.  The revisions may also be sufficient to trigger impairment losses on certain properties that would result in a further non-cash charge to earnings.

Risks Relating To The Market For Our Common Stock - Volatility Of Our Stock Price

The public market for our common stock has been characterized by significant price and volume fluctuations.  There can be no assurance that the market price of our common stock will not decline below its current or historic price ranges.  The market price may bear no relationship to the prospects, stage of development, existence of oil and gas reserves, revenues, earnings, assets or potential of our company and may not be indicative of our future business performance.  The trading price of our common stock could be subject to wide fluctuations.  Fluctuations in the price of oil and gas and related international political events can be expected to affect the price of our common stock.  In addition, the stock market in general has experienced extreme price and volume fluctuations that have affected the market price for many companies which fluctuations have been unrelated to the operating performance of these companies.  These market fluctuations, as well as general economic, political and market conditions, may have a material adverse effect on the market price of our common stock.  In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been instituted against such companies.  Such litigation, if instituted, and irrespective of the outcome of such litigation, could result in substantial costs and a diversion of management’s attention and resources and have a material adverse effect on our business, results of operations and financial condition.

Cautionary Statement For Purposes Of The “Safe Harbor” Provisions Of The Private Securities Litigation Reform Act Of 1995

With the exception of historical matters, the matters discussed in this Report are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 that involve risks and uncertainties.  Forward-looking statements made herein include, but are not limited to:

·   statements in this Report regarding our plans and objectives relating to our future operations,

·   plans and objectives regarding the exploration, development and production activities conducted on the exploration blocks in India, Israel and Colombia where we have interests,

·   plans regarding drilling activities intended to be conducted through the ventures in which we are a participant, the success of those drilling activities and our ability and the ability of the ventures to complete any wells on the exploration blocks, to develop reserves of hydrocarbons in commercially marketable quantities, to establish facilities for the collection, distribution and marketing of hydrocarbons, to produce oil and natural gas in commercial quantities and to realize revenues from the sales of those hydrocarbons,

·   our ability to maintain compliance with the terms and conditions of licenses and our production sharing and other contracts, including the related work commitments, to obtain consents, waivers and extensions under the terms of these licenses and production sharing and other contracts as and when required, and our ability to fund those work commitments,

·   our plans and objectives to join with others or to directly seek to enter into or acquire interests in additional licenses and production sharing or other contracts in India, Israel, Colombia and elsewhere,

·   our assumptions, plans and expectations regarding our future capital requirements,

·   our plans and intentions to raise additional capital we require and our likelihood of success in that regard,

·   the costs and expenses to be incurred in conducting exploration, well drilling, development and production activities, our estimates as to the anticipated annual costs of those activities and the adequacy of our capital to meet our requirements for our present and anticipated levels of activities are all forward-looking statements.

These statements appear, among other places, in Part I under the caption “Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Part II under the caption “Item 1A - Risk Factors”.  If our plans fail to materialize, your investment will be in jeopardy.

·   We cannot assure you that our assumptions or our business plans and objectives will prove to be accurate or be able to be attained.

·   We cannot assure you that the exploratory drilling to be conducted on the exploration blocks in which we hold an interest will result in a discovery of reserves of hydrocarbons or that any hydrocarbons discovered will be in commercially recoverable quantities.  In addition, the realization of any revenues from commercially recoverable hydrocarbons is dependent upon the ability to deliver, store and market any hydrocarbons discovered.

·   Our ability to realize material revenues cannot be assured.  Our ability to successfully drill, test and complete significant numbers of producing wells cannot be assured.

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·   We cannot assure you that we will have available the capital required to meet our plans and objectives at the times and in the amounts required or we will have available to us the amounts we are required to fund under the terms of the licenses or production sharing and other contracts we are a party to.  We cannot assure you that we will be successful in raising the additional capital we currently require.

·   We cannot assure you that we will be successful in joining any further ventures seeking to be granted licenses or production sharing or other contracts in India, Israel, Colombia or elsewhere or that we will be successful in acquiring interests in existing ventures.

·   We cannot assure you that we will obtain all required consents, waivers and extensions from a governmental or regulatory body in India, Israel or Colombia as and when required to maintain compliance with the licenses or production sharing or other contracts we have entered into, that we may not be adversely affected by any delays we may experience in receiving those consents, waivers and extensions, and that we may not incur liabilities under the production sharing or other contracts for our failure to maintain compliance with the requirements of and timely complete the related work programs.

·   We cannot assure you that GSPC, will not be successful in its efforts to obtain payment from us on account of exploration costs it has expended on the KG Offshore Block for which it asserts we are liable or otherwise seek to hold us in breach of the PSC or commence arbitration proceedings against us and be successful in its assertion that it can terminate our contract with them or the Government of India.

·   We cannot assure you of our ability to meet our goals and objectives.  The consequences to us from adverse developments in general economic or capital market conditions, events having international consequences, or military or terrorist activities could have a material adverse effect on us.

An investment in shares of our common stock involves a high degree of risk.  There can be no assurance that the exploratory drilling to be conducted on the exploration blocks in which we hold an interest will result in any discovery of reserves of hydrocarbons or that any hydrocarbons that are discovered will be in commercially recoverable quantities.  In addition, the realization of any revenues from commercially recoverable hydrocarbons is dependent upon the ability to deliver, store and market any hydrocarbons that are discovered.

Our inability to meet our goals and objectives or the consequences to us from adverse developments in general economic or capital market conditions, events having international consequences, or military or terrorist activities could have a material adverse effect on us.  We caution you that various risk factors accompany those forward-looking statements and are described, among other places, under the caption “Risk Factors” herein.  They are also described in our Quarterly Reports on Form 10-Q and our Current Reports on Form 8-K.  These risk factors could cause our operating results, financial condition and ability to fulfill our plans to differ materially from those expressed in any forward-looking statements made in this Report and could adversely affect our financial condition and our ability to pursue our business strategy and plans.

Item 1B.                Unresolved Staff Comments

As of December 31, 2010 we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

Item 2.                 Properties

Our corporate head office is located at Suite #200, 625 – 4 Avenue SW, Calgary, Alberta, T2P 0K2 Canada.  These premises are leased for a term of 35 months ending January 31, 2013 at an annual rental of approximately $165,000 for base rent and operating costs.  These premises include approximately 3,515 square feet which we consider adequate for our present activities.

Our India operations office is located at 304 & 305, Third floor, IT Tower – II Infocity, Gandhinagar, 382 009 India.  We purchased these premises which are part of an office condominium complex.  The premises include approximately 11,203 square feet which we consider adequate for our activities.  The annual operating and maintenance cost of these premises is approximately $11,000.

Our interests in oil and gas properties are described under “Item 1 - Business”.

Item 3.                Legal Proceedings

There are no legal proceedings pending against us.

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

No matter was submitted during the fourth quarter of the year ended December 31, 2010 to a vote of our securityholders through the solicitation of proxies or otherwise.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our Common Stock is traded on the NYSE Amex (formerly the American Stock Exchange) under the symbol GGR.  The following table sets forth the quarterly high and low sales price for the period January 1, 2009 through March 30, 2011.

Year	Calendar Quarter	High ($)	Low ($)
2009	First Quarter	1.67	0.50
	Second Quarter	1.60	0.70
	Third Quarter	1.39	0.75
	Fourth Quarter	3.04	0.90
2010	First Quarter	2.80	1.50
	Second Quarter	1.95	0.95
	Third Quarter	1.11	0.61
	Fourth Quarter	1.09	0.66
2011	First Quarter (up to March 30, 2011)	1.00	0.63

On March 30, 2011 the closing sales price for our Common Stock as reported on the NYSE Amex was $0.67.

Holders

As of March 30, 2011 we had approximately 80 shareholders of record.  This does not include the number of shareholders of our Common Stock held beneficially in street name.

Dividends

We did not pay any dividends on our Common Stock during the years ended December 31, 2010 and 2009 and we do not intend to pay any dividends on our Common Stock for the foreseeable future.  Any determination as to the payment of dividends on our Common Stock in the future will be made by our Board of Directors and will depend on a number of factors, including future earnings, capital requirements, financial condition and future prospects as well as such other factors as our Board of Directors may deem relevant.

Performance Graph

The following graph compares the performance of our Common Stock over the preceding five-year period.  The following graph is presented as required by SEC rules.  The comparison (change in year-end stock price plus reinvested dividends) assumes that $100 was invested on December 31, 2005 in each of the shares of GeoGlobal Resources Inc., Cubic Energy, Inc., Abraxas Petroleum Corporation and the S&P 500 Index.  It includes the reinvestment of any dividends, although we have never paid any cash dividends.

(1) Cubic Energy, Inc. is a NYSE/Amex listed company engaged in development and production in oil and gas in the United States.  This Company falls under the same SIC code of “Drilling of Oil and Gas Wells” as GeoGlobal.  It has a market capitalization of less than $200.0 million and revenues of less than $100.0 million.  Therefore, we deem it to be comparative to our company for these purposes.

(2) Abraxas Petroleum Corporation is a NASDAQ listed company with operations principally in Texas and the Rocky Mountains and is engaged in exploration, development and production of natural gas and crude oil in Texas and Wyoming.  Although this company has production and reserves, it has a market capitalization of less than $200.0 million and revenues of less than $100.0 million.  Therefore, we also deem it to be comparative to our company for these purposes.

The Performance Graph is not deemed to be “soliciting material” or filed with the Securities and Exchange Commission under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, or incorporated by reference in any documents so filed.

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Comparison of Cumulative Total Return

The following table sets forth the dollar amounts used in the above comparison:

		2005	2006	2007	2008	2009	2010
GeoGlobal Resources Inc.	GGR	100.00	61.47	38.76	12.53	16.21	6.19
S&P 500 Index	$INX	100.00	113.61	117.62	72.35	89.32	100.77
Cubic Energy, Inc.	QBC	100.00	106.67	202.67	180.00	198.67	133.33
Abraxas Petroleum Corp.	AXAS	100.00	58.52	73.11	13.64	36.36	86.55

Recent Sales of Unregistered Securities

There were no sales of unregistered securities during the quarter ended December 31, 2010.  All sales of unregistered securities prior to October 1, 2010 during the fiscal year ended December 31, 2010, if any, were previously reported.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

No purchases of shares of our Common Stock were made by us or on our behalf or by any “affiliated purchaser”, as defined in Rule 10b-18(a)(3) under the U.S. Securities Exchange Act of 1934, as amended, during the quarter ended December 31, 2010.

Item 6.                 Selected Financial Data

Set forth below is certain financial information for each of the five years ended December 31, 2010, 2009, 2008, 2007 and 2006 taken from our audited financial statements for those years.

	December 31,
	2010	2009	2008	2007	2006
Oil and gas sales	790,342	661,922	--	--	--
Interest Income	52,607	299,550	1,148,479	2,165,920	1,751,550
Asset Impairment	13,789,000	--	10,098,015	--	--
Net loss and comprehensive loss	18,788,624	4,424,247	13,313,915	1,543,110	1,548,803
Net loss per share – basic and diluted	0.25	0.09	0.20	0.04	0.03
Current assets	12,500,689	16,532,345	25,904,515	48,406,887	32,597,031
Property and equipment	41,375,680	46,813,004	35,160,814	27,256,945	12,121,334
Total assets	58,894,369	70,270,349	71,865,329	80,219,312	48,492,561
Current liabilities	8,544,120	10,053,780	9,211,020	6,329,980	1,955,195
Total liabilities	9,285,264	10,828,780	9,844,618	6,648,902	1,955,195
Stockholders’ equity	49,609,105	59,441,569	62,020,711	73,570,410	46,537,366
Cash dividends	- 0 -	- 0 -	- 0 -	- 0 -	- 0 -

Item 7.                Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with, and is qualified in its entirety by, the more detailed information including our Consolidated Financial Statements and the related Notes appearing elsewhere in this Annual Report.  This Annual 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 Item 1A. - Risk Factors as well as those discussed elsewhere in this Annual Report.

Our Business Activities

We are engaged, through our subsidiaries, in the exploration for and development of oil and natural gas reserves.  At December 31, 2010 we have not yet achieved our planned principal operations and are considered to be a development stage enterprise.  We initiated these activities in 2003.  The recoverability of the costs we have incurred to date is uncertain and dependent upon achieving commercial production and sale of hydrocarbons, our ability to obtain sufficient financing to fulfill our obligations under the production sharing or other contracts we are a party to with respect to oil and natural gas exploration and development activities in India, Israel and Colombia and upon future profitable operations.  At present, our activities are being undertaken in four geological basins located offshore and onshore in India, one geological basin located offshore Israel and one geological basin located onshore in Colombia where reserves of oil or natural gas are believed by our management to exist.

The exploration rights pursuant to PSCs we have entered into with the Government of India are located in the following areas:

·   The Krishna Godavari Basin offshore and onshore in the State of Andhra Pradesh in south 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 Bikaner-Nagaur Basin onshore in the State of Rajasthan in north western India.

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The exploration rights pursuant to licenses we have been granted in Israel are located in the Levantine Basin located off the coast of Israel with the licenses varying in distances between 6 and 25 miles offshore.

We have entered into a Memorandum of Understanding (MOU) with respect to two exploration blocks located in the Putumayo Basin onshore in southwest Colombia.

May 2009 saw the commencement of oil revenue from our Tarapur exploration block in the Cambay Basin.  To date however, we have not achieved our planned principal operations and are considered to be in the development stage.  The recoverability of the exploration costs we have incurred to date is uncertain and dependent upon us achieving significant commercial production, 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.

Results of Operations for the Years ended December 31, 2010 and 2009

For the year ended December 31, 2010 we incurred a net loss of $18.789 million as compared to a net loss of $4.424 million for the year ended December 31, 2009.  The increase in the net loss is mostly a result of realizing an asset impairment in 2010 of $13.789 million compared with no asset impairment in the year 2009.

Oil and gas operations

	Year ended December 31, 2010		Year ended December 31,  2009
Oil Production (barrels)	9,161		10,856
Oil Sales (barrels)	8,496		9,828
Oil Sales	$	632,734	$		661,922
Average Oil Price per Barrel	$	74.48	$		67.35
Gas Sales (Mcf)	19,603		--
Gas Sales	$	157,608	$	--
Average Gas Price per Mcf	$	8.04	$	--
Operating Costs	$	173,297	$	98,878
Operating Costs per Barrel	$	18.92	$	9.11
Depletion	$	767,000	$	293,700
Depletion per Barrel	$	83.72	$	27.05

Oil sales

All of our oil sales are derived from production in India.  With the approval of the Tarapur 1 field development plan by the Management Committee, three wells began production in mid-May 2009, two in September 2009 and one in January 2010. There are ten additional wells which are drilled, tested and awaiting tie-in to the oil tank storage facilities.  Oil sales for the year ended December 31, 2010 were $0.633 million or $74.48 per barrel compared to oil sales for the year ended December 31, 2009 of $0.662 million or $67.35 per barrel.  Oil sales are currently based on a discount to the spot price based on the Nigeria Bonny Light Crude bench mark.  To date, none of our production has been hedged.

Gas sales

In addition to the crude oil production from the six wells in Tarapur, associated natural gas was contained and sold commencing January 2010. Prior thereto, the associated natural gas was flared off.  As a result, total gas sales for the year ended December 31, 2010 was $0.158 million or $8.04 per Mcf as compared to $nil for the year ended December 31, 2009. There is one gas well awaiting approval for the development plan.

Interest income

Interest income decreased to $0.053 million for the year ended December 31, 2010 as compared to $0.300 million for the same period in 2009.  This decrease is directly related to the decrease in the amount of our invested cash balances.

Operating costs

Operating costs for the year ended December 31, 2010 were $0.173 million or $18.92 per barrel, compared to $0.099 million or $9.11 per barrel for the year ended December 31, 2009.  The operating costs include handling and processing charges, transportation costs, utilities, maintenance and tank rental charges and contain a fixed and variable portion.

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General and administrative

Our general and administrative expenses increased to $3.193 million from $2.987 million.  These general and administrative expenses include costs related to the corporate head office including administrative salaries and services, directors’ fees, rent and office costs, insurance, bank guarantee fees, NYSE Amex listing and filing fees, investor relation services and transfer agent fees and services.  Also included in our general and administrative expenses are our compensation costs for stock-based compensation arrangements with employees and directors which are being expensed over their respective vesting periods of the related option grants.  The majority of the increase in the general and administrative expenses is a result of an increase in directors’ fees of $0.232 million combined with an increase in salaries and benefits of $0.270 million and travel and hotel of $0.153 million.  These increases are consistent with the restructuring of our management team including the addition of a new executive officer combined with our stepping into new ventures in Israel and Colombia.  These increases were offset by a decrease in stock-based compensation costs from $0.779 million to $0.700 million for the same period in 2009.  Further offsets to the increase were a result of a charge of $0.264 million in 2009 for the warrant modification that was not incurred in the year ending December 31, 2010 as well as a recovery of $0.114 million as a result of an over accrual of estimated interest, penalties and related costs of $0.214 million in regularizing our respective tax and regulatory filings in India.

Consulting fees

Our consulting fees decreased to $0.652 million during the year ended December 31, 2010 from $0.823 million in the prior year.  Consulting fees include fees and expenses we incurred in employing various technical and corporate consultants who advised us on a variety of matters.  This change is mostly attributable to the decrease for stock-based compensation with non-employee consultants for the year ended December 31, 2010 being $0.017 million versus $0.140 million for the year ended December 31, 2009.  A portion of this decrease is also a result of consulting fees paid under our Technical Services Agreement which expired in August 2010 with a corporation wholly owned by Mr. Roy, whereby we expensed $0.209 million during the year ended December 31, 2010 versus $0.263 million during the year ended December 31, 2009.  The balance of the decrease is a result of the cancellation in August 2010 of the agreement to pay consulting fees to D.I. Investments Ltd., whereby we expensed $0.134 million during the year ended December 31, 2010 versus $0.213 million for the same period in 2009.

Professional fees

Professional fees decreased to $0.828 million during the year ended December 31, 2010 from $1.085 million during the year ended December 31, 2009.  Professional fees include those paid to our auditors for pre-approved audit, accounting and tax services and fees paid to our legal advisors primarily for services provided with regard to filing various periodic reports and other documents and reviewing our various oil and gas and other agreements.  This decrease is mostly a result of professional fees which were paid to various tax advisors to complete a review of our corporate structure with a goal to ensure tax compliance, strategy and efficiency across all jurisdictions in which we operate during incurred in the year ended December 31, 2009 not incurred in 2010.

Depletion and depreciation

Depletion and depreciation increased to $0.824 million ($83.72 per barrel) during the year ended December 31, 2010 from $0.353 million ($27.05 per barrel) during the year ended December 31, 2009.  This increase is mostly attributable to the substantial increase in the amortization base for the depletion calculation as a result of the transfer of the abandoned well costs from unproven to proven properties combined with the decrease in the proved reserves based on an updated reserve report dated January 1, 2011 by Chapman Petroleum Engineering Ltd.

Impairment of oil and gas properties

During the year 2010, we incurred asset impairment expenses of 13.789 million versus $nil during the year ended December 31, 2009.  In 2010, any impairment to exploration properties is transferred to our full cost pool which is subject to ceiling test limitations.  No impairment was recognized under our ceiling test in 2009.  Our asset impairment in 2010 consisted of $13.789 million as a result of assessing our Indian properties on an individual basis considering various factors, including land relinquishment and the absence of hydrocarbons in certain exploratory wells.  The exploration work programs have been completed on the four Cambay blocks which accounted for the majority of the impairment with the relinquishment of all lands where there is not a discovery, as well as the abandonment of twenty two wells in the fourth quarter of 2010. Further there was one well abandoned in one of the Rajasthan blocks.  Since the result of this assessment indicated impairment, the related costs incurred were charged to the statement of operations.

Capitalized overhead on oil and gas properties

We capitalize overhead costs directly related to our exploration activities in India.  During the year ended December 31, 2010, these capitalized overhead costs amounted to $0.599 million as compared to $1.098 million during the year ended December 31, 2009.  The decrease is mostly attributable to a decrease in the capitalized portion of stock-based compensation for our non-employee consultants directly related in our oil and gas exploration activities for the year ended December 31, 2010 of $0.252 million versus $0.662 million for the year ended December 31, 2009.  The treatment of capitalized overhead costs remained consistent with the prior year 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.

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Results of Operations for the Years ended December 31, 2009 and 2008

For the year ended December 31, 2009, we incurred a net loss of $4.424 million as compared to a net loss of $13.314 million for the year ended December 31, 2008.  The decrease in net loss was mostly attributable to realizing an asset impairment in 2008 of $10.098 million compared with no asset impairment in the year 2009.  This decrease was offset by an increase in our general and administrative expenses and consulting fees combined with a decline in our interest income.

Oil sales

All of our oil sales are derived from 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 and two in September 2009.  There are twelve additional wells which are drilled, tested and awaiting tie-in to the oil tank storage facilities.  Oil sales for the year ended December 31, 2009 were $0.662 million or $67.35 per barrel.  Oil sales are currently based on 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 associated natural gas was produced and flared off.  Commencing with the first quarter in 2010, the associated natural gas has been contained and sold.  We did not generate any oil sales during the year ended December 31, 2008.

Interest income

Interest income decreased to $0.300 million for the year ended December 31, 2009 as compared to $1.148 million for the same period in 2008.  This decrease was directly related to the decrease in US prime interest rate in 2009 as compared to 2008 as well a decrease in the amount of our invested cash balances.

Operating costs

Operating costs for the year ended December 31, 2009 were $0.099 million or $9.11 per barrel, as a result of our first production in the Tarapur 1 field which commenced in May 2009.  The operating costs include handling and processing charges, transportation costs, utilities, maintenance and tank rental charges and contain a fixed and variable portion.  We did not incur any operating costs during the year ended December 31, 2008.

General and administrative

Our general and administrative expenses increased to $2.987 million from $2.343 million.  These general and administrative expenses include costs related to the corporate head office including administrative salaries and services, directors’ fees, rent and office costs, insurance, bank guarantee fees, NYSE Amex listing and filing fees, investor relation services and transfer agent fees and services.  Also included in our general and administrative expenses are our compensation costs for stock-based compensation arrangements with employees and directors which were being expensed over their respective vesting periods of the related option grants.  These stock-based compensation costs increased to $0.779 million from $0.675 million for the same period in 2008.  The remaining majority of the increase in the general and administrative expenses was a result of an increase in directors’ fees of $0.145 million and interest, penalties and related costs of $0.214 million in regularizing our respective tax and regulatory filings in our various countries of operations

Consulting fees

Our consulting fees increased to $0.823 million during the year ended December 31, 2009 from $0.742 million in the prior year.  This change was mostly attributable to the increase for stock-based compensation with non-employee consultants for the year ended December 31, 2009 being $0.140 million versus a reversal of $0.048 million for the year ended December 31, 2008.  A portion of this increase was also a result of the accounting for the consulting fees paid under our Technical Services Agreement with a corporation wholly owned by Mr. Roy, whereby we expensed $0.263 million during the year ended December 31, 2009 versus $0.175 million during the year ended December 31, 2008.  The balance of the increase was a result of other fees and expenses we incurred in employing various technical and corporate consultants who advised us on a variety of matters.

Professional fees

Professional fees decreased slightly to $1.085 million during the year ended December 31, 2009 from $1.089 million during the year ended December 31, 2008.  Professional fees included those paid to our auditors for pre-approved audit, accounting and tax services and fees paid to our legal advisors primarily for services provided with regard to filing various periodic reports and other documents and reviewing our various oil and gas and other agreements.

Depletion and depreciation

Depletion and depreciation increased to $0.353 million during the year ended December 31, 2009 from $0.052 million during the year ended December 31, 2008.  As a result of our first production in the Tarapur 1 field we had depletion of $0.294 million or $27.05 per barrel for the year ended December 31, 2009 and depreciation of $0.059 million.  No depletion expense and depreciation of $0.052 million was recognized during the year ended December 31, 2008.

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Impairment of oil and gas properties

During 2009, we incurred no asset impairment expense versus $10.098 million during the year ended December 31, 2008.  In 2009, any impairment to exploration properties was transferred to our full cost pool which is subject to ceiling test limitations.  No impairment was recognized under our ceiling test in 2009.  Our asset impairment in 2008 consisted of $3.765 million as a result of our decision not to exercise our option on two exploration blocks in the Arab Republic of Egypt and cease our exploration activities in Oman and Yemen.  The balance from 2008 of $6.333 million was a result of assessing our Indian properties on an individual basis considering various factors, including land relinquishment and the absence of hydrocarbons in certain exploratory wells.  Since the result of this assessment indicated impairment, the related costs incurred were charged to the statement of operations.

Capitalized overhead on oil and gas properties

We capitalize overhead costs directly related to our exploration activities in India.  During the year ended December 31, 2009 these capitalized overhead costs amounted to $1.098 million as compared to $1.081 million during the year ended December 31, 2008.  The difference was mostly attributable to an increase in the capitalized portion of the stock-based compensation for our non-employee consultants directly related in our oil and gas exploration activities for the year ended December 31, 2009 of $0.662 million versus $0.478 million for the year ended December 31, 2008.  The treatment of capitalized overhead costs remained consistent with the prior year 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.

Reserve Report

As a result of the approval of the Tarapur 1 field development plan by the Management Committee in April 2009 and the completion of an independent reserve study dated January 1, 2011 by Chapman Petroleum Engineering Ltd. out of Calgary, Alberta, Canada, we claim reserves in the Tarapur 1 field as at December 31, 2010 as follows:

Summary of Oil and Gas Reserves as of December 31, 2010

Reserves Category	Oil (MBbls)	Natural Gas (MMcf)
PROVED
Developed	55	155
Undeveloped	--	--
TOTAL PROVED	55	155
Probable
Developed	53	143
Undeveloped	356	452
Possible
Developed	--	--
Undeveloped	--	--

Proved Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinable or probabilistic methods are used for the estimates.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

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 current operations are dependent upon the adequacy of our current assets to meet our current expenditure requirements and the accuracy of management’s estimates of those requirements.  Should those estimates be materially incorrect, our ability to continue as a going concern will be impaired.  Our consolidated financial statements for the year ended December 31, 2010 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.

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At December 31, 2010 our cash and cash equivalents were $7.751 million (December 31, 2009 - $16.295 million). The majority of this balance is being held in US funds, of which $7.592 million is held in term deposits earning interest based on the US prime rate which will contribute to covering a portion of our administrative costs and overhead throughout 2011. We have working capital of approximately $3.957 million available for the Company’s future operations.  In addition, we have $5.018 million in restricted deposits pledged as security against the minimum work programs for our exploration blocks which will be released upon completion of those minimum work programs.

We expect to incur expenditures to further our exploration programs.  Our existing cash balance and any cash flow from operating activities is not sufficient to satisfy our current obligations and meet our exploration commitments of $27.753 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 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 and our lack of any material oil and natural gas reserves, 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, appraisal and development expenditures.  We believe that we will be able to raise additional capital which combined with 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 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.  Our 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.

Years ended December 31, 2010 and 2009

During the year ended December 31, 2010 our overall position in cash and cash equivalents decreased by $8.544 million, as compared to a net decrease in the comparable period of 2009 of $9.138 million.  These cash movements were attributable to the following activities:

Our net cash used in operating activities during the year ended December 31, 2010 was $4.067 million as compared to $2.119 million for the year ended December 31, 2009.  This increase is mostly attributable to and consistent with the decrease in our current liabilities at December 31, 2010 to $8.544 million from $10.054 million at December 31, 2009.  The remainder of the decrease is comprised of the increase in the cash expenditures combined with a decline in our revenue and other income from $0.961 for the year ended December 31, 2009 to $0.843 million for the year ended December 31, 2010.

Cash used in investing activities during the year ended December 31, 2010 was $12.463 million as compared to $7.019 million during the year ended December 31, 2009.  Funds of $9.040 million were used for exploration activities as compared to $11.222 million in 2009.  This decrease is attributable and consistent with the decrease in accounts payable from $8.734 million at December 31, 2009 to $6.834 million at December 31, 2010 offset by an increase in accrued liabilities from $1.197 million to $1.683 million respectively.  This combined with our increase in accounts receivable which is mostly attributable to an unexpended cash call receivable of $1.961 for the seismic acquisition on our Samuel exploration license at December 31, 2010.

Cash provided by financing activities for the year ended December 31, 2010 was $7.986 as compared to $nil during the year ended December 31, 2009.  During the year ended December 31, 2010 9,941,177 shares of common stock were issued pursuant to two private placement financings for gross proceeds of $8.450 million less share issuance costs of $0.464 million.  There were no private placement sales of our securities during 2009.

Years ended December 31, 2009 and 2008

During the year ended December 31, 2009 our overall position in cash and cash equivalents decreased by $9.138 million, as compared to a net decrease in the comparable period of 2008 of $22.702 million.  These cash movements were attributable to the following activities:

Our net cash used in operating activities during the year ended December 31, 2009 was $2.119 million as compared to $3.099 million for the year ended December 31, 2008.  This decrease is attributable to and consistent with the increase in our current liabilities at December 31, 2009 to $10.054 million from $9.211 million at December 31, 2008.

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Cash used in investing activities during the year ended December 31, 2009 was $7.019 million as compared to $20.263 million during the year ended December 31, 2008.  Funds of $11.222 million were used for exploration activities as compared to $16.074 million in 2008.  This decrease is consistent with the decrease in exploration activity in the year 2009 versus the year 2008.  Consequently, bank guarantees related to exploration activity also declined such that in the year ended December 31, 2009 funds were provided of $3.875 million versus an outlay for such instruments of $7.415 million in the year ended December 31, 2008.  These bank guarantees have been provided and serve as guarantees for the performance of our minimum work programs and are in the form of irrevocable letters of credit which are secured by our term deposits in the same amount.

Cash provided by financing activities for the year ended December 31, 2009 was $Nil as compared to cash provided by financing activities of $0.660 million during the year ended December 31, 2008.  During the year ended December 31, 2009, no shares were issued versus the issuance of 600,000 shares of common stock on the exercise of options in the prior year for gross proceeds of $0.660 million.  There were no private placement sales of our securities during 2009 or 2008.

Capital Resources

We expect our exploration and development activities pursuant to our PSCs in India will continue through 2011 in accordance with the terms of those agreements.  During the year 2011 and up to March 31, 2012, based on the current budgets in India, we anticipate drilling seven exploratory wells; two core wells; acquiring, processing and interpreting 2,480 line kilometers of 2D seismic data; and acquiring, processing and interpreting 350 square kilometers of 3D seismic data as well as processing and interpreting an additional 400 square kilometers of 3D seismic data.  We further expect to tie-in additional oil wells in Tarapur along with the construction of a gas pipeline for the Tarapur G gas discovery and continue with the construction of the gas gathering and production facilities together with further development drilling on the KG Offshore Block in which we have a carried interest. Additional expenditures may be incurred in connection with additional exploratory, appraisal and development wells we may participate in.  Also, if the Government of India approves the increase to our participating interest in the KG Onshore Block to 20%, our obligations to fund 3D seismic acquisition and exploratory drilling on the block will increase.

We expect our exploration activities pursuant to our licenses in Israel will continue through 2011 in accordance with the terms of those agreements.  During the year 2011, we expect to complete the acquisition, processing and interpretation of 43 square kilometers of 3D seismic data in our Samuel license as well as to complete the processing and interpretation of 1,360 square kilometers of 3D seismic data covering our Sara and Myra licenses and also commence drilling our first deepwater exploration well before the end of the year.

In addition, we may during 2011 seek to participate in joint ventures bidding for the acquisition of oil and gas interests in India and other countries.  As of March 30, 2011 we have no specific plans regarding such activities and have not entered into any binding agreements with respect to such activities.  We expect that our interest in any such ventures would involve a minority participating interest in the venture.  In addition, although there are no present plans to do so, 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.

As of March 30, 2011 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 will 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 when 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 such capital will be raised, the price per share or possible number of shares involved or the terms of any agreements to raise capital under other arrangements.

During the first quarter of 2010, we hired a new Senior Executive.  We do not expect to have any further significant change in 2011 in our number of employees.

Tabular Disclosure of Contractual Obligations

The following table sets forth our contractual obligations by type of agreement and amounts due during the year ended December 31, 2010 and each succeeding year thereafter.  Where the amounts of payments are 0.0, this indicates we have no material obligations under such types of agreements.

	Payments due by period ($ in millions)
Contractual Obligation	Total	Less than 1 year	1-3 years	3-5 years	More than 5 years
Operating lease	0.4	0.2	0.2	0.0	0.0
Asset retirement obligation	0.7	0.0	0.0	0.0	0.7
Financial commitments under PSCs	27.8	11.1	16.7	0.0	0.0
Total	28.9	11.3	16.9	0.0	0.7

Under the production sharing and other contracts, we are obligated to pay for our proportionate share of the exploration expenses in fulfilling the minimum work programs on each of our exploration blocks and licenses.  Inasmuch as exploration and drilling activities can involve unanticipated expenses and cost overruns, there can be no assurance that these management estimates will prove to be accurate.

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Financial commitments under the production sharing and other contracts are outlined below and include only the commitments for the current exploration Phase that we are conducting.  Further, as we have not yet received Government of India consent to increasing our participating interest in the KG Onshore Block from 10% to 20%, our financial commitment shown in the table above includes only our 10% participating interest.

The KG Offshore Block

2011 Potential Expenditures

We anticipate the estimated total capital expenditures to be incurred by GSPC, the Operator of the KG Offshore Block during the twelve month period from April 1, 2011 to March 31, 2012 pursuant to the budget submitted to the  Management Committee in December 2010 for the development drilling of two new wells in the Deen Dayal West along with part of the construction of the wellhead platform, the gas gathering pipeline and the onshore gas terminal will be approximately $747.95 million (our 10% share being $74.795 million of which 50% is for the account of Roy Group (Mauritius) Inc.).

Certain exploration costs related to the KG Offshore Block are incurred by us and on our behalf in providing our services under the Carried Interest Agreement and are therefore not reimbursable under the Carried Interest Agreement.

Financial Commitment

The amount attributable to us for the twelve month period from April 1, 2011 to March 31, 2012 under the Carried Interest Agreement is approximately $74.795 million, of which 50% is for the account of Roy Group (Mauritius) Inc.  Under the terms of the Carried Interest Agreement, GeoGlobal and Roy Group (Mauritius) Inc. are carried by GSPC for 100% of our share of any costs during the exploration phase on the KG Offshore Block prior to the start date of initial commercial production.

As at December 31, 2010 GSPC has expended on exploration activities approximately $189.0 million attributable to us under the Carried Interest Agreement as compared to $150.0 million at December 31, 2009.  Of this amount, 50% is for the account of Roy Group (Mauritius) Inc.

We will not realize cash flow from the KG Offshore Block until such time as the expenditures attributed to us, including those expenditures made for the account of Roy Group (Mauritius) Inc. under the Carried Interest Agreement have been recovered by GSPC from future production revenue.  Under the terms of the Carried Interest Agreement, all of our proportionate share of capital costs for exploration and development activities must be repaid to GSPC without interest over the projected production life or ten years, whichever is less.

KG Onshore Block

2011 Potential Expenditures

We anticipate the estimated total capital expenditures we will contribute to the exploration activities on this block during 2011 based on a 10% participating interest will be $1.804 million ($3.608 million based on a 20% participating interest).  These expenditures include completing the 3D acquisition, processing and interpretation along with the required gravity and magnetic and geochemical surveys required under the Phase I minimum work program and the drilling of one exploration well in 2011.

Financial Commitments

We will be required to fund our proportionate share of the costs incurred in the KG Onshore exploration activities estimated to be approximately $9.309 million over the remaining three years of the first phase of the minimum work commitment with respect to a 10% participating interest in the block and approximately $18.618 million with respect to a 20% participating interest in the block.  These expenditures entail performing the required surveys and studies for Phase I, being the acquisition of a 400 square kilometer 3D seismic program and the interpretation and processing thereof and the drilling of twelve exploratory wells.  It is expected that costs incurred will be $1.804, $2.274, and $5.231 million over each of the years 2011, 2012 and 2013 respectively for a 10% participating interest and $3.608, $4.548, and $10.462 million for a 20% participating interest.

Mehsana Block

2011 Potential Expenditures

At present, we have not estimated any capital expenditures on this block during the year 2011 based on our 10% participating interest.

Financial Commitments

All financial commitments in accordance with the PSC have been met for Phase I.  We have elected not to move into Phase II on the Mehsana block.

Sanand/Miroli Block

2011 Potential Expenditures

At present, we have not estimated any capital expenditures on this block during 2011 based on our 10% participating interest.

Financial Commitments

We have completed the minimum work program for all three exploration phases and as such all financial commitments have been met under the terms of the PSC.

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Ankleshwar Block

2011 Potential Expenditures

At present, we have not estimated any capital expenditures on this block during 2011 based on our 10% participating interest.

Financial Commitments

We have completed the minimum work program for all three exploration phases and as such all financial commitments have been met under the terms of the PSC.

Tarapur Block

2011 Potential Expenditures

We anticipate the estimated total capital expenditures which we may contribute to the development activities on this block during 2011 will be funded by oil sales.  These expenditures may include the tie in of the Tarapur 6 wells upon approval of a field development plan, or the building of a gas pipeline for the Tarapur G upon approval of a field development plan and possibly the drilling of two appraisal wells to further evaluate the Tarapur South discovery.

If the consortium succeeds in having the additional eighteen month extension of the exploration phase granted by the Government of India, then we may participate in additional capital expenditures of approximately $1.6 million for exploration activities during 2011.  This would include our 18% participating interest in a 330 square kilometer 3D seismic acquisition program and the 30% cash payment as agreed in non-refundable pre-estimated damages based on the cost of the additional work program.

Financial Commitments

We have completed the minimum work programs for all three exploration phases and as such, all financial commitments have been met under the terms of the PSC.

DS 03 Block

2011 Potential Expenditures

We anticipate that the estimated total capital expenditures we will be required to contribute to the exploration activities on these blocks during 2011 based on our 100% participating interest will be $1.456 million.  These expenditures will include the acquisition, processing and interpretation of 500 line kilometers of 2D seismic data.

Financial Commitments

We will be required to fund 100% of the costs incurred in the DS03 Block exploration activities estimated to be approximately $4.053 million over the remaining two years to complete the first and second phase of the minimum work commitments.  These expenditures entail completing the acquisition, processing and interpretation of 500 line kilometers of 2D seismic data, completion of a 12,000 line kilometer aeromagnetic survey and the drilling of one exploratory well to the depth of 1,500 meters.  It is expected that these total costs will be split as to $1.456 and $2.597 million over each of the next two years.

DS 04 Block

2011 Potential Expenditures

We anticipate the estimated total capital expenditures we will be required to contribute to the exploration activities on these blocks during 2011 based on our 100% participating interest will be $2.028 million.  These expenditures will include the acquisition, processing and interpretation of 500 line kilometers of 2D seismic data.

Financial Commitments

The remaining work to be completed to fulfil the Phase I commitment is to complete the drilling of ten core holes to a depth of 500 meters each.  Our 100% participating interest share of this commitment is $0.501 million which is expected to be completed in 2012.

RJ Block 20

2011 Potential Expenditures

We anticipate the estimated total capital expenditures we will contribute to the exploration activities on this block during 2011 based on our 25% participating interest will be $3.287 million.  These expenditures include the acquisition processing and interpretation of 820 line kilometers of 2D seismic data, the drilling of four exploratory wells and the gravity and magnetic and geochemical surveys required under the Phase I minimum work program.

Financial Commitments

We anticipate the total expenditures we will be required to fund for the current year to be approximately $3.287 million as outlined above in our 2011 Potential Expenditures.  We further expect $2.365 and $1.700 million to be expended in each of 2012 and 2013 to complete the minimum work program of drilling a total of twelve exploratory wells based on our 25% participating interest.

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RJ Block 21

2011 Potential Expenditures

We anticipate the estimated total capital expenditures we will contribute to the exploration activities on this block during 2011 based on our 25% participating interest will be $2.477 million.  These expenditures include the acquisition processing and interpretation of 660 line kilometers of 2D seismic data, the drilling of two exploratory wells and the gravity and magnetic and geochemical surveys required under the Phase I minimum work program.

Financial Commitments

We anticipate the total expenditures we will be required to fund for the current year to be approximately $2.477 million as outlined above in our 2011 Potential Expenditures.  We expect $1.552 million and $0.480 million to be expended in each of 2012 and 2013, respectively to complete the minimum work program which entails the drilling of an additional six exploratory wells based on our 25% participating interest.

Sara and Myra

2011 Potential Expenditures

We anticipate the estimated total capital expenditure we will contribute to the exploration activities on these licenses during 2011 based on our 5% participating interest will be $2.233 million.  These expenditures include the processing and interpretation of 1,360 square kilometers of 3D seismic data covering both the licenses along with the ordering of the equipment and services including contracting a rig to commence drilling before the end of the year 2011.

Financial Commitments

We have no financial commitments for these expenditures.

Samuel

2011 Potential Expenditures

We anticipate the estimated total capital expenditure we will contribute to exploration activities on this license during 2011 based on our effective 45% participating interest will be $2.072 million.  These expenditures include the acquisition, processing and interpretation of 43 square kilometers of 3-D seismic data.

Financial Commitments

We have no financial commitments for these expenditures.

Critical Accounting Policies and Estimates

This discussion of financial condition and results of operations is based upon the information reported in our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at thedate of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates. Our significant accounting policies are detailed in Note 3 to our consolidated financial statements. We have outlined below certain accounting policies that are of particular importance to the presentation of our financial position and results of operations and require the application of significant judgment or estimates by our management.

Use of estimates

The preparation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results may differ from these estimated amounts due to factors such as fluctuations in interest rates, currency exchange rates, inflation levels and commodity prices, changes in economic conditions and legislative and regulatory changes.

Significant estimates with regard to the consolidated financial statements include the estimated carrying value of unproved properties, the estimated cost and timing related to asset retirement obligations, stock-based compensation and contingencies.

Oil and Natural Gas Properties

We use the full cost method of accounting for our oil and natural gas properties.  Separate cost centers are maintained for each country in which we incur costs.  Under this method, we capitalize all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities.  Costs associated with production and general corporate activities, however, are expensed in the period incurred.  To the extent that support equipment is used in oil and gas activities, the related depreciation is capitalized.  Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such disposition would alter the depletion and depreciation rate by 20% or more.

Capitalized costs of development oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proven reserves plus the lower of cost or fair value of unproven properties.  Should capitalized costs exceed this ceiling, an impairment is recognized.

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The present value of estimated future net cash flows is computed by applying the average first-day-of-the-month prices during the previous twelve month period of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year-end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Following the discovery of reserves and the commencement of production, we compute depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities.

We assess all items classified as unproved property on a quarterly basis for possible impairment or reduction in value.  We assess properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: land relinquishment; intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment, the related exploration costs incurred are transferred to the full cost pool and are then subject to depletion and the ceiling limitations on development oil and natural gas expenditures.

Asset Retirement Obligation

The fair values of estimated asset retirement obligations are recorded as liabilities when incurred and the associated cost is capitalized as part of the cost of the related asset.  The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.  The liabilities are accreted as operating expense for the change in their time value.  The initial capitalized costs are included in depletion expense in a manner consistent with the related assets.  Changes in the estimated obligation resulting from revisions to the estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and related asset.  Actual expenditures incurred are charged against the accumulated obligation.

Stock Based Compensation

Compensation cost for all share based payments are based on the fair value estimated and is recognized on a straight line basis over the vesting period for the award.  We account for transactions in which we issue equity instruments to acquire goods or services from non employees based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.

The fair value of share-based payments is capitalized or expensed, with a corresponding increase to additional paid-in capital for the equity classified awards, or the share-based payment liability for the liability classified awards.  Upon exercise of stock options, the consideration paid upon exercise is recorded as additional value of common stock in additional paid-in capital.

Item 7A.                 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the potential loss arising from changes in market rates and prices.  We are exposed to the impact of market fluctuations associated with the following:

Interest Rate Risk

We consider our exposure to interest rate risk to be immaterial.  Interest rate exposures relate entirely to our investment portfolio, as we do not have short-term or long-term debt.  Our investment objectives are focused on preservation of principal and liquidity.  We manage our exposure to market risks by limiting investments to high quality bank issuers at overnight rates, or government securities of the United States or Canadian federal governments such as Guaranteed Investment Certificates or Treasury Bills.  We do not hold any of these investments for trading purposes.  We do not hold equity investments.  We do not expect any material loss from cash equivalents and therefore we believe our interest rate exposure on invested funds is not material.

Foreign Currency Exchange Risk

Substantially, all of our cash and cash equivalents are held in U.S. dollars or U.S. dollar denominated securities.  Certain of our expenses are fixed or denominated by foreign currencies including the Canadian dollar and the Indian Rupees.  We are exposed to market risks associated with fluctuations in foreign currency exchange rates related to our transactions denominated in currencies other than the U.S. dollar.

At December 31, 2010, we had not entered into any market risk sensitive instruments relating to our foreign currency exchange risk.

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Commodity Price Risk

Oil and natural gas prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global demand for petroleum products, international supply of oil and gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions, the price and availability of alternative fuels, overall economic conditions, both international and domestic, and possible international disruptions.  We cannot predict future oil and gas prices with any degree of certainty.  Sustained weakness in oil and gas prices may adversely affect our ability to obtain capital to fund our activities and could in the future require a reduction in the carrying value of our oil and gas properties.  Similarly, an improvement in oil and gas prices can have a favourable impact on our financial condition, results of operations and capital resources.

At December 31, 2010, we had not entered into any market risk sensitive instruments as such term is defined in Item 305 of Regulation S-K, relating to oil and natural gas.

Trading Risks

We have no market risk sensitive instruments held for trading purposes.

Item 8.                 Financial Statements and Supplementary Data

Our Financial Statements are included in a separate section of this report.  See Page FS 1.

Item 9.                 Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

There were no disagreements with accountants on accounting and financial disclosure.

Item 9A.                 Controls and Procedures

Disclosure Controls and Procedures

In participation with our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2010.  Disclosure controls and procedures are defined under SEC rules as controls and other procedures that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based on our evaluation of our disclosure controls and procedures, the Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2010, our disclosure controls and procedures were effective.

Management’s Report on Internal Controls Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934.  A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In making our assessment of the effectiveness of the internal controls over financial reporting, management, including the Chief Executive Officer and Chief Financial Officer, used the criteria set forth in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

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A material weakness (as defined in SEC Rule 12b-2) is a control deficiency, or combination of control deficiencies, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

Management has assessed and concluded that its internal control over financial reporting was effective as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by COSO.

KPMG LLP, an independent registered public accounting firm that audited the consolidated financial statements, has performed an audit of internal control over financial reporting.  Their report is included in this Annual Report on Form 10-K under Item 8, herein.

Remediation of Material Weaknesses in Internal Control Over Financial Reporting

In 2009, we did not maintain an effective control environment.  Specifically, we did not formally communicate and emphasize controls and enforce corporate strategy and objectives. We did not formally define roles and responsibilities for employees and management or have a formal process to monitor performance of employees and management against such objectives.  In response to this material weakness, management implemented the following corrective actions:

• During the first quarter of 2010, a new senior executive officer was hired.  One of the responsibilities of this senior executive was to assist with strengthening our control environment.

• During the third quarter of 2010, we strengthened our internal controls environment by restructuring our executive management team.  The new senior executive hired during the first quarter of 2010 was appointed as the new President and Chief Executive Officer.  The former Chief Financial Officer assumed new responsibilities as Vice President of Finance and the former Corporate Controller was promoted as our new Chief Financial Officer.

• Also in the third quarter of 2010, we formally defined roles and responsibilities for our newly structured executive management team.

• During the fourth quarter of 2010, the President and Chief Executive Officer conducted performance reviews with our employees and executive management team.

As a result of the corrective actions discussed above and the testing of these new controls, we have concluded that the material weakness in our internal control over financial reporting relating to an effective control environment has been remediated in the fourth quarter of 2010.

Material Changes in Internal Controls over Financial Reporting

There were no other changes in our internal controls over financial reporting during the fourth quarter of 2010, other than described above that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

Item 9B.                Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Our Directors and Executive Officers as at December 31, 2010 and their ages and employment histories are as follows:

Name	Age	Employment History
Paul B. Miller	37	Mr. Miller joined our Company in March 2010 and was elected a Director on September 15, 2010.  With the resignation of Mr. Roy as President and Chief Executive Officer effective August 17, 2010, Mr. Miller assumed on that date, the position of President and Chief Executive Officer.  Mr. Miller is responsible for presenting the company to shareholders and investors as well as performing day to day operations in conjunction with current management.  Mr. Miller is a professional engineer licenced in Ontario and Alberta.  He has a depth of experience working in the oil and gas industry all over the world.  Originally from the East Coast of Canada, Mr. Miller has lived and worked throughout Canada having started his career in Alberta in 1997 working for Talisman Energy from 1997 to 2000 before moving on to Matrikon Inc., a global engineering consulting company, where he was employed in various management capacities from 2000 to 2010.  During his ten year tenure with Matrikon, he headed up business units in Australia, Eastern North America, and the Middle East prior to returning to Alberta.  Mr. Miller holds a Bachelor of Science degree in Chemical Engineering from the University of Alberta and in 2009 graduated from the Kellogg-Schulich Executive MBA program.

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Jean Paul Roy	54	Mr. Roy was elected a Director, President and Chief Executive Officer on August 29, 2003.  Effective August 17, 2010 Mr. Roy resigned his position of President and Chief Executive Officer.  Before joining GeoGlobal, Mr. Roy had been consulting in the oil and gas industry through his private company, GeoGlobal Technologies Inc. which he owned 100%.  Mr. Roy has in excess of twenty-eight years of geological and geophysical experience in basins worldwide as he has worked on projects throughout India, North and South America, Europe, the Middle East, the former Soviet Union and South East Asia.  His specialties include modern seismic data acquisition and processing techniques, and integrated geological and geophysical data interpretation.  Since 1981 he has held geophysical positions with Niko Resources Ltd., Gujarat State Petroleum Corporation, Reliance Industries, Cubacan Exploration Inc., PetroCanada, GEDCO, Eurocan USA and British Petroleum.  Mr. Roy graduated from St. Mary’s University of Halifax, Nova Scotia in 1982 with a B.Sc. in Geology and has been certified as a Professional Geophysicist.
Allan J. Kent	57	Mr. Kent was elected a Director, Executive Vice President and Chief Financial Officer of our company on August 29, 2003.  Mr. Kent did not stand for re-election to the Board of Directors at the September 15, 2010 Annual Meeting of Shareholders.  Effective August 17, 2010, Mr. Kent assumed new responsibilities as Vice President of Finance.  Mr. Kent has in excess of 28 years experience in the area of oil and gas exploration finance and has, since 1987, held a number of senior management positions and directorships with Cubacan Exploration Inc., Endeavour Resources Inc. and MacDonald Oil Exploration Ltd., all publicly listed companies.  Prior thereto, beginning in 1980, he was a consultant in various capacities to a number of companies in the oil and gas industry.  He received his Bachelor of Mathematics degree in 1977 from the University of Waterloo, Ontario.
Brent J. Peters	38	Mr. Peters was elected a Director of our company on February 25, 2002.  Mr. Peters has been Vice President of Finance and Treasurer of Northfield Capital Corporation, a publicly traded investment company acquiring shares in public and private corporations since 1997.  Mr. Peters has a Bachelor of Business Administration degree, specializing in accounting.
Peter R. Smith	63	Mr. Smith was elected a Director of our company on January 8, 2004.  Mr. Smith currently sits on the Board of Directors of Brampton Brick Limited.  Mr. Smith was elected Chairman of the Board of the Greater Toronto Transportation Authority (GO Transit) in March 2004, and a director of Tarion Warranty Corporation (a Canadian new home warranty company) in April 2004.  Since 1989, Mr. Smith has been President and co-owner of Andrin Limited, a large developer/builder of housing in Canada.  Mr. Smith held the position of Chairman of the Board of Directors, Canada Mortgage and Housing Corporation (CMHC) from September 1995 to September 2003.  On February 14, 2001, the Governor General of Canada announced the appointment of Mr. Smith as a Member of the Order of Canada, effective November 15, 2000.  Mr. Smith holds a Masters Degree in Political Science (Public Policy) from the State University of New York, and an Honours B.A. History and Political Science, Dean’s Honour List, McMaster University, Ontario.
Michael J. Hudson	64	Mr. Hudson was elected a Director of our company on May 17, 2004.  Mr. Hudson is a retired partner with the accounting firm Grant Thornton LLP.  Mr. Hudson was with Grant Thornton for 20 years and with his experience in the oil and gas industry he was responsible for Assurance services and providing advice to private, not-for-profit and public company clients listed on Canadian and US exchanges.  Mr. Hudson spent two years in London, England assisting the Institute of Chartered Accountants in England and Wales with the start up of a consulting service to members on best practices for the management of their firms including ethics and governance issues.  Upon returning to Canada he went on secondment for 18 months with the Auditor General of Canada to learn and apply the disciplines of “value for money” auditing.  He was co-director of the comprehensive (value for money) audit of Statistics Canada reporting in the 1983 Auditor General’s Report.

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David Conklin	46	Mr. Conklin was elected a Director of our company on May 11, 2009.  Mr. Conklin currently serves as counsel at Goodmans LLP, a law firm in Toronto, Ontario, Canada and specializes in commercial litigation with an emphasis on corporate governance and business valuation.  Before joining Goodmans LLP in 2007, Mr. Conklin practised for one year with Bernstein Litowitz Berger & Grossman LLP, a securities and class action firm in New York.  Prior thereto he was a partner and senior litigator at Lerners LLP, a leading Toronto litigation law firm.  Mr. Conklin has extensive experience appearing before all levels of civil courts in Ontario litigating commercial disputes involving shareholder and partnership disputes, oppression claims, breach of confidentiality and other fiduciary duties, secured and unsecured creditor claims, professional negligence claims and other related business law issues.  He represents shareholders, boards of directors and entrepreneurs of both private and public companies.  Mr. Conklin is currently an Executive in Residence at the Schulich School of Business, York University where he teaches courses in the MBA and EMBA programs on Corporate Governance Mergers and Acquisitions.  Throughout his career, Mr. Conklin has taught a variety of legal and business courses including trial advocacy at the University Of Toronto Faculty Of Law and the Advocates’ Society.  Mr. Conklin received his LL.M from Columbia University in New York City focusing on capital markets, corporate finance and governance issues and was admitted to the Law Society of Upper Canada in 1993 and to the New York State Bar in 2007.
Anoop Poddar	37	Mr. Poddar was elected a Director of our company on September 15, 2010.  Mr. Poddar is currently a Partner and Investment Manager in the Aberdeen, UK office of Energy Ventures where he has been employed since 2008.  Energy Ventures is a venture capital firm focusing on equity investment into technology-focused companies in the oil and gas sector.  Mr. Poddar has extensive experience commencing in 1994 in the oil and gas industry in such capacities as a petroleum engineer, an investment banker and as vice president of corporate finance.  Originally from India, Mr. Poddar was a Drilling Engineer for Essar Oil in India for two years from 1994 to 1996, worked for five years internationally from 1997 to 2002 with Schlumberger as a Project Co-ordinator/Drilling Engineer and was the Associate/VP of Corporate Finance with Simmons and Company in the UK from 2004 to 2007.  Mr. Poddar holds a Bachelor of Engineering degree in Petroleum Engineering from the Indian School of Mines in Dhanbad, India, has a Master of Science degree in offshore engineering from the Robert Gordon University in Aberdeen, UK and has Masters in Business Administration degree from the Harvard Business School in Boston, USA.
Sunil S. Karkera	37	Mr. Karkera joined our company in November 2009 and held the position of Corporate Controller until August 17, 2010 when Mr. Karkera was promoted to serve as the Chief Financial Officer.  Mr. Karkera is a Chartered Accountant from Canada and India and a Certified Public Accountant (Colorado) from USA with over 19 years of global experience with international accounting, advisory and consulting firms and with multi industry business groups, including the oil and gas industry.  Mr. Karkera moved to Canada from Dubai, UAE in 2005 and worked with Ernst & Young LLP, an international accounting firm from February 2005 until he joined GeoGlobal in 2009.  Prior thereto, Mr. Karkera worked with Pannell Kerr Forster, an international accounting firm, in Dubai, UAE from November 2000 to November 2004.  Mr. Karkera worked with RMS & Co (now PricewaterhouseCoopers), in Mumbai, India from April 1996 to October 2000.   Mr. Karkera started his career in the accounting field with a variety of positions with growth-orientated companies active in India.

At our Annual Meeting of Stockholders held on September 15, 2010, Mr. Miller, Mr. Roy, Mr. Peters, Mr. Smith, Mr. Hudson, Mr. Conklin and Mr. Poddar were elected to serve as Directors of our company until our annual meeting of stockholders in 2011 and the election and qualification of their successors.  At this 2010 Annual Meeting, all members of the Board of Directors were in attendance, with the exception of Mr. Anoop Poddar, who was a nominee for election.

On February 2, 2010, we announced that Mr. Subir Raha, a then Director of our company, had passed away.

Our Board of Directors has determined that Messrs. Peters, Smith, Hudson, Conklin and Poddar are “independent directors” under the listing standards of the NYSE Amex.

Our Board of Directors had fourteen meetings during the year ended December 31, 2010.  Of these fourteen meetings, Mr. Roy was unable to attend two of the meetings and each of Messrs. Poddar, Smith, Peters and Kent were unable to attend one meeting, all of which were  held by conference call.

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Director and Officer Securities Reports

The Federal securities laws require our Directors and Executive Officers, and persons who own more than ten percent (10%) of a registered class of our equity securities to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of any of our equity securities.  Copies of such reports are required to be furnished to us.  To our knowledge, based solely on a review of the copies of such reports and other information furnished to us, all persons subject to these reporting requirements filed the required reports on a timely basis with respect to the year ended December 31, 2010.

Audit Committee and Audit Committee Financial Expert

Our Board of Directors has appointed an Audit Committee consisting of Messrs. Hudson, who is the Chairman, Mr. Peters and Mr. Conklin, each of whom have been determined to be an “independent director” under the listing standards of the NYSE Amex.  Under our Audit Committee Charter, adopted as amended on March 6, 2005, our Audit Committee’s responsibilities include, among other responsibilities:

·   the appointment, compensation and oversight of the work performed by our independent auditor,

·   the adoption and assurance of compliance with a pre-approval policy with respect to services provided by the independent auditor,

·   at least annually to obtain and review a report by our independent auditor as to relationships between the independent auditor and our company so as to assure the independence of the independent auditor,

·   review the annual audited and quarterly financial statements with our management and the independent auditor, and

·   discuss with the independent auditor their required disclosure relating to the conduct of the audit.

Our Board of Directors has determined that Mr. Michael J. Hudson has the attributes of an Audit Committee Financial Expert and as such, serves as the Audit Committee Financial Expert on our Audit Committee.

Our Audit Committee had four meetings during the year ended December 31, 2010, of which all were held by conference telephone call.  All members of the Audit Committee attended all four meetings with the exception of Mr. Peters who was unavailable for one meeting.

On March 28, 2011, our Audit Committee discussed our audited consolidated financial statements with management and discussed with KPMG, our independent registered public accounting firm, the matters required to be discussed by Statement of Auditing Standards No. 61 and received the written disclosures and the letter from KPMG as required by Independence Standards Board Standard No. 1 which confirmed KPMG’s independence as auditor.  Based on that review and those discussions, our Audit Committee recommended that our audited consolidated financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2010 for filing with the Securities and Exchange Commission.

Our Audit Committee Charter is available in the “Corporate Governance” section of our website at www.geoglobal.com.

Compensation Committee

Our Compensation Committee consists of Mr. Hudson whom is the Chairman and Mr. Peters, both of whom have been determined to be an “independent” director.  Our Compensation Committee, which has adopted a charter, among other things, exercises general responsibility regarding overall employee and executive compensation.  Our Compensation Committee sets the annual salary, bonus and other benefits of the President and the Chief Executive Officer and approves compensation for all our other executive officers, consultants and employees after considering the recommendations of our President and Chief Executive Officer.  Although Committee meetings are held in executive session, without management’s presence, the Committee (and from time to time individual members of the Committee) may meet with senior officers of our company to discuss objectives, explain the rationale for certain objectives or milestones, and to assure that it has management’s input in assessing the consequences of decisions made in the Committee meetings, for instance, the impact that its decisions may have on our financial statements.  The Committee’s interactions with management seek to achieve a balance between receiving management’s opinion but still ensuring that management is not, in effect, establishing the terms and parameters for its own compensation.  In certain instances, where management has proposed objectives that are more aggressive than those proposed by the Committee, the Committee may elect to utilize management’s milestones rather than its own.

Our Compensation Committee had no meetings during the year ended December 31, 2010, however, two resolutions were circulated to the members of the Compensation Committee and both resolutions were signed by all members.

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Nominating Committee

Our Nominating Committee consists of Mr. Smith, who is the Chairman, Mr. Peters and Mr. Hudson, each of whom have been determined to be an “independent director” under the listing standards of the NYSE/Amex.  Our Nominating Committee, among other things, exercises general responsibility regarding the identification of individuals qualified to become Board members and recommend that the Board select the director nominees for the next annual meeting of stockholders.  Our Board of Directors has adopted a charter for the nominating committee.

The Nominating Committee had no meetings during the year ended December 31, 2010 however one resolution was circulated to the members of the Nominating Committee and was signed by all members.

Our Nominating Committee will seek out nominees for new directors as vacancies become available using the following criteria: a majority of the directors must be independent, as determined by the Board under applicable rules; nominees shall possess expertise in general business matters and in such other areas as are relevant to Committees on which they are expected to serve (such as financial expertise, for Directors expected to serve as Audit Committee members); and nominees shall be individuals with the background, character, skills and expertise such that they will meaningfully contribute to our success and our operations.

Our Nominating Committee Charter is available in the “Corporate Governance” section of our website at www.geoglobal.com.

Reserve Committee

Our Reserve Committee consists of Mr. Miller who is the Chairman, and Messrs. Karkera, Leggett, Hudson, Mohapatra, Choudhary and Sinha.  Our Reserve Committee, among other things, will assist the Board with duties and responsibilities in evaluating and reporting the Company’s oil and gas reserves as well as work in consultation with the Company’s senior reserves engineering personnel to approve the appointment of, and any proposed changes in the independent engineering consultants retained to assist the Company in the annual review of reserves.  Mr. Miller possesses a professional engineer designation and has experience in energy company reserve evaluations.

Our Reserve Committee had one meeting during the year ended December 31, 2010 which was held by conference telephone call.

Code of Ethics

We have adopted a Code of Ethics that applies to our principal executive officer and principal financial and accounting officer.  A copy of our Code of Ethics was attached as Exhibit 14 to the Annual Report on Form 10-K for the year ended December 31, 2009.

Our Code of Ethics Charter is available in the “Corporate Governance” section of our website at www.geoglobal.com.

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Item 11.                 Executive Compensation

The following table sets forth the compensation of our principal executive officer and all of our other executive officers for the two fiscal years ended December 31, 2010 who received total compensation exceeding $100,000 for the year ended December 31, 2010 and who served in such capacities at December 31, 2010.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)	Option Awards ($) (1)	Non-Equity Incentive Plan Compen- sation ($)	Nonqualified Deferred Compen- sation  Earnings ($)	All Other Compen-sation ($)	Total ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Jean Paul Roy, (2) (3) President & CEO (13)	2010 2009	350,711 350,000	-0- -0-	-0- -0-	-0- -0-	Nil Nil	Nil Nil	16,281 (7) 32,730 (8)	366,992 382,730
Allan J. Kent, (2) (4) Exec VP & CFO (14)	2010 2009	215,469 212,750	5,000 -0-	-0- -0-	-0- -0-	Nil Nil	Nil Nil	22,404 (9) 27,903 (10)	242,873 240,653
Paul B. Miller, (2) President and CEO (13)	2010	183,333	-0-	-0-	124,001	Nil	Nil	83,352 (11)	390,686
Sunil Karkera CFO (15)	2010	58,125	-0-	-0-	65,700	Nil	Nil	2,250 (12)	126,075

(1)   Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with ASC 718.

(2)   Messrs. Miller, Roy and Kent were Directors or are currently Directors of our company; however they receive no additional compensation for serving in those capacities.

(3)   Up to August 17, 2010, the salary amounts were paid to Roy Group (Barbados) Inc., a Barbados company wholly owned by Mr. Roy, pursuant to the terms of an agreement described below.

(4)   Up to August 17, 2010 salary amounts were paid to D.I. Investments Ltd., a company controlled by Mr. Kent, pursuant to a Financial Services Agreement described below.  Subsequent to August 17, 2010, the salary amounts paid to Mr. Kent are pursuant to an Employment Agreement as described below.

(5)   The salary amounts paid to Mr. Miller are pursuant to an oral arrangement described below.

(6)   The salary amounts paid to Mr. Karkera up to August 17, 2010 are pursuant to an offer of employment agreement.  Subsequent to August 17, 2010, the salary amounts paid are pursuant to an Employment Agreement as described below.

(7)   Costs paid for by us included in this amount are $16,281 for medical coverage for Mr. Roy and his family up to August 8, 2010.

(8)   Costs paid for by us included in this amount are $32,730 for medical coverage for Mr. Roy and his family.

(9)   Costs paid for by us included in this amount are $22,404 for medical coverage for Mr. Kent and his family up to September 20, 2010.

(10)   Costs paid for by us included in this amount are $27,903 for medical coverage for Mr. Kent and his family.

(11)   Costs paid for by us included in this amount are $83,352 for moving costs to relocate Mr. Miller and his family.

(12)   This amount is an RRSP contribution by us of $2,250.

(13)   Up to August 17, 2010, Mr. Roy performed the duties of President and Chief Executive Officer.  Subsequent to August 17, 2010, Mr. Miller performed the duties of President and Chief Executive Officer.

(14)   Up to August 17, 2010, Mr. Kent performed the duties of Executive VP and CFO.  Subsequent to August 17, 2010, Mr. Kent performed the duties of Vice President of Finance.

(15)   Up to August 17, 2010, Mr. Karkera performed the duties of Corporate Controller.  Subsequent to August 17, 2010, Mr. Karkera performed the duties of Chief Financial Officer and as such, the above table includes compensation from August 17, 2010 to December 31, 2010 only.

Narrative Disclosure to Summary Compensation Table

From the period of August 29, 2003 to August 17, 2010 the services of Mr. Roy as President and Chief Executive Officer were provided to us under a Technical Services Agreement with Roy Group (Barbados) Inc., a company controlled by Mr. Roy for consideration of $350,000 per year.   Effective August 18, 2010 Roy Group (Barbados) Inc. charges consulting fees based on the time expended to provide technical services to the Company as assigned by the Company and to bring new oil and gas opportunities to the Company.

Up to August 17, 2010, the services of Mr. Kent as Chief Financial Officer were provided to us pursuant to a Financial Services Agreement with D. I. Investments Ltd., a company controlled by Mr. Kent.  The agreement provided for an annual fee payable of $212,750 effective January 1, 2008 to August 17, 2010 for consulting services.  Subsequent to August 17, 2010 the services of Mr. Kent as Vice President of Finance are provided to us pursuant to an Employment Agreement.  The agreement provides for annual compensation of $220,000.

The services of Mr. Miller are provided to us pursuant to an oral agreement with him to provide services for annual compensation of $220,000.

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From the period of November 9, 2009 to August 17, 2010 the services of Mr. Karkera as Corporate Controller were provided to us pursuant to an offer of employment which provided annual compensation of Cdn$132,000.  Subsequent to August 17, 2010 the services of Mr. Karkera as Chief Financial Officer are provided to us pursuant to an Employment Agreement.  The agreement provides for annual compensation of $155,000.

Grants of Plan-Based Awards

Grants of plan-based awards were made to our executive officers during the year 2010 as set below.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stocks or Units (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Options Awards ($/Sh)	Grant Date Fair Value of Stock and Option Awards
Name	Grant Date (mm/dd/yy)	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
Paul B. Miller	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	50,000 (1)	1.50	1.0402
Paul B. Miller	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	50,000 (1)	2.25	1.0315
Paul B. Miller	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	50,000 (1)	3.00	1.0244
Sunil S. Karkera	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	30,000 (2)	1.50	1.0402
Sunil S. Karkera	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	30,000 (2)	2.25	1.0315
Sunil S. Karkera	05/27/10	-0-	-0-	-0-	-0-	-0-	-0-	-0-	30,000 (2)	3.00	1.0244

(1)   Of the total 150,000 options awarded, 75,000 vested on November 27, 2010 and 75,000 will vest on May 27, 2011.

(2)   Of the total 90,000 options awarded, 45,000 vested on November 27, 2010 and 45,000 will vest on May 27, 2011.

Outstanding Equity Awards at Fiscal Year-End

The following table provides information with respect to our named executive officers regarding outstanding equity awards at December 31, 2010.

	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date mm/dd/yy	Number of Shares or Units of Stock That Have Not Vested (#)	Market Value of Shares or Units of Stock That Have Not Vested ($)	Equity Incentive Plan Awards:  Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Jean Paul Roy	500,000 (1)	-0-	-0-	3.95	07/25/16	-0-	-0-	-0-	-0-
Allan J. Kent	500,000 (1)	-0-	-0-	3.95	07/25/16	-0-	-0-	-0-	-0-
Paul B. Miller	50,000 (2)	-0-	-0-	1.50	05/27/20	-0-	-0-	-0-	-0-
Paul B. Miller	25,000 (2)	-0-	-0-	2.25	05/27/20	-0-	-0-	-0-	-0-
Paul B. Miller	-0-	25,000	-0-	2.25	05/27/20	-0-	-0-	-0-	-0-
Paul B. Miller	-0-	50,000	-0-	3.00	05/27/20	-0-	-0-	-0-	-0-
Sunil S. Karkera	30,000 (2)	-0-	-0-	1.50	05/27/20	-0-	-0-	-0-	-0-
Sunil S. Karkera	15,000 (2)	-0-	-0-	2.25	05/27/20	-0-	-0-	-0-	-0-
Sunil S. Karkera	-0-	15,000	-0-	2.25	05/27/20	-0-	-0-	-0-	-0-
Sunil S. Karkera	-0-	30,000	-0-	3.00	05/27/20	-0-	-0-	-0-	-0-
Sunil S. Karkera	-0-	60,000	-0-	1.65	12/31/12	-0-	-0-	-0-	-0-

(1)   Of these options, 250,000 vested on each of December 31, 2006 and July 25, 2007.

(2)   These options vested on November 27, 2010.

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Option Exercises and Stock Vested

The following table provides information with respect to the executive officers regarding option exercises and stock that vested during the fiscal year ended December 31, 2010.

	Options Awards		Stock Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)	Number of Shares Acquired on Vesting (#)	Value Realized on Vesting ($)
(a)	(b)	(c)	(d)	(e)
Jean Paul Roy	-0-	-0-	-0-	-0-
Allan J. Kent	-0-	-0-	-0-	-0-
Paul B. Miller	-0-	-0-	-0-	-0-
Sunil S. Karkera	-0-	-0-	-0-	-0-

Director Compensation

The following table provides information with respect to compensation of our Directors during the year ended December 31, 2010.  The compensation paid to our named executive officers who are also Directors is reflected in the Summary Compensation Table above.

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($) (1)	Option Awards ($) (1)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation  Earnings ($)	All Other Compensation ($)	Total ($)
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)
Peter Smith	24,000	-0-	50,263	-0-	-0-	-0-	74,263
Brent Peters	24,000	-0-	50,263	-0-	-0-	-0-	74,263
Michael Hudson	30,000	-0-	50,263	-0-	-0-	-0-	80,263
David Conklin	324,000	-0-	28,209	-0-	-0-	-0-	352,209
Subir Raha	2,000	-0-	40,408	-0-	-0-	-0-	42,408
Anoop Poddar	7,000	-0-	9,855	-0-	-0-	-0-	16,855

(1) Represents the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with ASC 718.

Effective May 11, 2009 our company’s Board of Directors adopted an Independent Director Compensation Policy.  Under the Policy, each of our Independent Directors, as such term is defined under the NYSE Amex Company Guide, will receive an annual retainer of $24,000 payable in monthly instalments, and the Chairperson of our Audit Committee will receive an additional annual retainer of $6,000 payable in monthly instalments.

On September 24, 2009 a Special Committee of the Board of Directors was created for a six month period consisting of Mr. David Conklin as an independent director to perform the duties of and for this Special Committee.  The Board of Directors extended the terms of the Special Committee and as such, Mr. Conklin received $25,000 each month during 2010 for his duties performed of and for this Special Committee.  Subsequent to December 31, 2010 the Board of Directors amended the terms of the Special Committee to terminate at the end of January 2011 and effective February 1, 2011, Mr. Conklin will act as Special Advisor to the Chief Executive Officer and be paid monthly compensation of Cdn$13,500.

Our Directors are also reimbursed for out-of-pocket expenses in attending meetings.

Pursuant to the terms of our 2008 Stock Incentive Plan, each non-employee Director automatically receives an option grant for 50,000 shares on the date such person joins the Board.  In addition, on the date of each annual stockholder meeting provided such person has served as a non-employee Director for at least six months, each non-employee Board member who is to continue to serve as a non-employee Board member will automatically be granted an option to purchase 50,000 shares.  Each such option has a term of ten years, subject to earlier termination following such person’s cessation of Board service, and is subject to certain vesting provisions.  For the purposes of the automatic grant provisions of our stock incentive plans, all of our Directors, other than Messrs. Roy and Kent are considered non-employee Board members.

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Compensation Committee Interlocks and Insider Participation

None of the members of our Compensation Committee were officers or employees of our company during the year ended December 31, 2010 or were former officers of our company or had any other relationship with our company requiring disclosure.

Compensation Discussion and Analysis

Policies and Objectives

Our Compensation Committee believes that our compensation policies and objectives should align with and reflect the stage of development of our operations, our operating objectives and the extent of realization of our objectives.  Our Compensation Committee believes that our policies and objectives must take into consideration our specific business objectives and manner of achieving those objectives and our ability to implement those objectives under the terms of the PSCs to which we are a party.  Accordingly, our compensation policies and objectives should be based on both our successes in entering into and pursuing joint venture arrangements, as well as the progress and success of the exploration and drilling activities of those ventures, whether undertaken directly by us or through the operators of the exploration blocks.

Our Compensation Committee also believes that the compensation of our executive officers should be based on the principles that the levels of compensation must enable our company to motivate and retain the talent we need to lead and make our company grow.  Our Compensation Committee further believes that the compensation levels must be competitive with similar other companies, be fair and reasonable and, where appropriate, reward successful performance.  Our Compensation Committee relies upon its judgment in making compensation decisions.

Because it believes such a structure is most appropriate to our company’s stage of development, the Compensation Committee has followed the practices established in 2005 of providing a compensation package to our executive officers consisting of monetary compensation and stock options.  Our Compensation Committee believes that the impact of applicable Canadian, United States and other foreign tax laws should be considered with respect to the compensation paid and the form of the compensation.  Our Compensation Committee does not establish any specific performance or target goals.

Direct Monetary Compensation

In a meeting in December 2007, the Compensation Committee considered in arriving at compensation for the fiscal year 2008 and beyond, among other things, the level of compensation for the executive officers during the prior fiscal years, the compensation levels paid by the peer group of companies as found in a compensation report prepared by Lane Caputo for the Company dated December 10, 2007, the growth and complexity of the executive officers tasks during the year and our company’s overall business plans for further growth in the following fiscal years.  We participated in the Lane Caputo December 2010 International Oil and Gas Exploration and Production Compensation Survey and as such, the survey was reviewed by the Compensation Committee and accordingly, the Compensation Committee made recommendations for the compensation for fiscal year 2010 and beyond in line with the findings of the updated report.

The direct monetary compensation of our executive officers is based on the scope of their duties and responsibilities and the executives’ individual performance in fulfilling those duties and responsibilities, in addition to the other factors described above.  Because of the inherent nature of our activities, the uncertain nature of the outcome of our activities, and the extended period of time over which the success of our activities will be determined, the Compensation Committee believes that, because the company’s ability to achieve its objectives is greatly dependent upon the activities of the operators of the drilling blocks in which we have an interest, the company’s success in its exploration and drilling activities during a particular year should not be the sole measure by which the direct monetary compensation of our executive officers is determined.  The Compensation Committee also recognizes that our company’s opportunity to enter into additional production-sharing or other contracts or acquire interests in ventures that are parties to such contracts is limited by availability of contracts and our company’s capital.  However, the Committee recognizes that future successes may lead it to award cash or other bonuses determined at that time and in the light of future events.

Our Compensation Committee had no meetings during the year ended December 31, 2010, however, two resolutions were circulated to the members of the Compensation Committee and both resolutions were signed by all members.

Equity Compensation

Our Compensation Committee believes that a material element of executive compensation should be the award of equity grants.  This element of compensation has taken the form of grants of options under our Stock Incentive Plan but other forms of equity grants may be considered.  The Compensation Committee believes the award of equity grants has the effect of aligning executive officers compensation to the future growth and success of our company.

Equity grants are the only form of long-term compensation utilized to compensate our executive officers at this time.  The Compensation Committee does not consider any relationship between Direct Monetary Compensation and Equity Compensation in making equity grants.  These grants are not based on any strict formula but rather are determined in the light of practices at the peer group selected, our company’s past practices, and our overall corporate performance during the period relative to our progress made in achieving our overall business plan objectives and achieving stockholder value.

The Compensation Committee awarded equity grants to certain of our executive officers in 2010.  See “Item 11 – Executive Compensation - Outstanding Equity Awards at Fiscal Year-End” for the schedule of award.

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Other Benefits - Change of Control

We have no arrangements with our Directors regarding any monetary payments to them in the event of a change in control of our company.

However, we do have arrangements with our Executive Officers regarding monetary payments to them in the event of a change in control of our company.  Disbursements to the Executive Officers under these arrangements cover such payments as unpaid base salary, unpaid vacation pay and any unpaid bonus as approved by the Board of Directors as well as a lump sum amount which is determined based on length of service.

In the event that our company is acquired by merger or sale of substantially all of its assets or of securities possessing more than 50% of the total combined voting power of our outstanding securities, outstanding options granted under our 1998 Stock Incentive Plan and/or our 2008 Stock Incentive Plan containing vesting provisions, including those held by executive officers and Directors, immediately vest.  Each outstanding option which is not to be assumed by the successor corporation or otherwise continued in effect will automatically accelerate in full and become fully vested, subject to certain exceptions.  Our Stock Incentive Plans contain discretionary provisions regarding the grant of options with vesting provisions.  Options may also immediately vest in connection with a change in the majority of the Board of Directors of our company by reason of one or more contested elections for Board membership.

Perquisites

Our executive officers receive perquisites in the form of medical insurance coverage for executives and their families.  Our executives are also reimbursed for out-of-pocket expenses on a cost recovery basis for expenses such as travel, hotel, meals and entertainment expenses incurred by them.

In addition, travel expenses of Mr. Roy will be paid for travel to India as approved by the Board of Directors based on the duration and purpose of the trip.

Structure of Compensation Arrangements

We have entered into the following arrangements regarding our executive officers.

We have an agreement with Roy Group (Barbados) Inc. under which, Roy Group (Barbados) Inc. agreed to perform such geologic and geophysical duties as are assigned to it by our company.  Mr. Roy performs services for us in his capacity as an employee of Roy Group (Barbados) Inc. and we pay compensation to Roy Group (Barbados) Inc.  Expenses incurred by Mr. Roy in connection with our company are reimbursed to Roy Group (Barbados) Inc. including travel expenses, hotel, meals, entertainment, computer costs and amounts billed to third parties.

Mr. Kent’s services up to August 17, 2010 were provided through D.I. Investments Ltd., a company controlled by Mr. Kent pursuant to a Financial Services Agreement.  Subsequent to August 17, 2010 Mr. Kent’s services are provided pursuant to an Employment Agreement.  In addition, we pay for medical insurance for Mr. Kent and his family.  Expenses incurred by Mr. Kent in connection with the Company are reimbursed to him including travel, hotel, meals and entertainment expenses.

The services of Mr. Miller are provided to us pursuant to an oral agreement.  In addition, we pay for medical insurance for Mr. Miller and his family.  Expenses incurred by Mr. Miller in connection with the Company are reimbursed to him for travel, hotel, meals and entertainment expenses.

Up to August 17, 2010 the services of Mr. Karkera as Corporate Controller were provided to us pursuant to an offer of employment.  Subsequent to August 17, 2010 the services of Mr. Karkera as Chief Financial Officer are provided to us pursuant to an Employment Agreement.  In addition, we pay for medical insurance for Mr. Karkera and his family.  Expenses incurred by Mr. Karkera in connection with the Company are reimbursed to him including travel, hotel, meals and entertainment expenses.

Director Compensation

Effective May 11, 2009 our company’s Board of Directors adopted an Independent Director Compensation Policy.  Under the Policy, each of our Independent Directors, as such term is defined under the NYSE Amex Company Guide, will receive an annual retainer of $24,000 payable in monthly instalments, and the Chairperson of our Audit Committee will receive an additional annual retainer of $6,000 payable in monthly instalments.

On September 24, 2009 a Special Committee of the Board of Directors was created for a six month period consisting of Mr. David Conklin as an independent director to perform the duties of and for this Special Committee.  The Board of Directors extended the terms of the Special Committee and as such, Mr. Conklin received $25,000 per month during 2010 for his duties performed of and for this Special Committee.  Subsequent to December 31, 2010, the Board of Directors amended the terms of the Special Committee to terminate at the end of January 2011 and effective February 1, 2011, Mr. Conklin will act as Special Advisor to the Chief Executive Officer and be paid monthly compensation of Cdn$13,500.

Our Directors are also reimbursed for out-of-pocket expenses in attending meetings.

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Pursuant to the terms of our 2008 Stock Incentive Plan, each non-employee Director automatically receives an option grant for 50,000 shares on the date such person joins the Board.  In addition, on the date of each annual stockholder meeting provided such person has served as a non-employee Director for at least six months, each non-employee Board member who is to continue to serve as a non-employee Board member will automatically be granted an option to purchase 50,000 shares.  Each such option has a term of ten years, subject to earlier termination following such person’s cessation of Board service, and is subject to certain vesting provisions.  For the purposes of the automatic grant provisions of our Stock Incentive Plan, all of our Directors, other than Messrs. Miller, Roy and Kent, are/were considered non-employee Board members.

Compensation Committee Report

The Compensation Committee of our Board of Directors has reviewed and discussed with management the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K.  Based on such review and discussions, the Compensation Committee recommended to the Board of Directors that the Compensation Discussion and Analysis be included in the 2010 Annual Report on Form 10-K and the Proxy Statement for the 2011 Annual Meeting of Stockholders for filing with the Securities and Exchange Commission.

Submitted by the Compensation Committee:

Michael J. Hudson (Chairman)

Brent J. Peters

The above Compensation Committee Report is not deemed to be “soliciting material” or “filed” with the Securities and Exchange Commission under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, or incorporated by reference in any documents so filed.

Item 12.                 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Securities Authorized for Issuance Under Equity Compensation Plans

During the year ended December 31, 2010, we had two equity compensation plans for our employees, directors and consultants pursuant to which options, rights or shares may be granted or have been issued.  They are referred to as our 1998 Stock Incentive Plan (the 1998 Plan), which expired on December 4, 2008 and our 2008 Stock Incentive Plan (the 2008 Plan).  See the Notes to Consolidated Financial Statements to the attached financial statements for further information on the material terms of these plans.

The following table provides information as of December 31, 2010 with respect to our equity compensation plans (including individual compensation arrangements), under which securities are authorized for issuance aggregated as to (i) compensation plans previously approved by stockholders, and (ii) compensation plans not previously approved by stockholders:

	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Plan Category	(a)	(b)	(c)
Equity compensation plans approved by security holders
1998 Stock Incentive Plan	1,800,000	$4.19	-0-
2008 Stock Incentive Plan	2,750,000	$1.75	9,250,000
Equity compensation plans not approved by security holders	-0-	-0-	-0-
Total	4,550,000	$2.72	9,250,000

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Security Ownership of Certain Beneficial Owners and Management

Set forth below is information concerning the Common Stock ownership of all persons known by us to own beneficially 5% or more of our Common Stock, the Common Stock ownership of each of our Directors and officers and all Directors and officers as a group, as of March 30, 2011.  As of March 30, 2011, we had 82,746,933 shares of Common Stock outstanding.

Name and Address of Beneficial Owner	(1)   Number of Shares Beneficially Owned	Percentage of Outstanding Common Stock
Jean Paul Roy c/o  GeoGlobal Resources Inc. Suite 200, 625 – 4 Avenue SW Calgary, Alberta    T2P 0K2	(2) (7)  32,751,000	39.6%
Allan J. Kent	(3) (7)  905,000	1.1%
Brent J. Peters	(4)  250,000	*
Peter R. Smith	(5)  250,000	*
Michael J. Hudson	(6)  250,000	*
David D. Conklin	(8)  33,334	*
Anoop Poddar	-0-	*
Paul B. Miller	(9) 190,000	*
Sunil S. Karkera	(10) 150,000	*
All directors and officers as a group (9 persons)	34,779,334	42.0%

* holds less than 1%

(1) For purposes of the above table, a person is considered to “beneficially own” any shares with respect to which he exercises sole or shared voting or investment power or of which he has the right to acquire the beneficial ownership within 60 days of March 30, 2011.

(2) Includes 32,251,000 shares of Common Stock and 500,000 options to purchase Common Stock exercisable within 60 days of March 30, 2011.

(3) Includes 405,000 shares of Common Stock and 500,000 options to purchase Common Stock exercisable within 60 days of March 30, 2011.

(4) Includes options to purchase 250,000 shares of Common Stock exercisable within 60 days of March 30, 2011.

(5) Includes options to purchase 250,000 shares of Common Stock exercisable within 60 days of March 30, 2011.

(6) Includes options to purchase 250,000 shares of Common Stock exercisable within 60 days of March 30, 2011.

(7)           On September 2, 2008, Messrs. Roy and Kent entered into a Share Purchase Agreement (Agreement) with a private investor whereby Messrs Roy and Kent each agreed to sell on the closing date in a privately negotiated transaction 375,000 shares of our common stock at a price of $3.00 per share.  In accordance with the Agreement, the closing of the sale of 270,000 of Mr. Kent’s shares occurred on September 2, 2008 and the closing of the sale of Mr. Roy’s shares and the balance of Mr. Kent’s shares was to occur seven (7) days after the filing by Mr. Roy with the required Canadian securities regulatory authorities of a Form 45-102F1, Notice of Intention to Distribute Securities under Section 2.8 of NI 45-102.  Also on September 2, 2008, Messrs. Roy and Kent entered into a Securities Pledge Agreement with the private investor whereby they delivered to the investor an additional 600,000 shares of our common stock to secure the performance by Messrs. Roy and Kent of their agreement to indemnify the investor, should the investor elect to sell the shares, against any deficiency resulting to the investor between the purchase price for the shares of common stock plus a stipulated sum per share and the price realized from the sale during the period commencing six months and one day after the respective initial and subsequent closing dates of the investor’s purchase of the shares through the date seven months after such closing dates.  The sale of the 270,000 shares by Mr. Kent was completed and is reflected in the table above, however, because of intervening market conditions the completion of the purchase of the shares from Mr. Roy and the remaining shares from Mr Kent shares was not completed.  We have been advised by Messrs. Roy and Kent that an amendment to the Agreement is currently under negotiation.

(8)           Includes options to purchase 33,334 shares of Common Stock exercisable within 60 days of March 30, 2011.

(9)           Includes 40,000 shares of Common Stock and 150,000 options to purchase Common Stock exercisable within 60 days of March 30, 2011.

(10)         Includes options to purchase 150,000 shares of Common Stock exercisable within 60 days of March 30, 2011.

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Item 13.                Certain Relationships and Related Transactions, and Director Independence

On March 27, 2003 we entered into a Participating Interest Agreement with Roy Group (Mauritius) Inc., a corporation wholly owned by Jean Paul Roy, our President, Chief Executive Officer, a Director and principal stockholder, whereby we assigned and hold in trust for Roy Group (Mauritius) Inc. subject to the Government of India consent, 50% of the benefits and obligations of the PSC covering the KG Offshore Block and the Carried Interest Agreement leaving us with a net 5% participating interest in the KG Offshore Block and a net 5% carried interest in the Carried Interest Agreement.  Under the terms of the Participating Interest Agreement, until the Government of India consent is obtained, we retain the exclusive right to deal with the other parties related to the KG Offshore Block and the Carried Interest Agreement and are entitled to make all decisions regarding the interest assigned to Roy Group (Mauritius) Inc.  Roy Group (Mauritius) Inc. has agreed to be bound by and be responsible for the actions taken by, obligations undertaken and costs incurred by us in regard to Roy Group (Mauritius) Inc.’s interest, and to be liable to us for its share of all costs, interests, liabilities and obligations arising out of or relating to the Roy Group (Mauritius) Inc. interest.  Roy Group (Mauritius) Inc. has agreed to indemnify us against any and all costs, expenses, losses, damages or liabilities incurred by reason of Roy Group (Mauritius) Inc.’s failure to pay the same.

Subject to obtaining the government consent to the assignment, Roy Group (Mauritius) Inc. is entitled to all income, receipts, credits, reimbursements, monies receivable, rebates and other benefits in respect of its 5% interest which relate to the KG Offshore PSC.

We have a right of set-off against sums owing to us by Roy Group (Mauritius) Inc.  In the event that the Government of India consent is delayed or denied, resulting in either Roy Group (Mauritius) Inc. or our company being denied an economic benefit either would have realized under the Participating Interest Agreement, the parties agreed to amend the agreement or take other reasonable steps to assure that an equitable result is achieved consistent with the parties’ intentions contained in the Participating Interest Agreement.  In the event the consent is denied, neither party is entitled to assert any claim against the other except as is specifically set forth in the agreement.  We have not yet obtained the consent of the Government of India.  As a consequence of this transaction, we report our holdings under the KG Offshore PSC and Carried Interest Agreement as a net 5% participating interest.

On August 29, 2003 we entered into a Technical Services Agreement with Roy Group (Barbados) Inc., a corporation wholly owned by Mr. Roy, whereby Roy Group (Barbados) Inc. agreed to perform geological and geophysical duties assigned to it by our company.  The term of the agreement, as amended, extends through December 31, 2010 and continues for successive periods of one year thereafter unless otherwise agreed by the parties or either party has given notice that the agreement will terminate at the end of the term.  On January 31, 2006, the terms of the agreement were amended to amend the fee payable from $250,000 to $350,000 effective January 1, 2006.  Roy Group (Barbados) Inc. is reimbursed for authorized travel and other out-of-pocket expenses.  The agreement prohibits Roy Group (Barbados) Inc. from disclosing any of our confidential information and from competing directly or indirectly with us for a period ending December 31, 2010 with respect to any acquisition, exploration, or development of any crude oil, natural gas or related hydrocarbon interests within the area of the country of India.  The agreement terminated on August 17, 2010, however the confidentiality and non-competition provisions survive this termination.  Roy Group (Barbados) Inc. received $350,711 from us during 2010 under the terms of this agreement.

Roy Group (Barbados) Inc. was reimbursed for expenses such as travel, hotel, meals and entertainment, computer costs and amounts billed to third parties incurred by Mr. Roy during 2010.  Additionally, we paid for medical insurance coverage for Mr. Roy and his family during 2010 in the amount of $16,281.At December 31, 2010, we owed Roy Group (Barbados) Inc. $16,200 for services provided and expenses incurred on behalf of our Company which amount bears no interest and has no set terms of repayment.

During the year ended December 31, 2010 Mr. Allan J. Kent who was Executive Vice President, Chief Financial Officer and a Director, was paid $133,827 by us for consulting services of Mr. Kent which are provided to us pursuant to a contract with D.I. Investments Ltd., a corporation wholly-owned by him which expired on August 17, 2010.

D.I. Investments Ltd. was reimbursed for expenses such as travel, hotel, meals and entertainment and expenses incurred directly throughout 2010.  Additionally, we paid for medical insurance coverage for Mr. Kent and his family during 2010 in the amount of $22,404.  At December 31, 2010, we owed D.I. Investments Ltd. $nil as a result of services provided and expenses incurred on behalf of our company.

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During the year ended December 31, 2010 Amicus Services Inc., a company controlled by Mr. Vincent Roy, a brother of Jean Paul Roy, our President, Chief Executive Officer and President, was paid $51,783 by us for consulting fees for services rendered pursuant to an oral agreement.  Amicus Services Inc. provided, pursuant to the agreement, IT and computer related services to cover such duties as: organizing, managing and maintaining a geological database in Canada relating to our exploration interests an India and elsewhere; upgrading on a continuing basis all information systems (both software and hardware) and network systems (including onsite and offsite backups of data and security issues) of a corporate nature; and providing ongoing IT services as required to Calgary staff.  The hourly rate paid to Amicus Services Inc. throughout 2010 was Canadian $70.00.  We are provided these IT services approximately three days per week.  The oral agreement can be immediately terminated by either party at any time by notice given to the other party.

At December 31, 2010 we owed Amicus Services Inc. $11,355 as a result of services provided and expenses incurred on behalf of our company.

Item 14.                Principal Accountant Fees and Services

The following sets forth fees we incurred for professional services provided by KPMG, LLP and Ernst & Young LLP for accounting services rendered during the years ended December 31, 2010 and December 31, 2009, respectively.

	Audit Fees	Audit Related Fees	Tax Fees	All Other Fees	Total
2010	359,247	26,407	14,702	--	400,356
2009	388,432	4,424	91,228	9,790	493,874

Our Board of Directors believes that the provision of the services during the years ended December 31, 2010 and December 31, 2009 is compatible with maintaining the independence of KPMG LLP.  Our Audit Committee approves before the engagement the rendering of all audit and non-audit services provided to our company by our independent auditor.  Engagements to render services are not entered into pursuant to any pre-approval policies and procedures adopted by the Audit Committee.  The services provided by KPMG LLP included under the caption Audit Fees include services rendered for the audit of our annual financial statements and the review of our quarterly financial reports filed with the Securities and Exchange Commission.  Audit Related Fees include services rendered in connection with a follow-up the review of other filings with the Securities and Exchange Commission.  Tax Fees include services rendered relating primarily to tax compliance, consulting, customs and duties.  All Other Fees include administration fees to cover various expenses and SOX related work performed to date.

Part IV

Item 15.                Exhibits and Financial Statement Schedules

Exhibit	Description
3.1	Certificate of Incorporation of the Registrant, as amended (1)
3.2	Bylaws of the Registrant, as amended (4)
3.2	Bylaws of the Registrant, as amended (16)
3.3	Certificate of Amendment filed with the State of Delaware on November 25, 1998 (2)
3.4	Certificate of Amendment filed with the State of Delaware on December 4, 1998 (2)
3.5	Certificate of Amendment filed with the State of Delaware on March 18, 2003 (5)
3.6	Certificate of Amendment filed with the State of Delaware on January 8, 2004 (5)
4.1	Specimen stock certificate of the Registrant (5)
10.1	1998 Stock Incentive Plan (2)
10.2	2008 Stock Incentive Plan (13)
10.3	Stock Purchase Agreement dated April 4, 2003 by and among Suite101.com, Inc., Jean Paul Roy and GeoGlobal Resources (India) Inc. (3)
10.4	Amendment dated August 29, 2003 to Stock Purchase Agreement dated April 4, 2003 (4)
10.5	Technical Services Agreement dated August 29, 2003 between Suite101.com, Inc. and Roy Group (Barbados) Inc. (4)
10.5.1	Amendment to Technical Services Agreement dated January 31, 2006 between GeoGlobal Resources Inc. and Roy Group (Barbados) Inc. (8)
10.6	Participating Interest Agreement dated March 27, 2003 between GeoGlobal Resources (India) Inc. and Roy Group (Mauritius) Inc. (4)
10.7	Escrow Agreement dated August 29, 2003 among Registrant, Jean Paul Roy and Computershare Trust Company of Canada (4)
10.8	Promissory Note dated August 29, 2003 payable to Jean Paul Roy (4)
10.9	Production Sharing Contract dated February 4, 2003 among The Government of India, Gujarat State Petroleum Corporation Limited, Jubilant Enpro Limited and GeoGlobal Resources (India) Inc. (6)
10.10	Production Sharing Contract dated February 6, 2004 among The Government of India, Gujarat State Petroleum Corporation Limited, Jubilant Enpro Private Limited and GeoGlobal Resources (Barbados) Inc. (6)
10.11	Production Sharing Contract dated February 6, 2004 among The Government of India, Gujarat State Petroleum Corporation Limited, Jubilant Enpro Private Limited, Prize Petroleum Company Limited and GeoGlobal Resources (Barbados) Inc. (6)

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Exhibit	Description
10.12	Carried Interest Agreement dated August 27, 2002 between Gujarat State Petroleum Corporation Limited and GeoGlobal Resources (India) Inc. (5)
10.13	Production Sharing Contract dated September 23, 2005 between the Government of India and GeoGlobal Resources (Barbados) Inc. (7)
10.14	Production Sharing Contract dated September 23, 2005 between the Government of India, Gujarat State Petroleum Corporation Limited, GAIL (India) Ltd., Jubilant Capital Pvt. Ltd. and GeoGlobal Resources (Barbados) Inc. (7)
10.15	Production Sharing Contract dated March 2, 2007 between the Government of India, Oil India Limited and GeoGlobal Resources (Barbados) Inc. (9)
10.16	Production Sharing Contract dated March 2, 2007 between the Government of India, Oil India Limited and GeoGlobal Resources (Barbados) Inc. (9)
10.17	Production Sharing Contract dated March 2, 2007 between the Government of India, Oil India Limited, Hindustan Petroleum Corpn. Ltd. and GeoGlobal Resources (Barbados) Inc. (9)
10.18	Production Sharing Contract dated March 2, 2007 between the Government of India and GeoGlobal Resources (Barbados) Inc. (9)
10.19	Form of Warrant Certificate issued to subscribers relating to the offer and sale of Units from June 2007 financing (10)
10.20	Compensation Option dated June 20, 2007 between the Company and Primary Capital Inc. for the issuance of 170,400 compensation options (10)
10.21	Compensation Option dated June 20, 2007 between the Company and Jones, Gable & Company Limited for the issuance of 170,400 compensation options (10)
10.22	Joint Operating Agreement dated August 7, 2003 between Gujarat State Petroleum Corporation Limited, Jubilant Enpro Limited and GeoGlobal Resources (India) Inc. (11)
10.23	Production Sharing Contract dated April 12, 2000 between the Government of India, Oil & Natural Gas Corporation Limited, Gujarat State Petroleum Corporation Limited and Hindustan Oil Exploration Company Limited (12)
10.24	Amendment No. 2 to Production Sharing Contract dated April 12, 2000 between the Government of India, Oil & Natural Gas Corporation Limited, Gujarat State Petroleum Corporation Limited and Hindustan Oil Exploration Company Limited effective August 24, 2006 (12)
10.25	Description of terms of oral consulting agreement between GeoGlobal Resources Inc. and Amicus Services Inc. (14)
10.26	Chapman Petroleum Engineering Report dated January 1, 2010 effective December 31, 2009 (15)
10.27	Joint Bidding Agreement dated August 27, 2002 between Gujarat State Petroleum Corporation Limited, Jubilant ENPRO Limited and GeoGlobal Resources (India) Incorporated (17)
10.28	Securities Purchase Agreement dated October 12, 2010 between GeoGlobal Resources Inc. and purchasers relating to the issuance of 2,941,177 Units (18)
10.29	Financial Services Agreement dated October 29, 2010 with an effective date of August 29, 2003 between GeoGlobal Resources Inc. And D.I. Investments Ltd. (19)
10.30	Joint Operating Agreement dated October 6, 2010 between IPC Oil and Gas (Israel) Limited Partnership, Emanuelle Energy Limited, Emanuelle Energy Oil and Gas Limited Partnership, The Israel Land and Development Company Limited, IDB Development Corporation Limited, Modiin Energy Limited Partnership and Blue Water Oil and Gas Exploration Limited (as Non-Operators) and GeoGlobal Resources (India) Inc. (20)
10.31	Joint Operating Agreement dated October 6, 2010 between IPC Oil and Gas (Israel) Limited Partnership, Emanuelle Energy Limited, Emanuelle Energy Oil and Gas Limited Partnership, The Israel Land and Development Company Limited, IDB Development Corporation Limited, Modiin Energy Limited Partnership and Blue Water Oil and Gas Exploration Limited (as Non-Operators) and GeoGlobal Resources (India) Inc. (20)
10.32	Employment Agreement dated November 18, 2010 with an effective date of August 17, 2010 between Mr. Sunil S. Karkera and GeoGlobal Resources Inc. (21)
10.33	Employment Agreement dated November 18, 2010 with an effective date of August 17, 2010 between Mr. Allan J. Kent and GeoGlobal Resources Inc. (21)
10.34	Employment Agreement executed January 27, 2011 with an effective date of January 1, 2011 between Mr. Paul B. Miller and GeoGlobal Resources Inc.  (22)
10.35	Chapman Petroleum Engineering Report dated January 1, 2011 effective December 31, 2010 (23)
10.36	International Operating Agreement dated February, 2011 and effective March 8, 2011 between Adira Geoglobal Ltd, Adira Oil Technologies Ltd., Brownstone Venture Inc., Pinetree Capital Ltd., and GeoGlobal Resources (India) Inc. (23)

23.1	Consent of KPMG LLP (23)
23.2	Consent of Ernst & Young LLP (23)
31.1	Certification of President and Chief Executive Officer Pursuant to Rule 13a-14(a) (23)
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) (23)
32.1	Certification of President and Chief Executive Officer Pursuant to Section 1350 (23)
32.2	Certification of Chief Financial Officer Pursuant to Section 1350 (23)

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Exhibit	Description
99.1	Code of Ethics (15)
99.2	Subsidiaries of the Registrant:
	Name	State or Jurisdiction of Incorporation
	GeoGlobal Resources (India) Inc.	Barbados
	GeoGlobal Resources (Canada) Inc.	Alberta
	GeoGlobal Resources (Barbados) Inc.	Barbados
	GGR Oil & Gas (India) Private Limited	India

(1) Filed as an Exhibit to Neuro Navigational Corporation Form 10-KSB No. 0-25136 dated September 30, 1994.

(2) Filed as an Exhibit to our Current Report on Form 8-K dated December 10, 1998.

(3) Filed as exhibit 10.1 to our Quarterly Report on Form 10-QSB for the quarter ended March 31, 2003.

(4) Filed as an exhibit to our Current Report on Form 8-K for August 29, 2003.

(5) Filed as an Exhibit to our Form 10-KSB dated April 1, 2004.

(6) Filed as an Exhibit to our Form 10-KSB/A dated April 28, 2004.

(7) Filed as an Exhibit to our Quarterly Report on Form 10-QSB for the quarter ended September 30, 2005.

(8) Filed as an Exhibit to our Current Report on Form 8-K dated January 31, 2006.

(9) Filed as an Exhibit to our Quarterly Report on Form 10-Q for the quarter ending March 31, 2007.

(10) Filed as an Exhibit to our Current Report on Form 8-K dated June 27, 2007.

(11) Filed as an Exhibit to our Current Report on Form 8-K dated August 14, 2007.

(12) Filed as an Exhibit to our Form 10-K dated June 4, 2008.

(13) Filed as an Exhibit to our Form S-8 dated December 31, 2008.

(14) Filed as an Exhibit to our Form 10-K dated March 26, 2009.

(15) Filed as an Exhibit to our Form 10-K dated March 31, 2010.

(16) Filed as Exhibit 3.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010.

(17) Filed as an Exhibit to our Current Report on Form 8-K for August 30, 2010.

(18) Filed as an Exhibit to our Current Report on Form 8-K for October 12, 2010.

(19) Filed as an Exhibit to our Current Report on Form 8-K for October 29, 2010.

(20) Filed as an Exhibit to our Current Report on Form 8-K for November 8, 2010.

(21) Filed as an Exhibit to our Current Report on Form 8-K for November 18, 2010.

(22) Filed as an Exhibit to our Current Report on Form 8-K for January 28, 2011.

(23) Filed herewith.

  Page 54

GEOGLOBAL RESOURCES INC.

(a development stage enterprise)

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND DECEMBER 31, 2009

(in United States dollars)

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm- - KPMG Audit Report		FS 2
Report of Independent Registered Public Accounting Firm - KPMG Audit of Internal Control over Financial Reporting		FS 3
Report of Independent Registered Public Accounting Firm- - Ernst & Young Audit Report		FS 4
Financial Statements
	Consolidated Balance Sheets	FS 5
	Consolidated Statements of Operations and Comprehensive Loss	FS 6
	Consolidated Statements of Changes in Stockholders’ Equity	FS 7
	Consolidated Statements of Cash Flows	FS 8
	Notes to the Consolidated Financial Statements	FS 9-26

FS 1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

GeoGlobal Resources Inc.

We have audited the accompanying consolidated balance sheets of GeoGlobal Resources Inc. and subsidiaries (a development stage enterprise) as of December 31, 2010 and 2009, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2010 and for the period from August 21, 2002 (inception) to December 31, 2010. These consolidated financial statements are the responsibility of GeoGlobal Resources Inc.’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The cumulative statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the period August 21, 2002 (inception) to December 31, 2010 include amounts for the period from August 21, 2002 (inception) to December 31, 2002 and for each of the years in the four-year period ending December 31, 2006, which were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for the period August 21, 2002 through December 31, 2006 is based solely on the report of other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoGlobal Resources Inc. and subsidiaries (a development stage enterprise) as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010 and for the period from August 21, 2002 (inception) to December 31, 2010, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that GeoGlobal Resources Inc. will continue as a going concern. As discussed in note 2 to the consolidated financial statements, GeoGlobal Resources Inc. has suffered recurring losses from operations and has a deficit accumulated during the development stage that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), GeoGlobal Resource Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 31, 2011, expressed an unqualified opinion on the effectiveness of GeoGlobal Resources Inc.’s internal control over financial reporting.

(signed) KPMG LLP

Calgary, Canada

March 31, 2011

FS 2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

GeoGlobal Resources Inc.:

We have audited GeoGlobal Resources Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GeoGlobal Resources Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Controls Over Financial Reporting. Our responsibility is to express an opinion on the GeoGlobal Resources Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, GeoGlobal Resources Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of GeoGlobal Resources Inc. and its subsidiaries (a development stage enterprise) as of December 31, 2010 and 2009, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010 and for the period from August 21, 2002 (inception) to December 31, 2010, and our report dated March 31, 2011 expressed an unqualified opinion on those consolidated financial statements.

(signed) KPMG LLP

Calgary, Canada

March 31, 2011

FS 3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders Of

GeoGlobal Resources Inc.

We have audited the accompanying consolidated statement of operations and comprehensive loss of GeoGlobal Resources Inc., a development stage enterprise, and the related consolidated statements of stockholders' equity and cash flows for the cumulative period from inception on August 21, 2002 to December 31, 2006 (not separately presented herein).  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  We were not engaged to perform an audit of the Company's internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of its operations, changes in shareholders and its cash flows for the cumulative period from inception on August 21, 2002 to December 31, 2006 (not separately presented herein) in conformity with United States generally accepted accounting principles.

CALGARY, ALBERTA                                                                                                           "Ernst & Young LLP" (signed)

March 23, 2007 except for Note 8,                                                                                           CHARTERED ACCOUNTANTS

which is as of June 5, 2008

FS 4

GEOGLOBAL RESOURCES INC. (a development stage enterprise) CONSOLIDATED BALANCE SHEETS
	December 31, 2010 $			December 31, 2009 $
Assets
Current
Cash and cash equivalents		7,751,105			16,294,996
Restricted deposits (note 4)		2,034,000			--
Accounts receivable		2,317,180			64,031
Prepaid expenses and deposits		398,404			173,318
		12,500,689			16,532,345
Restricted deposits (note 4)		5,018,000			6,925,000
Property and equipment (notes 5, 10 and 11)		41,375,680			46,813,004
		58,894,369			70,270,349
Liabilities
Current
Accounts payable		6,834,061			8,733,612
Accrued liabilities		1,682,504			1,196,614
Due to related companies (note 11)		27,555			123,554
		8,544,120			10,053,780
Deferred income taxes		61,000			--
Asset retirement obligation (note 6)		680,144			775,000
		9,285,264			10,828,780
Stockholders’ Equity
Capital stock (note 8)
Authorized
125,000,000 common stock with a par value of $0.001 each
1,000,000 preferred stock with a par value of $0.01 each
Issued
82,746,933 common stock (December 31, 2009 – 72,805,756)		68,155			58,214
Additional paid-in capital		97,099,997			88,153,778
Deficit accumulated during the development stage		(47,559,047	)		(28,770,423	)
		49,609,105			59,441,569
		58,894,369			70,270,349
See Going Concern (note 2), Commitments (note 15) and Contingencies (note 16) The accompanying notes are an integral part of these Consolidated Financial Statements.

FS 5

GEOGLOBAL RESOURCES INC. (a development stage enterprise) CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS
	Year ended Dec 31, 2010 $			Year ended Dec 31, 2009 $			Year ended Dec 31, 2008 $			Period from Inception, Aug 21, 2002 to Dec 31, 2010 $
Revenue and other income
Oil and gas sales		790,342			661,922			--			1,452,264
Interest income		52,607			299,550			1,148,479			5,913,734
Gain on sale of equipment		--			--			--			42,228
		842,949			961,472			1,148,479			7,408,226
Expenses
Operating		173,297			98,878			--			272,175
General and administrative		3,193,328			2,986,967			2,343,138			13,779,912
Consulting fees (note 11)		652,359			822,652			742,002			7,311,702
Professional fees		827,995			1,085,056			1,089,173			4,792,871
Depletion and depreciation		824,304			352,637			52,144			1,495,820
Accretion (note 6)		41,289			55,619			32,202			129,110
Foreign exchange (gain) loss		23,501			(16,090	)		105,720			118,168
Impairment of oil and gas properties (note 5)		13,789,000			--			10,098,015			23,887,015
		19,525,073			5,385,719			14,462,394			51,786,773
Net loss before tax		(18,682,124	)		(4,424,247	)		(13,313,915	)		(44,378,547	)
Current income tax (note 13)		(45,500	)		--			--			(45,500	)
Deferred income tax (note 13)		(61,000	)		--			--			(61,000	)
Net loss and comprehensive loss for the year		(18,788,624	)		(4,424,247	)		(13,313,915	)		(44,485,047	)
Warrant modification (note 9)		--			(1,754,000	)		--			(3,074,000	)
Net loss and comprehensive loss attributable to     common stockholders		(18,788,624	)		(6,178,247	)		(13,313,915	)		(47,559,047	)
Basic and diluted net loss per share (note 12)		(0.25	)		(0.09	)		(0.20	)

The accompanying notes are an integral part of these Consolidated Financial Statements.

FS 6

GEOGLOBAL RESOURCES INC. (a development stage enterprise) CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
	Number of Shares #	Capital  Stock $	Additional paid-in capital $	Accumulated Deficit $	Stockholders’Equity $
For the period from inception August 21, 2002 to     December 31, 2007
Common stock issued	57,550,068	57,614	76,001,511	--	76,059,125
Capital stock of GeoGlobal at August 29, 2003	14,656,688	14,657	--	10,914,545	10,929,202
Elimination of GeoGlobal capital stock in      recognition of reverse takeover	(1,000)	(14,657)	--	(10,914,545)	(10,929,202)
Share issuance cost	--	--	(4,778,844)	--	(4,778,844)
2007 Compensation Options	--	--	705,456	--	705,456
2005 Stock Purchase Warrant modification	--	--	1,320,000	(1,320,000)	--
2005 Compensation Option & Warrant modification	--	--	240,000	--	240,000
Stock-based compensation	--	--	9,302,934	--	9,302,934
Net loss	--	--	--	(7,958,261)	(7,958,261)
Balance as at December 31, 2007	72,205,756	57,614	82,791,057	(9,278,261)	73,570,410
Common stock issued for exercise of options	600,000	600	659,400	--	660,000
Stock-based compensation	--	--	1,104,216	--	1,104,216
Net loss	--	--	--	(13,313,915)	(13,313,915)
Balance as at December 31, 2008	72,805,756	58,214	84,554,673	(22,592,176)	62,020,711
Compensation option and warrant modification	--	--	264,000	--	264,000
Stock purchase warrant modification	--	--	1,754,000	(1,754,000)	--
Stock-based compensation	--	--	1,581,105	--	1,581,105
Net loss	--	--	--	(4,424,247)	(4,424,247)
Balance as at December 31, 2009	72,805,756	58,214	88,153,778	(28,770,423)	59,441,569
Common stock issued for private placements (note 8)	9,941,177	9,941	8,440,059	--	8,450,000
Share issuance costs (note 8)	--	--	(463,804)	--	(463,804)
Stock-based compensation (note 10)	--	--	969,964	--	969,964
Net loss	--	--	--	(18,788,624)	(18,788,624)
Balance as at December 31, 2010	82,746,933	68,155	97,099,997	(47,559,047)	49,609,105
The accompanying notes are an integral part of these Consolidated Financial Statements.

FS 7

GEOGLOBAL RESOURCES INC. (a development stage enterprise) CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year ended Dec 31, 2010 $			Year ended Dec 31, 2009 $			Year ended Dec 31, 2008 $			Period from Inception, Aug 21, 2002 to Dec 31, 2010 $
Cash flows provided by (used in) operating activities:
Net loss		(18,788,624	)		(4,424,247	)		(13,313,915	)		(44,485,047	)
Adjustments to reconcile net loss to net cash used in operating activities:
Accretion expense		41,289			55,619			32,202			129,110
Asset impairment		13,789,000			--			10,098,015			23,887,015
Depletion and depreciation		824,304			352,637			52,144			1,495,820
Gain on sale of equipment		--			--			--			(42,228	)
Stock-based compensation (note 10)		717,629			918,685			626,257			7,548,216
Compensation option and warrant  modification		--			264,000			--			504,000
Deferred income taxes		61,000			--			--			61,000
Changes in non-cash working capital (note 17)		(711,636	)		714,647			(593,494	)		38,937
		(4,067,038	)		(2,118,659	)		(3,098,791	)		(10,863,177	)
Cash flows provided by (used in) investing activities:
Oil and natural gas property additions		(9,039,941	)		(11,222,450	)		(16,073,528	)		(58,092,726	)
Other property and equipment additions		(19,849	)		(34,174	)		(50,067	)		(1,575,324	)
Proceeds on sale of equipment		--			--			--			82,800
Cash acquired on acquisition		--			--			--			3,034,666
Restricted deposits (note 4)		(127,000	)		3,875,000			(7,414,520	)		(8,222,000	)
Changes in non-cash working capital (note 17)		(3,276,259	)		362,465			3,274,862			5,773,835
		(12,463,049	)		(7,019,159	)		(20,263,253	)		(58,998,749	)
Cash flows provided by (used in) financing activities:
Proceeds from issuance of common stock		8,450,000			--			660,000			84,062,165
Share issuance costs		(463,804	)		--			--			(4,537,192	)
Changes in non-cash working capital (note 17)		--			--			--			(1,911,942	)
		7,986,196			--			660,000			77,613,031
Net increase (decrease) in cash and cash equivalents		(8,543,891	)		(9,137,818	)		(22,702,044	)		7,751,105
Cash and cash equivalents, beginning of the year		16,294,996			25,432,814			48,134,858			--
Cash and cash equivalents, end of the year		7,751,105			16,294,996			25,432,814			7,751,105
Cash and cash equivalents
Current bank accounts		158,879			163,280			365,726			158,879
Short term deposits		7,592,226			16,131,716			25,067,088			7,592,226
		7,751,105			16,294,996			25,432,814			7,751,105
Cash taxes paid during the year		73,775			17,750			32,650

The accompanying notes are an integral part of these Consolidated Financial Statements.

FS 8

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

1.         Organization and Nature of Operations

The Company is engaged in the pursuit of petroleum and natural gas through exploration and development in India, Israel and Colombia.  Since inception, the efforts of GeoGlobal have primarily been devoted to the pursuit of Production Sharing Contracts (PSCs) with the Gujarat State Petroleum Corporation (GSPC), Oil India Limited and the Government of India and the exploration and development thereof.  The Company is a Delaware corporation with common stock listed and traded on the NYSE Amex Exchange under the symbol GGR.

On August 29, 2003, the Company commenced oil and gas exploration activities.  As of December 31, 2010, the Company has not achieved its planned principal operations from its oil and gas operations.  Accordingly, the Company’s activities are considered to be those of a “Development Stage Enterprise”.  Among the disclosures required by this status is that the Company’s financial statements be identified as those of a development stage enterprise.  In addition, the statements of operations and comprehensive loss, stockholders’ equity and cash flows are required to disclose all activity since the Company’s date of inception.  The Company will continue to prepare its financial statements and related disclosures as those of a development stage enterprise until such time that the Company achieves planned principal operations.

2.         Going Concern

To date, the Company has not achieved its planned principal operations and is considered to be in the development stage.  The Company incurs cash outflows from operations, and at this time all exploration activities and overhead expenses are financed by way of equity issuance, oil and gas sales incidental to the exploration process and interest income.  The recoverability of the costs incurred to date is uncertain and dependent upon achieving significant commercial production or sale.

The Company’s 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 its oil and natural gas interests in the future.  The Company’s current operations are dependent upon the adequacy of its current assets to meet its current expenditure requirements and the accuracy of management’s estimates of those requirements.  Should those estimates be materially incorrect, the Company’s ability to continue as a going concern will be impaired.  The Company’s financial statements as at and for the year ended December 31, 2010 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.  During the year ended December 31, 2010, the Company incurred a net loss of approximately $18.79 million, used approximately $4.07 million of cash flow in its operating activities, used approximately $12.46 million in its investing activities and had an accumulated deficit of approximately $47.56 million.  These matters raise doubt about the Company’s ability to continue as a going concern.

The Company expects to incur expenditures to further its exploration programs.  The Company’s existing cash balance and any cash flow from operating activities is not sufficient to satisfy its current obligations and meet its commitments of $29.85 million over the next three years ending December 31, 2013, approximately $13.15 million of which is attributable to the twelve months ending December 31, 2011.  The Company is considering various alternatives to remedy any future shortfall in capital.  The Company deems it necessary to raise capital for continued exploration and development expenditures through equity markets, debt markets or other financing arrangements, which could include the sale of oil and gas interests or participation arrangements in oil and gas interests.   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 and development expenditures.

As at December 31, 2010, the Company has working capital of approximately $3.96 million which is available for the company’s future operations.  In addition, the Company has $5.02 million in restricted deposits pledged as security against the minimum work programs which will be released upon completion of the minimum work programs.

Should the going concern assumption not be appropriate and the Company not be able to realize its assets and settle its liabilities, commitments (as described in note 15) and contingencies (as described in note 16) in the normal course of operations, these audited consolidated financial statements would require adjustments to the amounts and classifications of assets and liabilities, and these adjustments could be significant.

These audited consolidated financial statements do not reflect the adjustments or reclassifications of assets and liabilities that would be necessary if the Company is unable to continue as a going concern.

FS 9

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

3.         Significant Accounting Policies

Principles of consolidation

These consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly-owned.  These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States.  A significant portion of the Company’s activities conducted jointly with others and the consolidated financial statements reflect only the Company’s proportionate interest in such activities.  All inter-company balances and transactions have been eliminated in consolidation.  Certain of the comparative amounts have been reclassified to conform to current year presentation.

Use of estimates

The preparation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results may differ from these estimated amounts due to factors such as fluctuations in interest rates, currency exchange rates, inflation levels and commodity prices, changes in economic conditions and legislative and regulatory changes.

Significant estimates with regard to the consolidated financial statements include the estimated carrying value of unproved properties, the estimated cost and timing related to asset retirement obligations, stock-based compensation and contingencies.

Cash and cash equivalents

Cash and cash equivalents include cash on hand, balances with banks, money market mutual funds and highly liquid debt instruments purchased with an original maturity of three months or less.  Certain of the Company’s cash balances are maintained in foreign banks.  At times, the Company maintains deposits in financial institutions in excess of federally insured limits.

Property and equipment

Oil and natural gas properties

The Company uses the full cost method of accounting for its oil and natural gas properties.  Separate cost centers are maintained for each country in which the Company incurs costs.  Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities.  Costs associated with production and general corporate activities, however, are expensed in the period incurred.  To the extent that support equipment is used in oil and gas activities, the related depreciation is capitalized.  Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such disposition would alter the depletion and depreciation rate by 25% or more.

Capitalized costs of development oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved reserves plus the lower of cost or fair value of unproven properties.  Should capitalized costs exceed this ceiling, an impairment is recognized.

The present value of estimated future net cash flows is computed by applying the average first-day-of-the-month prices during the previous twelve-month period of oil and natural gas to estimated future production of proved oil and natural gas reserves as of year-end less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Following the discovery of reserves and the commencement of production, the Company computes depletion of oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities.

The Company assesses all items classified as unproved property on a quarterly basis for possible impairment or reduction in value.  The Company assesses properties on an individual basis or as a group if properties are individually insignificant.  The assessment includes consideration of the following factors, among others: land relinquishment; intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned.  During any period in which these factors indicate an impairment, the related exploration costs incurred are transferred to the full cost pool and are then subject to depletion and the ceiling limitations on development oil and natural gas expenditures.

FS 10

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

3.         Significant Accounting Policies (continued)

Others

Property and equipment, other than oil and natural gas properties, are recorded at cost and depreciated over their estimated useful lives which range from three to twenty years on a declining balance basis.  The Company reviews the carrying value of property and equipment for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

Income taxes

The Company follows the liability method of tax allocation.  This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities.  The tax benefits of tax loss carry-forwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not.  Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled.  The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted rate change.  Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense.

Asset retirement obligations

The fair values of estimated asset retirement obligations are recorded as liabilities when incurred and the associated cost is capitalized as part of the cost of the related asset.  The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.  The liabilities are accreted as operating expense for the change in their time value.  The initial capitalized costs are included in depletion expense in a manner consistent with the related assets.  Changes in the estimated obligation resulting from revisions to the estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and related asset.  Actual expenditures incurred are charged against the accumulated obligation.

Stock-based compensation plan

Compensation cost for all share-based payments are based on the fair value estimated and is recognized on a straight line basis over the vesting period for the award.  The Company accounts for transactions in which it issues equity instruments to acquire goods or services from non-employees based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.

The fair value of share-based payments is capitalized or expensed, with a corresponding increase to additional paid-in capital for the equity-classified awards, or the share-based payment liability for the liability-classified awards.  Upon exercise of stock options, the consideration paid upon exercise is recorded as additional value of common stock in additional paid-in capital.

Revenue recognition

Revenue from the sale of crude oil and gas is recognized upon the transfer of custody to the customer.

Comprehensive loss

Comprehensive loss includes all changes in equity except those resulting from investments made by owners and distributions to owners.  Comprehensive loss consists only of net loss for all periods presented.

Net loss per share

Basic per share amounts are computed by dividing net loss attributable to common stockholders by the weighted average number of common stock outstanding for the period.  Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock were exercised to common stock.

The treasury stock method is used to determine the dilutive effect of the stock options.  The treasury stock method assumes any proceeds obtained upon exercise of options would be used to purchase common stock at the average market price during the period.  Under the treasury stock method, only options or other dilutive instruments for which the exercise price is less than the market value impact the dilution calculations.

Foreign currency translation

The U.S. dollar is the functional currency of the Company and its subsidiaries.  Monetary assets and liabilities denominated in foreign currencies are translated into U.S. dollars at rates of exchange in effect at the date of the balance sheet.  Non-monetary items are translated at the rate of exchange in effect when the assets are acquired or obligations incurred.  Revenues and expenses are translated at average rates in effect during the period, with the exception of depreciation which is translated at historic rates.  Exchange gains and losses are charged to operations.

FS 11

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

3.         Significant Accounting Policies (continued)

Concentration of risk

The majority of the Company’s capitalized costs for oil and gas interests are incurred with two major operators in India.  The Company relies on these operators in fulfilling its obligations and meeting the terms of its contracts with the Government of India.  In addition, the Company relies on these operators for discovering economically recoverable reserves and their ability to market those reserves at prices that will yield a return on our investment to us.

Financial instruments

The Company has estimated the fair value of its financial instruments which include cash and cash equivalents, restricted deposits, accounts receivable, accounts payable, accrued liabilities and amounts due to related companies.  The Company used market information available as at year end to determine that the carrying amounts of such financial instruments approximate fair value in all cases.

Periodically, the Company utilizes marketable securities to invest a portion of its cash on hand.  These securities are carried at fair value on the consolidated balance sheets, with the changes in the fair value included in the consolidated statements of operations and comprehensive loss for the period in which the change occurs.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

The following fair value hierarchy establishes a fair value hierarchy that prioritizes the inputs used to measure fair value:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date and includes those financial instruments that are valued using models or other valuation methodologies.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources.  These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

4.         Restricted Deposits

The Company’s PSCs relating to exploration blocks onshore and offshore India contain provisions whereby the joint venture participants must provide the Government of India a bank guarantee in the amount of 35% of the participant’s share of the minimum work program for a particular phase, to be undertaken annually during the budget period April 1 to March 31.  These bank guarantees have been provided to the Government of India and serve as guarantees for the performance of such minimum work programs and are in the form of irrevocable letters of credit which are secured by term deposits of the Company in the same amount.

The term deposits securing these bank guarantees are as follows:

	December 31, 2010			December 31, 2009
	$			$
Exploration Blocks - India
Mehsana		--			160,000
Sanand/Miroli		1,300,000			1,300,000
Ankleshwar		734,000			1,490,000
Tarapur		--			940,000
DS 03		330,000			450,000
DS 04		1,247,000			215,000
KG Onshore		900,000			1,475,000
RJ 20		1,100,000			490,000
RJ 21		1,441,000			405,000
		7,052,000			6,925,000
Less: current portion of restricted deposit		(2,034,000	)		--
		5,018,000			6,925,000

FS 12

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

4.         Restricted Deposits (continued)

The following term deposits are classified as current restricted deposits:

	December 31, 2010		December 31, 2009
	$		$
Sanand/Miroli		1,300,000		--
Ankleshwar		734,000		--
		2,034,000		--

Subsequent to December 31, 2010, the term deposit securing the bank guarantee amounting to $1,300,000 included in the current portion of restricted deposits has been released.

5.         Property and Equipment

The amounts capitalized as oil and natural gas properties were incurred for the purchase, exploration and ongoing development of various properties.

	December 31, 2010 $			December 31, 2009 $
Oil and natural gas properties (using the full-cost method)
Unproved properties		47,715,032			51,890,959
Proved properties		17,702,000			4,313,000
Total oil and natural gas properties		65,417,032			56,203,959
Building		889,609			889,609
Computer, office and other equipment		602,917			583,067
Total property and equipment		66,909,588			57,676,635
Accumulated impairment of oil and natural gas properties		(23,887,015	)		(10,098,015	)
Accumulated depletion		(1,060,700	)		(293,700	)
Accumulated depreciation		(586,163	)		(471,916	)
Total property and equipment, net		41,375,680			46,813,004

The oil and natural gas properties consist of contract interests in 10 exploration blocks in India, 3 exploration licenses held in Israel and 2 exploration licenses held in Colombia.

The Company has capitalized $599,234 (2009 - $1,098,345) of general and administrative costs directly related to exploration activities, including $252,335 (2009 - $662,420) of stock-based compensation expense.  In addition, the Company has capitalized $56,943 (2009 - $50,599) of support equipment depreciation.

Impairment of Oil and Gas Properties

The Company performed a ceiling test calculation at December 31, 2010, to assess the ceiling limitation of its proved oil and natural gas properties.  At December 31, 2010, the Company’s net capitalized costs of proved oil and natural gas properties did exceed the ceiling limitation.  Accordingly, for the year ended December 31, 2010, the Company charged $13,789,000 (December 31, 2009 - $Nil and December 31, 2008 - $10,098,015) to the statement of operations for impairment charges. The impairment charge of $13,789,000 was recognized in the fourth quarter of 2010 as a result of ceiling limitation as at December 31, 2010.

FS 13

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

6.         Asset Retirement Obligation

Asset retirement obligations are recorded for legal obligations where the Company will be required to retire, dismantle, abandon and restore tangible long-lived assets.

The following table summarizes the changes in the asset retirement obligation:

	December 31, 2010 $			December 31, 2009 $
Asset retirement obligation at beginning of year		775,000			633,598
Liabilities incurred		--			85,783
Liabilities released		(136,145	)		--
Accretion expense		41,289			55,619
Asset retirement obligation at end of year		680,144			775,000

For the year ended December 31, 2010, no new obligations were incurred.  In determining the fair value of the asset retirement obligations, the estimated cash flows of new obligations incurred during the year ended December 31, 2009 have been discounted at 10%.  The total undiscounted amount of the estimated cash flows required to settle the obligations is $1,543,000 (2009 – $1,874,000), which is expected to be paid after five years.  The obligations will be settled on an ongoing basis over the useful lives of the operating assets, which extend up to 20 years in the future.

7.         Fair Value Measurements

The carrying values of cash and cash equivalents, accounts receivable, restricted deposits, accounts payable, accrued liabilities and amounts due to related companies approximate their estimated fair value due to their short term to maturity.

8.         Capital Stock

On October 15, 2010, the Company completed a registered direct offering and issued 7,000,000 common stock to an institutional investor at a price of $0.85 per common share for aggregate gross proceeds of $5,950,000.  The total share issuance costs of $161,850 associated with the offering were fully allocated to the common stock and recorded as share issuance costs and reduced additional paid-in capital.

On October 18, 2010, the Company completed a registered direct placement with an institutional investor pursuant to which the Company issued 2,941,177 Units at a price of $0.85 per Unit for aggregate gross proceeds of $2,500,000.  The 2,941,177 Units consist of 2,941,177 common stock, 1,470,588 callable warrants and 1,470,588 non-callable warrants.  The holder of each callable and non-callable warrant is entitled to subscribe for and purchase one common share of the Company at an exercise price of $1.00 per common share and the warrants are exercisable for a period beginning April 11, 2011 and expiring October 15, 2015.  The callable warrants may be called for cancellation by the Company for $0.001 per common share if the volume weighted average price of a share of common stock for each of 30 consecutive trading days (the “Measurement Period”) exceeds $3.00 and the average daily volume for such Measurement Period exceeds $350,000 per trading day.  The placement agent on this transaction was paid a cash fee of 6% of the aggregate gross proceeds raised in the placement totaling $150,000 and $20,000 towards reimbursement for certain of its expenses.  In addition, the Company issued the placement agent 176,471 warrants to purchase up to 176,471 common stock of the Company at an exercise price of $1.00 per common share.

The proceeds from the issuance of the Units have been allocated between the common stock and the warrants based on their fair value.  The fair value of the common share was determined based on the market price of the stock the day the registered direct placement closed.  The fair value of the warrants was based on a Black-Scholes option-pricing model and the following weighted average assumptions as at the date of the registered direct placement closing as follows:

Risk-free interest rate	1.20%
Expected life	5.0 years
Expected volatility	104.7%
Expected dividend yield	0%

The resulting allocation of the fair value to the common stock and the warrants (included as additional paid-in capital) was $507,000 and $1,993,000 respectively.

FS 14

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

8.         Capital Stock (continued)

The total share issuance costs of $301,954 associated with the offering of the Units were recorded as share issuance costs and reduced additional paid-in capital and allocated to the common stock and the warrants as follows:

	Common stock			Warrants			Total
	$			$			$
Proceeds from the Unit offering		507,000			1,993,000			2,500,000
Issuance costs for the Unit offering		(61,236	)		(240,718	)		(301,954	)
		445,764			1,752,282			2,198,046

9.         Warrants

From time to time, the Company may issue compensation options, compensation warrants and or warrants (collectively the “Warrants”) in connection with a finance offering as an incentive to participate in such offerings.  The fair value of any Warrants issued is recorded as additional paid-in capital.  The fair value of the Warrants is determined using the Black-Scholes option pricing model.

Activity with respect to all warrants is presented below for the years ended December 31, 2010, 2009 and 2008:

	2010		2009		2008
	Warrants #	Weighted Average Exercise Price $	Warrants #	Weighted Average Exercise Price $	Warrants #	Weighted Average Exercise Price $
Outstanding warrants at the beginning of year	5,599,716	7.91	5,599,716	7.91	5,599,716	7.91
Warrants granted (note 8)	3,117,647	1.00	--	--	--	--
Warrants exercised	--	--	--	--	--	--
Warrants outstanding at the end of year	8,717,363	5.44	5,599,716	7.91	5,599,716	7.91
Exercisable at the end of year	5,599,716	7.91	5,599,716	7.91	5,599,716	7.91

The weighted average remaining life and exercise price as of December 31, 2010 is summarized below:

Warrants	Outstanding Warrants #	Weighted Average Remaining Life (Months)	Exercisable  Warrants #	Weighted Average Exercise Price $
Compensation Options	535,944	5.6	535,944	5.55
Compensation Warrants	97,572	5.6	97,572	9.00
Share Purchase Warrants	8,083,847	25.6	4,966,200	5.39
	8,717,363	24.2	5,599,716	5.44

The Warrants have certain terms and conditions as follows:

Compensation options enable the holder to purchase one fully-paid non-assessable common share of the Company at a specified price up to June 20, 2011.  Certain compensation options consist of one compensation option and one-half of one common share purchase warrant referred to as compensation warrants;

Compensation warrants enable the holder to purchase one fully-paid non-assessable common share of the Company at a specified price up to June 20, 2011; and

Share Purchase Warrants enable certain holders to purchase one fully-paid non-assessable common share of the Company at a specified price up to June 20, 2011 and one half of one common share callable warrant and one-half of one common share non-callable warrant at a specified price up to October 15, 2015.

FS 15

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

9.         Warrants (continued)

Warrant Modification

On May 26, 2009, the Board of Directors approved a two-year extension for all compensation options, Compensation Warrants and Share Purchase Warrants from June 20, 2009 to June 20, 2011.  The Company has recorded the incremental difference in the fair value of the original and modified instruments on the date of modification.  The fair value of the modified instruments was determined using a Black-Scholes option-pricing model using the following assumptions prior to and as at the date of extension:

	June 20, 2009	September 9, 2007	September 6, 2007
Risk-free interest rate	1.25%	4.08%	4.28%
Expected life	2.0 years	22 months	4 days
Expected volatility	127.7%	75%	134%
Expected dividend yield	0%	0%	0%

The resulting incremental fair value of $1,754,000 associated with the Stock Purchase Warrants was recorded as a charge to the deficit in the year ended December 31, 2009, with a corresponding entry to additional paid-in capital.  The resulting incremental fair value of the Compensation Options and the Compensation Warrants of $264,000 was recorded as a charge to general and administrative expense in the year ended December 31, 2009, with a corresponding entry to additional paid-in capital.

10.         Stock Options

The Company’s 1998 stock incentive plan (1998 Plan)

Under the terms of the 1998 Plan, as amended, 12,000,000 common stock were reserved for issuance on exercise of options granted under the 1998 Plan.  The 1998 Plan terminated on December 4, 2008 and as such, there are no options to be granted under the 1998 Plan, however, as at December 31, 2010, there are 1,800,000 options that were granted prior to December 4, 2008 which are currently outstanding and are able to be exercised.

The Company’s 2008 stock incentive plan (2008 Plan)

Under the terms of the 2008 Plan, 12,000,000 common stock have been reserved for issuance on exercise of options granted under the 2008 Plan.  As at December 31, 2010, the Company had 9,250,000 common stock remaining for the grant of options under the 2008 Plan.  The Board of Directors of the Company may amend or modify the 2008 Plan at any time, subject to any required stockholder approval.  The 2008 Plan will terminate on the earliest of: (i) May 30, 2018; (ii) the date on which all shares available for issuance under the 2008 Plan have been issued as fully-vested shares; or, (iii) the termination of all outstanding options in connection with certain changes in control or ownership of the Company.

Stock-based compensation

The Company is required to recognize compensation cost for stock-based compensation arrangements with employees, non-employee consultants and non-employee directors based on their fair value using the Black-Scholes option-pricing model, such cost to be expensed over the respective vesting periods.  For awards with graded vesting, in which portions of the award vest in different periods, the Company recognizes compensation costs over the vesting periods for each separate vested tranche.

The following table summarizes stock-based compensation for employees, non-employee consultants and independent directors:

	Year ended Dec 31, 2010 $		Year ended Dec 31, 2009 $		Year ended Dec 31, 2008 $			Period from Inception, Aug 21, 2002  to Dec 31, 2010 $
Stock-based compensation
Consolidated Statements of Operations
General and administrative		700,433		778,845		674,547			4,132,128
Consulting fees		17,196		139,840		(48,290	)		3,416,088
		717,629		918,685		626,257			7,548,216
Consolidated Balance Sheets
Property and equipment		252,335		662,420		477,959			5,410,003
		969,964		1,581,105		1,104,216			12,958,219

FS 16

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

10.         Stock Options (continued)

At December 31, 2010, the total compensation cost related to non-vested awards not yet recognized was $318,649 (December 31, 2009 – $382,483 and December 31, 2008 - $1,719,349) which will be recognized over a weighted-average period of nine months.  During the years ended December 31, 2010 and 2009, no options were exercised.  During the year ended December 31, 2008, 600,000 options were exercised for total gross proceeds of $660,000.

No income tax benefit has been recognized relating to stock-based compensation expense and no tax benefits have been realized from the exercise of stock options.

The fair value of each option granted was estimated on the date of grant using the Black-Scholes option-pricing model.  Weighted average assumptions used in the valuation are disclosed in the following table:

	Year ended Dec 31, 2010	Year ended Dec 31, 2009	Year ended Dec 31, 2008
Fair value of stock options granted (per option)	$0.90	$0.66	$1.25
Risk-free interest rate	2.6%	1.5%	1.3%
Volatility	129.7%	115.0%	102.0%
Expected life	8.4 years	3.3 years	3.8 years
Dividend yield	0%	0%	0%

Stock option table

Activity with respect to all stock options is presented below for the years ended December 31, 2010, 2009 and 2008:

	2010					2009					2008
	Shares #			Weighted Average Exercise Price $		Shares #			Weighted Average Exercise Price $		Shares #			Weighted Average Exercise Price $
Options outstanding at beginning of year		4,440,000			3.48		5,325,000			3.69		4,470,000			4.04
Options granted		1,280,000			1.58		280,000			1.15		1,575,000			1.94
Options exercised		--			--		--			--		(600,000	)		1.10
Options expired		(1,060,000	)		5.03		(1,060,000	)		4.03		(110,000	)		6.50
Forfeitures and cancellations		(110,000	)		1.72		(105,000	)		2.67		(10,000	)		7.52
Options outstanding at end of year		4,550,000			2.72		4,440,000			3.48		5,325,000			3.69
Outstanding aggregate intrinsic value	$	25,000				$	711,700				$	--
Exercisable at end of year		3,252,500			3.04		3,487,500			3.99		3,610,000			4.37
Exercisable aggregate intrinsic value	$	--				$	240,325				$	--

The weighted average remaining life by exercise price as of December 31, 2010 is summarized below:

Range of Exercise Prices $	Outstanding Shares #	Weighted Average Remaining Life Months	Exercisable Shares #	Weighted Average Exercise Price $
0.01 - 0.99	250,000	116.6	--	0.69
1.00 - 1.99	1,853,800	39.7	1,452,500	1.61
2.00 - 2.99	323,800	112.9	--	2.25
3.00 - 4.99	1,672,400	76.1	1,350,000	3.83
5.00 - 5.99	400,000	65.7	400,000	5.07
6.00 - 6.99	50,000	48.0	50,000	6.81
	4,550,000	64.9	3,252,500	2.72

FS 17

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

11.           Related Party Transactions

Related party transactions are measured at the exchange amount which is the amount of consideration established and agreed by the related parties.

Roy Group (Mauritius) Inc.

In March 2003, the Company entered into a Participating Interest Agreement with Roy Group (Mauritius) Inc. (a corporate entity controlled by a director and principal stockholder of the Company), whereby the Company assigned and holds in trust for Roy Group (Mauritius) Inc. 50% of the benefits and obligations of the production sharing contract covering the KG Offshore Block leaving the Company with a net 5% participating interest in the KG Offshore Block.  The assignment of interest is subject to approval by the Government of India.

Under the terms of the Participating Interest Agreement and until approval by the Government of India, the Company retains the exclusive right to deal with Roy Group (Mauritius) Inc. to the KG Offshore Block and is entitled to make all decisions regarding the interest assigned to Roy Group (Mauritius) Inc.  The Company has a right of set-off against sums owing to GeoGlobal by Roy Group (Mauritius) Inc.  In the event that the Government of Indian consent is delayed or denied, resulting in either Roy Group (Mauritius) Inc. or the Company being denied an economic benefit it would have realized under the Participating Interest Agreement, the parties agreed to amend the Participating Interest Agreement or take other reasonable steps to assure that an equitable result is achieved consistent with the parties’ intentions contained in the Participating Interest Agreement.

Roy Group (Barbados) Inc. (RGB)

RGB is a corporate entity controlled by a director and principal stockholder of the Company.  Effective August 18, 2010, RGB charges consulting fees based on the time expended to provide technical services to the Company as assigned by the Company and to bring new oil and gas opportunities to the Company.  From the period of August 29, 2003 to August 17, 2010, RGB provided services under a Technical Services Agreement for consideration of $350,000 per year.  Consulting fees paid to RGB are as outlined and recorded below:

	Year ended Dec 31, 2010		Year ended Dec 31, 2009		Year ended Dec 31, 2008		Period from Inception, Aug 21, 2002 to Dec 31, 2010
	$		$		$		$
Consolidated Statements of Operations
Consulting fees		209,179		262,500		175,000		915,346
Consolidated Balance Sheets
Property and equipment		141,532		87,500		175,000		1,478,698
		350,711		350,000		350,000		2,394,044

No options were granted during the years ended December 31, 2010, 2009 and 2008 to the principal of RGB.

At December 31, 2010, the Company owed RGB $16,200 (December 31, 2009 - $63,087) for services provided and expenses incurred on behalf of the Company.  These amounts bear no interest and have no set terms of repayment.

D.I. Investments Ltd. (DI)

DI is a corporate entity controlled by an officer of the Company.  DI charged consulting fees to the Company up to August 17, 2010 for management, financial and accounting services rendered.  Subsequent to August 17, 2010, the officer’s compensation is included in general and administrative expenses.  Consultancy fees paid to DI are as outlined and recorded below:

	Year ended Dec 31, 2010		Year ended Dec 31, 2009		Year ended Dec 31, 2008		Period from Inception, Aug 21, 2002 to Dec 31, 2010
	$		$		$		$
Consolidated Statements of Operations
Consulting fees		133,827		212,750		212,750		1,261,042

No options were granted during the years ended December 31, 2010, 2009 and 2008 to the principal of DI.

At December 31, 2010, the Company owed DI $nil (December 31, 2009 – $35,907) as a result of services provided and expenses incurred on behalf of the Company.  These amounts bear no interest and have no set terms of repayment.

FS 18

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

11.         Related Party Transactions (continued)

Amicus Services Inc. (Amicus)

Amicus is related to the Company by virtue of being controlled by a brother of a director and principal stockholder of the Company.  Amicus charged consulting fees to the Company for IT and computer-related services rendered, as outlined and recorded below:

	Year ended Dec 31, 2010		Year ended Dec 31, 2009		Year ended Dec 31, 2008		Period from Inception, Aug 21, 2002 to Dec 31, 2010
	$		$		$		$
Consolidated Statements of Operations
Consulting fees		51,783		55,782		89,204		392,476

On May 27, 2010, 60,000 options were granted to the principal of Amicus at exercise prices of $1.50 for 20,000 options, $2.25 for 20,000 options and $3.00 for 20,000 options which expire on May 27, 2020 and 30,000 options vested on December 31, 2010 and 30,000 options vest on June 30, 2011.  No options were granted during the year ended December 31, 2009.  On December 18, 2008, 60,000 options were granted to the principal of Amicus at an exercise price of $1.72 which expire on December 31, 2011 and 30,000 options vested on each of March 31, 2009 and March 31, 2010, respectively.  The compensation cost (recovery) for stock-based compensation arrangements is outlined and recorded below:

Consolidated Statements of Operations
Consulting fees	27,231	39,489	(30,580	)	652,345

At December 31, 2010, the Company owed Amicus $11,355 (December 31, 2009 - $24,560) as a result of services provided and expenses incurred on behalf of the Company.  These amounts bear no interest and have no set terms of repayment.

12.         Per Share Amounts

The following table presents the reconciliation between basic and diluted income per share:

	Year ended Dec 31, 2010 $			Year ended Dec 31, 2009 $			Year ended Dec 31, 2008 $
Net loss for the year		(18,788,624	)		(4,424,247	)		(13,313,915	)
Stock purchase warrant modification		--			(1,754,000	)		--
Net loss available to common stockholders		(18,788,624	)		(6,178,247	)		(13,313,915	)
Weighted average number of common stock outstanding:
Basic		74,878,761			68,107,126			67,407,395
Impact of securities convertible into common stock		658,423			19,014			502,013
Diluted		75,537,184			68,126,140			67,909,408
Per share amounts
Basic and diluted		(0.25	)		(0.09	)		(0.20	)
Securities excluded from denominator as anti-dilutive:
Stock options		4,020,000			4,160,000			3,950,000
Warrants		4,966,200			4,966,200			4,966,200
Compensation options		535,944			535,944			535,944
Compensation option warrants		97,572			97,572			97,572
		9,619,716			9,759,716			9,549,716

FS 19

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

13.         Income Taxes

Income tax expense

The Company or its subsidiaries operate in the United States, Canada, Barbados and India and the Company is subject to taxation in each of these jurisdictions.  The income tax expense (benefit) reported differs from the amount computed by applying the United States statutory rate to income (loss) before income taxes for the following items:

	Year ended Dec 31, 2010			Year ended Dec 31, 2009			Year ended Dec 31, 2008			Period from Inception, Aug 21, 2002 to Dec 31, 2010
	$			$			$			$
Net loss before tax		(18,682,124	)		(4,424,246	)		(13,313,915	)		(44,378,547	)
US statutory tax rate		34.0	%		35.0	%		35.0	%		-
Expected income tax benefit		(6,351,922	)		(1,548,486	)		(4,659,870	)		(15,346,653	)
Excess of US statutory tax rate over foreign tax rate		4,834,656			244,407			3,472,516			8,986,796
Non-deductible expenditures		577,343			496,471			256,544			3,302,511
Expiry of capital  losses		--			--			2,061,731			2,061,731
Expiry of non-capital losses		--			--			--			2,175,950
Acquisition and utilization of losses		--			--			--			(4,467,769	)
Tax rate differential and valuation allowance		368,262			150,479			--			52,909
Other		10,203			(11,346	)		(16,049	)		227,894
		(561,458	)		(668,475	)		(1,114,872	)		(3,006,631	)
Valuation allowance		667,958			668,475			1,114,872			3,113,131
Total income tax expense		106,500			--			--			106,500

The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing tax benefits.  There are no unrecognized tax benefits that if recognized would affect the tax rate.  The Company or one of its subsidiaries files income tax returns in the U.S. federal jurisdiction, state jurisdictions and other foreign jurisdictions.  The Company is no longer subject to US federal or non-US income tax examinations for years before 2006.  There are no income tax examinations currently in process.

Deferred income taxes

The Company provides for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse.  Significant components of the Company’s deferred tax assets and liabilities that result from loss carry forwards and temporary differences between the financial statement basis and tax basis of assets and liabilities are summarized as follows:

	Year ended Dec 31, 2010 $			Year ended Dec 31, 2009 $
Difference between tax base and reported amounts of depreciable assets		465,118			550,730
Non-capital loss carry forwards		2,585,415			1,892,845
		3,050,533			2,443,575
Valuation allowance		(3,111,533	)		(2,443,575	)
Deferred income tax asset/(liability)		(61,000	)		--

To date, the Company has incurred operating losses since inception.  This general pattern does not allow the Company to project sufficient sources of future taxable income to offset our net deferred tax assets.  Under these current circumstances, it is management’s opinion that the realization of these tax attributes does not reach the “more likely than not” criteria, and as a result, a valuation allowance has been recorded to off-set the net deferred tax asset at December 31, 2010.

FS 20

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

13.         Income Taxes (continued)

Loss carry forwards

At December 31, 2010, the Company has non-capital loss carry forwards to reduce taxable income for income tax purposes in the various jurisdictions as outlined below which have not been reflected in these consolidated financial statements:

Tax Jurisdiction	Amount $	Expiry Dates Commence (year)
United States	7,056,000	2023
Canada	337,000	2026
Barbados	4,085,000	2013
	11,478,000

At December 31, 2010, there are no capital losses to carry forward.

14.         Segmented Information

The majority of the Company’s oil and natural gas exploration activities is conducted in India.  All of the oil and gas sales are generated from India and are sold within the India markets.  Management of the Company considers the operations of the Company as one operating segment.  The following information relates to the Company’s geographic areas of operation.

	December 31, 2010 $		December 31, 2009 $
Property and equipment, net
India		39,693,301		46,703,331
Israel		1,459,476		--
Colombia and Canada		222,903		109,673
		41,375,680		46,813,004

15.         Commitments

Pursuant to current production sharing and other contracts, the Company is required to perform minimum exploration activities that include various types of surveys, acquisition and processing of seismic data and drilling of exploration wells.  These obligations have not been provided for in the financial statements.

The anticipated payments due under these agreements in effect at December 31, 2010 are as follows:

	Operating Leases	Production Sharing Contracts
	$	$
2011	192,000	11,052,000
2012	192,000	9,289,000
2013	16,000	7,412,000
2014 and thereafter	--	--
	400,000	27,753,000

In June 2010, Oil India Limited, the operator of the KG Onshore Block, approved an increase of the Company’s participating interest from 10% to 20%, subject to Government of India approval.  If approval is granted, the Company’s commitments would increase by $1.80 million in 2011, $2.27 million in 2012 and $5.23 million in 2013.  To date, approval has not been granted.

Subsequent to December 31, 2010, and pursuant to licenses relating to the Company’s Israeli interests, the Company’s commitments increased by approximately $2.1 million in 2011.

The Company has an office lease commitment in Calgary, Alberta, Canada which expires January 2013.

FS 21

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

16.         Contingencies

GSPC Dispute

GSPC, the operator of the KG Offshore Block in which the Company has a net 5% carried interest, has been seeking from the Company, payment of its pro rata portion of the amount by which the sums expended by GSPC under all phases for the minimum work program as set forth in the PSC for the KG Offshore Block in carrying out exploration activities on the block exceeds the amount that GSPC deems to be the Company’s pro rata portion of a financial commitment under all phases included in the parties’ joint bid for the award of the KG Offshore Block by the Government of India.

GSPC contends that this excess amount is not within the terms of the Carried Interest Agreement and asserts that the Company is required to pay 10% of the exploration expenses over and above gross costs of $109.7 million (10% being $10.97 million) (including the net 5% interest of Roy Group (Mauritius) Inc.) plus interest.

GSPC advised the Company on November 5, 2008 that the minimum work program for the KG Offshore Block had been completed in September 2008.  Further, GSPC elected to undertake an additional work program over and above the minimum work program as either Joint Operations or as Exclusive Operations under the terms of the PSC and advised that the Company must elect whether to participate in these additional exploration activities as a Joint Operation or alternatively, GSPC would conduct these drilling activities as Exclusive Operations, as defined in the PSC.

On November 13, 2008 the Company advised GSPC that it exercised its right to participate in the drilling operations proposed in the November 5, 2008 GSPC letter as a Joint Operation under the terms of the PSC and Joint Operating Agreement and  pursuant to the terms of our Carried Interest Agreement with GSPC.  As such, the Company continues to be of the view that it is carried for 100% of its entire share of any and all costs during the additional exploration phase prior to the start of initial commercial production and that the Carried Interest Agreement extends through the exploration period of the PSC.

In August 2010 GSPC advised the Company that it is of the view that the technical and other advice provided by the Company in the preparation of the parties’ original bid document submitted to the Government of India in 2002 under NELP-III has proven to be incorrect causing GSPC’s costs in the project to exceed its estimate.  GSPC asserts that by reason of the foregoing the Carried Interest Agreement between the parties is void and consequently the PSC to which the Government of India is party and the Joint Operating Agreement are also void.

The Company has advised GSPC that under the terms of the Carried Interest Agreement (the terms of which are also incorporated into the PSC and the Joint Operating Agreement) they have no right to such payment under the Carried Interest Agreement.  The Company has advised GSPC that the Company fulfilled its obligations under the Carried Interest Agreement to provide extensive technical assistance without any further remuneration other than the carried interest, all in accordance with the terms of the Carried Interest Agreement.  The Company obtained the opinion of prominent Indian legal counsel who has advised that under the terms of the agreements between the parties, and in particular the Carried Interest Agreement, the Company is not liable to pay any amount to GSPC for costs or expenses incurred or otherwise before reaching the stage of commercial production.

The Company disputes these positions of GSPC and the conclusions reached by GSPC and continue to state that the Company holds a gross 10% interest in the KG Offshore Block (including the 5% interest of Roy Group (Mauritius) Inc.).  In a KG Offshore Block Management Committee meeting held in October, 2010, the Management Committee (of which the Government of India is a member) advised GSPC to resolve these issues with the Company at the earliest and requested GSPC to maintain status quo until the issues are resolved.

Based upon the audited accounts of the joint venture for the KG Offshore Block, the total costs incurred to March 31, 2010 were $1.447 billion (10% being $144.7 million of which 50% is for the account of Roy Group (Mauritius) Inc.).  Further, based upon the budget for the fiscal year April 1, 2010 to March 31, 2011, total costs projected were $601 million with approximately $446 million spent by December 31, 2010 (10% being $60.1 million and $44.6 million respectively).  Therefore, management estimates that the amount of GSPC’s claim as of December 31, 2010 to be approximately $189 million plus interest of which 50% is for the account of Roy Group (Mauritius) Inc.  The Company disputes this assertion of GSPC.

The Company intends to vigorously protect its contractual rights in accordance with the dispute resolution process under the Carried Interest Agreement, the PSC and the Joint Operating Agreement as may be appropriate.  In September 2007, the Company commenced discussions with GSPC in an effort to reach an amicable resolution.  A number of draft settlement proposals have been put forward by the Company to GSPC seeking to settle this dispute amicably.  Subsequent to the October 2010 Management Committee meeting the Company’s management has again met with senior management of GSPC to continue its effort to reach an amicable resolution.  However, no settlement agreement has been reached as of March 30, 2011 and there can be no assurance that this matter will be settled amicably.

FS 22

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

16.         Contingencies (continued)

Other Matters

The Company previously determined that one of its subsidiaries was in breach of certain regulatory requirements of the jurisdiction of its organization.  The subsidiary’s non-compliance with these regulations may have resulted in a financial penalty being imposed against the subsidiary in an amount in the range of anywhere from $nil to $3.2 million at the discretion of the regulatory authority.  The Company took appropriate steps to remedy the matter and as a result of the steps taken, the Company paid a financial penalty of $3,000 and this matter is now fully resolved.

17.         Supplemental Disclosure of Cash Flow Information

Changes in non-cash working capital were as follows:

	Year ended Dec 31, 2010			Year ended Dec 31, 2009			Year ended Dec 31, 2008
	$			$			$
(Increase) decrease in non-cash working capital
Accounts receivable		(2,253,149	)		165,611			(57,665	)
Prepaids and deposits		(225,086	)		68,741			(142,007	)
Accounts payable		(1,899,551	)		3,886,099			939,007
Accrued liabilities		485,890			(3,133,977	)		1,975,269
Due to related companies		(95,999	)		90,638			(33,236	)
Net change in non-cash working capital		(3,987,895	)		1,077,112			2,681,368
Relating to:
Operating activities		(711,636	)		714,647			(593,494	)
Investing activities		(3,276,259	)		362,465			3,274,862
		(3,987,895	)		1,077,112			2,681,368

18.           Supplementary Oil and Gas Information (Unaudited)

This supplementary oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas”.

Net Proved Oil and Natural Gas Reserves

The Company retains qualified independent reserves evaluators to evaluate the Company’s proved oil and natural gas reserves.

·   For the years ended December 31, 2010 and 2009 the reports by Chapman Petroleum Engineering Ltd. (“Chapman”) covered 100% of the Company’s oil and natural gas reserves.

·   For the year ended December 31, 2008 the Company had no oil and natural gas reserves.

Proved oil and natural gas reserves, as defined within the SEC Rule 4-10(a)(22) of Regulation S-X, are those quantities of oil and gas, which, by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time of which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether determinable or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  Developed oil and natural gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate is the extraction is by means not involving a well.

Estimates of oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change.

FS 23

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

18.           Supplementary Oil and Gas Information (Unaudited) (continued)

The following table summarizes the Company’s proved developed and undeveloped oil and natural gas reserves within India, net of royalties, as at December 31, 2010, 2009 and 2008:

Oil (MBbls)	2010			2009			2008
Proved reserves as at January 1		118			--			--
Extensions and discoveries		--			131			--
Production		(11	)		(13	)		--
Revision of prior estimates		(52	)		--			--
Proved Reserves as at December 31		55			118			--
Proved - developed:
Producing		55			100			--
Non producing		--			18			--
Proved - undeveloped		--			--			--
Reserves, as at December 31		55			118			--

Natural Gas (MMcf)	2010			2009			2008
Proved reserves as at January 1		89			--			--
Extensions and discoveries		--			105			--
Production		(22	)		(16	)		--
Revision of prior estimates		88			--			--
Proved Reserves as at December 31		155			89			--
Proved - developed:
Producing		155			89			--
Non producing		--			--			--
Proved - undeveloped		--			--			--
Reserves, as at December 31		155			89			--

Capitalized Costs Related to Oil and Natural Gas Properties

	$	2010	$	2009	$	2008
Proved properties		17,702,000		4,313,000		--
Unproved properties		47,715,032		51,890,959		44,182,707
		65,417,032		56,203,959		44,182,707
Less:  Accumulated impairment		23,887,015		10,098,015		10,098,015
Less:  Accumulated depletion		1,060,700		293,700		--
Net capitalized costs		40,469,317		45,812,244		34,084,692

FS 24

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

18.           Supplementary Oil and Gas Information (Unaudited) (continued)

Cost Incurred in Oil and Natural Gas Activities

	$	2010	$	2009	$	2008
Development
India		7,618,315		4,313,000		--
Exploration
India		--		7,708,252		7,991,673
Israel		1,459,476		--		--
Colombia		135,282		--		--
Costs incurred		9,213,073		12,021,252		7,991,673

Standardized Measure of Discounted Future Net Cash Flows From Proved Oil and Natural Gas Reserves and Changes Therein

The following standardized measure of discounted future net cash flows from proved oil and natural gas reserves has been computed using the average first-day-of-the-month price during the previous 12-month period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including:

·   Future production will include production not only from proved properties, but may also include production from probable and possible reserves;

·   Future production of oil and natural gas from proved properties may differ from reserves estimated;

·   Future production rates may vary from those estimated;

·   Future rather than average first-day-of-the-month prices during the previous 12-month period and costs as at the balance sheet date will apply;

·   Economic factors such as changes to interest rates, income tax rates, regulatory and fiscal environments and operating conditions cannot be determined with certainty;

·   Future estimated income taxes do not take into account the effects of future exploration expenditures; and

·   Future development and asset retirement obligations may differ from those estimated.

Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 – “Extractive Activities – Oil and Gas”:

	$	2010		$	2009		$	2008
Future cash inflows		5,208,000			11,567,000			--
Future operating costs		(1,513,000	)		(2,637,000	)		--
Future asset retirement obligations		(84,000	)		(84,000	)		--
Future income taxes		--			(110,000	)		--
Future net cash flows		3,611,000			8,736,000			--
10% discount factor		(755,000	)		(2,932,000	)		--
Standardized measure		2,856,000			5,804,000			--

FS 25

GeoGlobal Resources Inc.

(a development stage enterprise)

Notes to the Consolidated Financial Statements

December 31, 2010

19.         Selected Quarterly Information (Unaudited)

The following represents selected quarterly financial information for 2010 and 2009:

	For the three months ended
	March 31			June 30			September 30			December 31
	$			$			$			$
2010
Oil and gas sales		191,217			234,672			220,435			144,018
Interest income		18,355			11,302			9,958			12,992
Net loss		(1,028,044	)		(1,084,673	)		(1,167,928	)		(15,480,971	)
Net loss per share – basic and diluted		(0.01	)		(0.01	)		(0.02	)		(0.21	)
2009
Oil and gas sales		--			190,048			300,394			171,480
Interest income		114,096			83,933			65,169			36,352
Net loss		(1,166,896	)		(1,146,442	)		(900,305	)		(1,210,604	)
Net loss per share – basic and diluted		(0.02	)		(0.04	)		(0.01	)		(0.02	)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

GeoGlobal Resources Inc.

By:           /s/ Sunil Karkera                                           

Sunil Karkera

Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Company and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Paul B. Miller Paul B. Miller	Director, President and Chief Executive Officer	March 31, 2011
/s/ Sunil Karkera Sunil Karkera	Chief Financial Officer “Chief Accounting Officer”	March 31, 2011
/s/ Jean Paul Roy Jean Paul Roy	Director	March 31, 2011
/s/ Brent J. Peters Brent J. Peters	Director	March 31, 2011
/s/ Peter R. Smith Peter R. Smith	Chairman of the Board and Director (On leave)	March 31, 2011
/s/ Michael J. Hudson Michael J. Hudson	Director	March 31, 2011
/s/ David D. Conklin David D. Conklin	Director (and Interim Chairman of the Board)	March 31, 2011
/s/ Anoop Poddar Anoop Poddar	Director	March 31, 2011

EX-10.35

Exhibit 10.35

REPORT OF INDEPENDENT PETROLEUM ENGINEERS

RESERVE AND ECONOMIC EVALUATION

OIL AND GAS PROPERTY

TARAPUR AREA

INDIA

Owned by

GEOGLOBAL RESOURCES INC.

January 1, 2011

(December 31, 2010)

February 22, 2011

GeoGlobal Resources Inc.

200, 625 - 4th Avenue SW

Calgary, AB

T2P 0K2

Attention:  Mr. Sunil Karkera

Dear Sir:

Re:         GeoGlobal Resources Inc.

Reserve and Economic Evaluation – January 1, 2011                                                                                                   

In accordance with your authorization we have performed a reserve and economic evaluation of oil and gas properties owned by GeoGlobal Resources Inc. (the "Company") for an effective date of January 1, 2011 (as of December 31, 2010).

This evaluation has been carried out in accordance with the guidelines of Regulation S-X, Rule 4 -10 (a) of the Securities Exchange Act, with respect to the classification of Proved and Probable Reserves, in conjunction with the standards set out in the Canadian Oil and Gas Evaluation Handbook, Volume 1 – Second Edition (COGEH-1) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy and Petroleum (Petroleum Society).  The report has been prepared and/or supervised by a "Qualified Reserves Evaluator" as demonstrated on the accompanying Certificate of Qualification of the author(s).

The SCOPE OF REPORT contains the authorization and purpose of the report and describes the methodology and economic parameters used in the preparation of this report.

The SUMMARY OF RESERVES AND ECONOMICS (SEC) contains the results of the economic forecasts using the new pricing guidelines as defined in Regulation S-X 210.4-10 22 (v), and expressed in United States dollars for the proved and proved plus probable reserves, as applicable for SEC filing.

The DISCUSSION contains a description of the interests and burdens, reserves and geology, production forecasts, product prices, capital and operating costs and a map of each major property.  The economic results and cash flow forecasts (before income tax) are also presented on an entity and property summary level.

A REPRESENTATION LETTER from the Company, confirming that to the best of their knowledge all the information they provided for our use in the preparation of this report was complete and accurate as of the effective date, is enclosed following the Glossary.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.  We have no responsibility to update our report for events and circumstances which may have occurred since the preparation date of this report.

Prior to public disclosure of any information contained in this report, or our name as author, our written consent must be obtained, as to the information being disclosed and the manner in which it is presented.  This report may not be reproduced, distributed or made available for use by any other party without our written consent and may not be reproduced for distribution at any time without the complete context of the report, unless otherwise reviewed and approved by us.

We consent to the submission of this report, in its entirety, to securities regulatory agencies and stock exchanges, by the Company.

It has been a pleasure to prepare this report and the opportunity to have been of service is appreciated.

Yours very truly,

Chapman Petroleum Engineering Ltd.

[Original Signed By:]

C.W. Chapman

C.W. Chapman, P. Eng.,

President

[Original Signed By:]

Roy A. Collver

Roy A. Collver, P. Eng

Petroleum Engineer

CERTIFICATE OF QUALIFICATION

I, C. W. CHAPMAN, P. Eng., Professional Engineer of the City of Calgary, Alberta, Canada, officing at Suite 445, 708 – 11th Avenue S.W., hereby certify:

1. THAT I am a registered Professional Engineer in the Province of Alberta and a member of the Australasian Institute of Mining and Metallurgy.

2. THAT I graduated from the University of Alberta with a Bachelor of Science degree in Mechanical Engineering in 1971.

3. THAT I have been employed in the petroleum industry since graduation by various companies and have been directly involved in reservoir engineering, petrophysics, operations, and evaluations during that time.

4. THAT I have in excess of 25 years in the conduct of evaluation and engineering studies relating to oil & gas fields in Canada and around the world.

5. THAT I participated directly in the evaluation of these assets and properties and preparation of this report for GeoGlobal Resources Inc., dated February 22, 2011 and the parameters and conditions employed in this evaluation were examined by me and adopted as representative and appropriate in establishing the value of these oil and gas properties according to the information available to date.

6. THAT I have not, nor do I expect to receive, any direct or indirect interest in the properties or securities of GeoGlobal Resources Inc. its participants or any affiliate thereof.

7. THAT I have not examined all of the documents pertaining to the ownership and agreements referred to in this report, or the chain of Title for the oil and gas properties discussed.

8. A personal field examination of these properties was considered to be unnecessary because the data available from the Company's records and public sources was satisfactory for our purposes.

[Original Signed By:]

C.W. Chapman

C. W. Chapman, P.Eng.

President

CERTIFICATE OF QUALIFICATION

I, ROY A. COLLVER, of the City of Calgary, Alberta, Canada, officing at Suite 445, 708 – 11th Avenue S.W., hereby certify:

1. THAT I am a registered Engineer-In-Training in the Province of Alberta.

2. THAT I graduated from Queen’s University in Kingston, Ontario with a Bachelor of Science degree in Engineering Physics in 2005.

3. THAT I participated directly in the evaluation of these assets and properties and preparation of this report for GeoGlobal Resources Inc., dated February 22, 2011 and the parameters and conditions employed in this evaluation were examined by me and adopted as representative and appropriate in establishing the value of these oil and gas properties according to the information available to date.

4. THAT I have not, nor do I expect to receive, any direct or indirect interest in the properties or securities of GeoGlobal Resources Inc., its participants or any affiliate thereof.

5. THAT I have not examined all of the documents pertaining to the ownership and agreements referred to in this report, or the chain of Title for the oil and gas properties discussed.

6. A personal field examination of these properties was considered to be unnecessary because the data available from the Company’s records and public sources was satisfactory for our purposes.

[Original Signed By:]

Roy A. Collver

Roy A. Collver, P. Eng.

Petroleum Engineer

TABLE OF CONTENTS

Scope of Report

Authorization

Purpose

Reserve Definitions

Barrels of Oil Equivalent

Sources of Information

Product Sales Arrangements

Royalties

Capital Expenditures and Operating Costs

Income Tax Parameters

Economics

Constant Price Parameters

Summary of Company Reserves and Economics

Table 1:                      Summary of Company Reserves and Economics Before Tax

Table 1T:                      Summary of Company Reserves and Economics After Tax

SCOPE OF REPORT

Authorization

This evaluation has been authorized by Mr. Sunil Karkera, on behalf of GeoGlobal Resources Inc.   The engineering analysis has been performed during the months of January and February 2011.

Purpose

The purpose of this report was to prepare a third party independent appraisal of the oil and gas reserves owned by GeoGlobal Resources Inc. for the Company's financial planning and for filing with the SEC in the USA.

The values in this report do not include the value of the Company's undeveloped land holdings nor the tangible value of their interest in associated plant and well site facilities they may own.

Reserve Definitions

Proved and probable reserves as classified in the report have been based on Rule 4-10(a) of Regulation S-X of the Securities Exchange Act. The following definitions are considered to be consistent with the principles of COGEH and are compliant with the standards of NI 51-101:

Classification of Reserves

Proved Oil and Gas Reserves

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)   When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii)   Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii)   Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)   When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii)   Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii)   Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

        (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(iv)   Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(v)   Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Barrel of Oil Equivalent

If at any time in this report reference is made to “Barrels of Oil Equivalent” (BOE), the conversion used is 6 Mscf : 1 STB (6 Mcf : 1 bbl).

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf : 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.

Sources of Information

Source of the data used in the preparation of this report are as follows:

i)   Ownership and Burdens have been derived from the Company's land records and other information from the Company as required for clarification;

ii)   Production data is acquired from public data sources, except for very recent data or certain wells which are provided directly by the Company;

iii)   Well data is accessed from the Company's well files and from public data sources;

iv)   Operating Costs are based on actual revenue and expense statements provided by the Company for established properties or from discussions with the Company and our experience in the area for new or non-producing properties;

v)   Price differentials are derived from revenue statements, compared to actual posted prices for the appropriate benchmark price over a period of several months for established properties or from discussions with the Company and our experience in the area for new or non-producing properties;

vi)   Timing of Development Plans and Capital estimates are normally determined by discussions with the Company together with our experience and judgment.

Product Sales Arrangements

The Company does not have any "hedge" contracts in place at this time.

Royalties

A full provision for Crown royalties under the latest regulations and incentive programs for the Tarapur area have been included in this report.

Under the terms of the Production Sharing Agreement, all royalties and cess fees are paid by the licensee, OGNC.

Capital Expenditures and Operating Costs

Operating costs and capital expenditures have been based on historical experience and analogy where necessary and have not been escalated.

Income Tax Parameters

Net cash flows after consideration of corporate income tax have been included in this report.

The Company has a seven year income tax holiday on production from this area. Once the holiday period has expired, the Company can offset future income with their share of sunk exploration and development capital. Once all sunk capital is recovered, the net revenue from profit petroleum is taxable at a rate of 41.2%. The majority of operating costs are deductible.

Abandonment and restoration costs, net of salvage, have been accounted for in the cash flow forecasts for each level of reserves. Abandonment and restoration cost estimates have been based on discussions with the Company and analogy with similar fields in the area.

Economics

The economic analysis has been performed on a spread sheet format to account for all the terms of the PSC.

Constant Price Parameters

The price used for each area in this report, in accordance with SEC regulation S-X rule 4-10, was the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Adjustments for crude quality, gas heating value and NGL trucking and fractionation have still been applied to the average prices to reflect actual prices being received.  In addition, no escalation has been applied to either the capital expenditures or operating costs.

The average price shown in the cash flows may differ from year to year due to variations in the proportionate production volumes from each property relative to the total.

For the purpose of US Security Exchange Commission filing, the results of the Constant Prices and Cost case for proved and probable reserves are expressed in United States dollars are presented in the Summary of Reserves and Economics (SEC).

SUMMARY OF COMPANY RESERVES AND ECONOMICS

INDEX

Constant Prices and Costs (SEC S-X GUIDELINES)

Table 1:               Summary of Company Reserves and Economics – Before Tax

Table lT:               Summary of Company Reserves and Economics – After Tax

Table 1
Summary of Company Reserves and Economics
Before Income Tax
January 1, 2011
Geoglobal Resources Inc
		N e t   T o   A p p r a i s e d    I n t e r e s t
		Reserves							Cumulative Cash Flow (BIT) - M$
			Light and Medium		Sales Gas		NGL
			Oil  MSTB		MMscf		Mbbls		Discounted at:
Description			Gross	Net	Gross	Net	Gross	Net	Undisc.	5%/year	10%/year	15%/year	20%/year
Proved Developed Producing
	Tarapur wells (Kalol)		55	55	155	155	0	0	3,605	3,180	2,852	2,593	2,384
Total Proved Developed Producing			55	55	155	155	0	0	3,605	3,180	2,852	2,593	2,384
Probable
	Tarapur wells (Kalol)		418	409	617	595	0	0	18,133	13,678	10,618	8,442	6,847
Total Probable			418	409	617	595	0	0	18,133	13,678	10,618	8,442	6,847
Total Proved Plus Probable			473	464	772	750	0	0	21,738	16,858	13,470	11,035	9,231
M$ means thousands of dollars
"Gross reserves" means the total of GGR's working interest in the estimated field reserves before the deduction of the Government's share of production under the applicable production sharing agreement and before the deduction of all applicable royalties.
"Net reserves" means the total of GGR's working interest in the estimated resources after the deduction of the Government's share of production under the applicable production sharing agreement and after the deduction of all applicable royalties.
Columns may not add precisely due to accumulative rounding of values throughout the report.

Table 1T												Constant Prices & Costs
Summary of Company Reserves and Economics
After Income Tax
January 1, 2011
Geoglobal Resources Inc
		N e t   T o   A p p r a i s e d    I n t e r e s t
		Reserves							Cumulative Cash Flow  - M$
		Light and Medium			Sales Gas		NGL
			Oil  MSTB		MMscf		Mbbls		Discounted at:
Description			Gross	Net	Gross	Net	Gross	Net	Undisc.	5%/year	10%/year		15%/year	20%/year
Proved Developed Producing
	Total Proved Developed Producing (BIT)		55	55	155	155	0	0	3,605	3,180	2,852		2,593	2,384
	Company Income Tax		-	-	-	-	-	-	-	-	-		-	-
Total Proved Developed Producing (AIT)			55	55	155	155	0	0	3,605	3,180	2,852		2,593	2,384
Probable
	Total Probable (BIT)		418	409	617	595	0	0	18,133	13,678	10,618		8,442	6,847
	Company Income Tax		-	-	-	-	-	-	(2,406)	(1,475)	(937)		(613)	(413)
Total Probable (AIT)			418	409	617	595	0	0	15,727	12,203	9,681		7,829	6,434
Total Proved Plus Probable (AIT)			473	464	772	750	0	0	19,332	15,383	12,533		10,422	8,818
M$ means thousands of dollars
"Gross reserves" means the total of GGR's working interest in the estimated field reserves before the deduction of the Government's share of production under the applicable production sharing agreement and before the deduction of all applicable royalties.
"Net reserves" means the total of GGR's working interest in the estimated resources after the deduction of the Government's share of production under the applicable production sharing agreement and after the deduction of all applicable royalties.
Columns may not add precisely due to accumulative rounding of values throughout the report.

EX-10.36

Exhibit 10.36

INTERNATIONAL OPERATING AGREEMENT

Geoglobal Resources (India) Inc.            (1)

Adira Geo Global Ltd.                            (2)

Adira Oil Technologies Ltd.                   (3)

Brownstone Venture Inc.                        (4)

Pinetree Capital Ltd.                               (5)

OPERATING AGREEMENT COVERING:

License No. “Samuel”/388

Offshore Israel

Exhibit 10.36

TABLE OF CONTENTS

1.1           Accounting Procedure

1.2           AFE 

1.3           Affiliate

1.4           Agreed Interest Rate

1.5           Agreement

1.6           Appraisal Well

1.7           Business Day 

1.8           Calendar Quarter

1.9           Calendar Year

1.10           Commercial Discovery

1.11           Completion

1.12           Consenting Party

1.13           Consequential Loss 

1.14           Contract

1.15           Contract Area 

1.16           Control 

1.17           Crude Oil 

1.18           Day 

1.19           Deepening 

1.20           Development Plan 

1.21           Development Well 

1.22           Discovery 

1.23           Dispute

1.24           Entitlement 

1.25           Environmental Loss 

1.26           Exclusive Operation 

1.27           Exclusive Well 

1.28           Exploitation Area 

1.29           Exploitation Period 

1.30           Exploration Period 

1.31           Exploration Well 

1.32           G & G Data 

1.33           Government

1.34           Gross Negligence / Willful Misconduct 

1.35           Hydrocarbons 

1.36           Joint Account 

1.37           Joint Operations 

1.38           Joint Property 

1.39           Laws / Regulations 

1.40           Natural Gas 

1.41           Non-Consenting Party 

1.42           Non-Operator 

1.43           Operating Committee 

1.44           Operator 

1.45           Participating Interest 

1.46           Plugging Back 

1.47           Recompletion 

1.48           Reworking 

1.49           Security 

1.50           Sidetracking 

1.51           Testing 

1.52           Urgent Operational Matters 

1.53           Work Program and Budget 

1.54           Zone 

3.1           Scope 

3.2           Participating Interest 

3.3           Ownership, Obligations and Liabilities 

4.1           Designation of Operator; Management Fee 

4.2           Rights and Duties of Operator

4.3           Operator Personnel 

4.4           Information Supplied by Operator 

4.5           Settlement of Claims and Lawsuits 

4.6           Limitation on Liability of Operator 

4.7           Insurance Obtained by Operator 

4.8           Commingling of Funds 

4.9           Resignation of Operator 

4.10           Removal of Operator 

4.11           Appointment of Successor

4.12           Health, Safety and Environment (“HSE”) 

5.1           Establishment of Operating Committee 

5.2           Powers and Duties of Operating Committee

5.3           Authority to Vote 

5.4           Subcommittees

5.5           Notice of Meeting 

5.6           Contents of Meeting Notice 

5.7           Location of Meetings 

5.8           Operator’s Duties for Meetings 

5.9           Voting Procedure 

5.10           Record of Votes 

5.11           Minutes 

5.12           Voting by Notice 

5.13           Effect of Vote

6.1           Exploration and Appraisal 

6.2           Development 

6.3           Production 

6.4           Itemization of Expenditures 

6.5           Multi-Year Work Program and Budget 

6.6           Contract Awards 

6.7           Authorization for Expenditure (“AFE”) Procedure 

6.8           Overexpenditures of Work Programs and Budgets

7.1           Limitation on Applicability 

7.2           Procedure to Propose Exclusive Operations 

7.3           Responsibility for Exclusive Operations 

7.4           Consequences of Exclusive Operations 

7.5           Order of Preference of Operations

7.6           Stand-By Costs 

7.7           Special Considerations Regarding Deepening and Sidetracking

7.8           Use of Property 

7.9           Lost Production During Tie-In of Exclusive Operation Facilities 

7.10         Conduct of Exclusive Operations 

ARTICLE 8. DEFAULT

8.1           Default and Notice 

8.2           Operating Committee Meetings and Data 

8.3           Allocation of Defaulted Accounts 

8.4           Remedies 

8.5           Survival 

8.6           No Right of Set Off 

9.1           No Right or Obligation to Take in Kind 

9.2           Disposition of Crude Oil 

9.3           Disposition of Natural Gas 

10.1           Abandonment of Wells Drilled as Joint Operations 

10.2           Abandonment of Exclusive Operations

10.3           Abandonment Security 

11.1           Surrender 

11.2           Extension of the Term 

12.1           Obligations

12.2           Transfer 

12.3           Change in Control 

13.1           Right of Withdrawal 

13.2           Partial or Complete Withdrawal 

13.3           Rights of a Withdrawing Party 

13.4           Obligations and Liabilities of a Withdrawing Party

13.5           Emergency 

13.6           Assignment 

13.7           Approvals 

13.8           Security 

13.9           Withdrawal or Abandonment by All Parties 

14.1           Relationship of Parties 

14.2           Royalty 

14.3           Tax 

14.4           United States Tax Election 

15.1           Venture Information 

15.2           Confidentiality 

15.3           Intellectual Property 

15.4           Continuing Obligations 

15.5           Trades 

16.1           Obligations 

16.2           Definition of Force Majeure 

18.1           Applicable Law 

18.2           Dispute Resolution 

19.1           Conduct of the Parties 

19.2           Conflicts of Interest 

19.3           Public Announcements 

19.4           Successors and Assigns 

19.5           Waiver 

19.6           No Third Party Beneficiaries 

19.7           Joint Preparation 

19.8           Severance of Invalid Provisions 

19.9           Modifications 

19.10           Interpretation

19.11           Counterpart Execution 

19.12           Entirety 

OPERATING AGREEMENT

THIS AGREEMENT is made as of the ____ day of February, 2011 (the “Effective Date”) among Geoglobal Resources (India) Inc., a company existing pursuant to the laws of Barbados (“GGR”); Adira Geoglobal Ltd, an Israeli limited company (“Adira Geo”); Adira Oil Technologies Ltd., an Israeli limited company (“AOT”); Brownstone Venture Inc., a _____________ corporation (“Brownstone”); and Pintetree Capital Ltd., a ________________ limited company (“Pinetree”). The companies named above, and their respective successors and assignees (if any), may sometimes individually be referred to as “Party” and collectively as the “Parties”.

WITNESSETH:

WHEREAS, the Parties have certain rights granted to them under that certain License 388/ "Samuel" dated August 1, 2010 by the Petroleum and Mining Commissioner by virtue of his authority under Section 16 of the Israel Petroleum Law, 5712-1952 and covering certain areas located offshore of Israel (the "Contract"); and

WHEREAS, the Parties desire to define their respective rights and obligations with respect to their Participating Interests, as defined herein, and operations under the Contract;

NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements and obligations set out below and to be performed, the Parties agree as follows:

ARTICLE 1.

DEFINITIONS

As used in this Agreement, the following words and terms shall have the meaning ascribed to them below:

1.1   Accounting Procedure

 means the rules, provisions and conditions contained in Exhibit A.

1.2   AFE

 means an authorization for expenditure pursuant to Article 6.7.

1.3   Affiliate

 means a legal entity which Controls, or is Controlled by, or which is Controlled by an entity which Controls, a Party.  For the avoidance of doubt, no Party to this Agreement shall be deemed to be an Affiliate of any other Party, absent amendment of this provision.

1.4   Agreed Interest Rate

 means interest compounded on a monthly basis, at the rate per annum equal to the one (1) month term, London Interbank Offered Rate (LIBOR rate) for U.S. dollar deposits, as published in London by the Financial Times or if not published, then by The Wall Street Journal, plus three (3) percentage points, applicable on the first Business Day prior to the due date of payment and thereafter on the first Business Day of each succeeding calendar month.  If the aforesaid rate is contrary to any applicable usury law, the rate of interest to be charged shall be the maximum rate permitted by such applicable law.

1.5   Agreement

 means this agreement, together with the Exhibits attached to this agreement, and any extension, renewal or amendment hereof agreed to in writing by all the Parties hereto.

1.6   Appraisal Well

 means any well (other than an Exploration Well or a Development Well) whose purpose at the time of commencement of drilling such well is to appraise the extent or the volume of Hydrocarbon reserves contained in an existing Discovery.

1.7   Business Day

 means a Day on which the banks in Tel Aviv, Toronto and New York are all customarily open for business.

1.8   Calendar Quarter

 means a period of three (3) months commencing with January 1 and ending on the following March 31, a period of three (3) months commencing with April 1 and ending on the following June 30, a period of three (3) months commencing with July 1 and ending on the following September 30, or a period of three (3) months commencing with October 1 and ending on the following December 31, all in accordance with the Gregorian Calendar.

1.9   Calendar Year

 means a period of twelve (12) months commencing with January 1 and ending on the following December 31 in accordance with the Gregorian Calendar.

1.10   Commercial Discovery

 means any Discovery that is sufficient to entitle the Parties to apply for authorization from the Government to commence exploitation.

1.11   Completion

 means an operation intended to complete a well through the Christmas tree as a producer of Hydrocarbons in one or more Zones, including the setting of production casing, perforating, stimulating the well and production Testing conducted in such operation.  “Complete” and other derivatives shall be construed accordingly.

1.12   Consenting Party

 means a Party who agrees to participate in and pay its share of the cost of an Exclusive Operation.

1.13   Consequential Loss

 means any loss, damages, costs, expenses or liabilities caused (directly or indirectly) by any of the following arising out of, relating to, or connected with this Agreement or the operations carried out under this Agreement: (i) reservoir or formation damage; (ii) inability to produce, use or dispose of Hydrocarbons; (iii) loss or deferment of income; (iv) punitive damages; or (v) other indirect damages or losses whether or not similar to the foregoing.

1.14   Contract

 means the instrument identified in the recitals to this Agreement and any extension, renewal or amendment thereto, including any lease granted after a Discovery in the Contract Area.

1.15   Contract Area

 means as of the Effective Date the area that is described in Exhibit B.  The perimeter or perimeters of the Contract Area shall correspond to that area covered by the Contract, as such area may vary from time to time during the term of validity of the Contract.

1.16   Control

 means the ownership directly or indirectly of more than fifty (50) percent of the voting rights in a legal entity.  “Controls”, “Controlled by” and other derivatives shall be construed accordingly.

1.17   Crude Oil

 means all crude oils, condensates, and natural gas liquids at atmospheric pressure which are subject to and covered by the Contract.

1.18   Day

 means a calendar day unless otherwise specifically provided.

1.19   Deepening

 means an operation whereby a well is drilled to an objective Zone below the deepest Zone in which the well was previously drilled, or below the deepest Zone proposed in the associated AFE (if required), whichever is the deeper.  “Deepen” and other derivatives shall be construed accordingly.

1.20   Development Plan

 means a plan for the development of Hydrocarbons from an Exploitation Area.

1.21   Development Well

 means any well drilled for the production of Hydrocarbons pursuant to a Development Plan.

1.22   Discovery

 means the discovery of an accumulation of Hydrocarbons whose existence until that moment was unproven by drilling and the commercial value of which is unknown. The Operator shall determine the economic and geological parameters applicable to any determination as to the existence or absence of a Discovery, and the extent thereof.

1.23   Dispute

 means any dispute, controversy or claim (of any and every kind or type, whether based on contract, tort, statute, regulation, or otherwise) arising out of, relating to, or connected with this Agreement or the operations carried out under this Agreement, including any dispute as to the construction, validity, interpretation, enforceability or breach of this Agreement.

1.24   Entitlement

 means that quantity of Hydrocarbons (excluding all quantities used or lost in Joint Operations) of which a Party has the right and obligation to take delivery pursuant to the terms of this Agreement and the Contract, as such rights and obligations may be adjusted by the terms of any lifting, balancing and other disposition agreements entered into pursuant to Article 9.

1.25   Environmental Loss

 means any loss, damages, costs, expenses or liabilities (other than Consequential Loss) caused by a discharge of Hydrocarbons, pollutants or other contaminants into or onto any medium (such as land, surface water, ground water and/or air) arising out of, relating to, or connected with this Agreement or the operations carried out under this Agreement, including any of the following: (i) injury or damage to, or destruction of, natural resources or real or personal property; (ii) cost of pollution control, cleanup and removal; (iii) cost of restoration of natural resources; and (iv) fines, penalties or other assessments.

1.26   Exclusive Operation

 means those operations and activities carried out pursuant to this Agreement, the costs of which are chargeable to the account of less than all the Parties hereto.

1.27   Exclusive Well

 means a well drilled pursuant to an Exclusive Operation.

1.28   Exploitation Area

 means that part of the Contract Area which is established for development of a Commercial Discovery pursuant to the Contract or, if the Contract does not establish an exploitation area, then that part of the Contract Area which is delineated as the exploitation area in a Development Plan approved as a Joint Operation or as an Exclusive Operation.

1.29   Exploitation Period

 means any and all periods of exploitation during which the production and removal of Hydrocarbons is permitted under the Contract.

1.30   Exploration Period

 means any and all periods of exploration set out in the Contract.

1.31   Exploration Well

 means any well the purpose of which at the time of the commencement of drilling is to explore for an accumulation of Hydrocarbons, which accumulation was at that time unproven by drilling.

1.32   G & G Data

 means only geological, geophysical and geochemical data and other similar information that is not obtained through a well bore.

1.33   Government

 means the government of Israel and any political subdivision, agency or instrumentality.

1.34   Gross Negligence / Willful Misconduct

 means any act or failure to act (whether sole, joint or concurrent) by any person or entity which was intended to cause, or which was in reckless disregard of or wanton indifference to, harmful consequences such person or entity knew, or should have known, such act or failure would have on the safety or property of another person or entity.

1.35   Hydrocarbons

 means all substances which are subject to and covered by the Contract, including Crude Oil and Natural Gas.

1.36   Joint Account

 means the accounts maintained by Operator in accordance with the provisions of this Agreement, including the Accounting Procedure.

1.37   Joint Operations

 means those operations and activities carried out by Operator pursuant to this Agreement, the costs of which are chargeable to all Parties.

1.38   Joint Property

 means, at any point in time, all wells, facilities, equipment, materials, information, funds and property (other than Hydrocarbons) held for use in Joint Operations.

1.39   Laws / Regulations

 means those laws, statutes, rules and regulations governing activities under the Contract.

1.40   Natural Gas

 means all gaseous hydrocarbons (including wet gas, dry gas and residue gas) which are subject to and covered by the Contract, but excluding Crude Oil.

1.41   Non-Consenting Party

 means each Party who elects not to participate in an Exclusive Operation.

1.42   Non-Operator

 means each Party to this Agreement other than Operator.

1.43   Operating Committee

 means the committee constituted in accordance with Article 5.

1.44   Operator

 means a Party to this Agreement designated as such in accordance with Articles 4 or 7.10(F).

1.45   Participating Interest

 means as to any Party, the undivided interest of such Party (expressed as a percentage of the total interests of all Parties) in the rights and obligations derived from the Parties’ interest in the Contract and this Agreement.

1.46   Plugging Back

 means a single operation whereby a deeper Zone is abandoned in order to attempt a Completion in a shallower Zone.  “Plug Back” and other derivatives shall be construed accordingly.

1.47   Recompletion

 means an operation whereby a Completion in one Zone is abandoned in order to attempt a Completion in a different Zone within the existing wellbore.  “Recomplete” and other derivatives shall be construed accordingly.

1.48   Reworking

 means an operation conducted in the wellbore of a well after it is Completed to secure, restore, or improve production in a Zone which is currently open to production in the wellbore.  Such operations include well stimulation operations, but exclude any routine repair or maintenance work, or drilling, Sidetracking, Deepening, Completing, Recompleting, or Plugging Back of a well.  “Rework” and other derivatives shall be construed accordingly.

1.49   Security

 means (i) a guarantee or standby letter of credit issued by a bank; (ii) an on-demand bond issued by a surety corporation; (iii) a corporate guarantee; (iv) any financial security required by the Contract or this Agreement; and (v) any financial security agreed from time to time by the Parties; provided, however, that the bank, surety or corporation issuing the guarantee, standby letter of credit, bond or other security (as applicable) has a credit rating indicating it has a sufficient worth to pay its obligations in all reasonably foreseeable circumstances.

1.50   Sidetracking

 means the directional control and intentional deviation of a well from vertical so as to change the bottom hole location unless done to straighten the hole or to drill around junk in the hole or to overcome other mechanical difficulties.  “Sidetrack” and other derivatives shall be construed accordingly.

1.51   Testing

 means an operation intended to evaluate the capacity of a Zone to produce Hydrocarbons.  “Test” and other derivatives shall be construed accordingly.

1.52   Urgent Operational Matters

 has the meaning ascribed to it in Article 5.12(A)(1).

1.53   Work Program and Budget

 means a work program for Joint Operations and budget therefor as described and approved in accordance with Article 6.

1.54   Zone

 means a stratum of earth containing or thought to contain an accumulation of Hydrocarbons separately producible from any other accumulation of Hydrocarbons.

ARTICLE 2.

EFFECTIVE DATE AND TERM

This Agreement shall have effect from the Effective Date (as defined in the preamble to this Agreement) and shall continue in effect until the following occur in accordance with the terms of this Agreement: the Contract terminates; all materials, equipment and personal property used in connection with Joint Operations or Exclusive Operations have been disposed of or removed; and final settlement (including settlement in relation to any financial audit carried out pursuant to the Accounting Procedure) has been made.  Notwithstanding the preceding sentence: (i) Article 10 shall remain in effect until all abandonment obligations under the Contract have been satisfied; and (ii) Article 4.5, Article 8,Article 15.2, Article 18 and the indemnity obligation under Article 19.1 (A) shall remain in effect until all obligations have been

extinguished and all Disputes have been resolved.  Termination of this Agreement shall be without prejudice to any rights and obligations arising out of or in connection with this Agreement which have vested, matured or accrued prior to such termination.

ARTICLE 3.

SCOPE

3.1   Scope

(A)   The purpose of this Agreement is to establish the respective rights and obligations of the Parties with regard to operations under the Contract, including the joint exploration, appraisal, development, production and disposition of Hydrocarbons from the Contract Area.

(B)   For greater certainty, the Parties confirm that, except to the extent expressly included in the Contract, the following activities are outside of the scope of this Agreement and are not addressed herein:

(1)   construction, operation, ownership, maintenance, repair and removal of facilities downstream from the delivery point (as determined under Article 9) of the Parties’ Entitlements;

(2)   transportation of the Parties’ Entitlements downstream from the delivery point (as determined under Article 9);

(3)   marketing and sales of Hydrocarbons, except as expressly provided in Article 7.10(E), Article 8.4 and Article 9;

(4)   acquisition of rights to explore for, appraise, develop or produce Hydrocarbons outside of the Contract Area (other than as a consequence of unitization with an adjoining contract area under the terms of the Contract); and

(5)   exploration, appraisal, development or production of minerals other than Hydrocarbons, whether inside or outside of the Contract Area.

3.2   Participating Interest

(A)   The Participating Interests of the Parties as of the Effective Date are noted in the table below:

Party	Participating Interest
GGR	30%
Adira Geo	30%
AOT	23.25%
Brownstone	6.75%
Pinetree	10%

(B)   If a Party transfers all or part of its Participating Interest pursuant to the provisions of this Agreement and the Contract, or if the Government consents to

the Transfers contemplated in Section C. of that certain Cooperation Agreement between GGR and its Affiliate Geoglobal Resources Inc, and Adira Energy Ltd., the Participating Interests of the Parties shall be revised accordingly.

3.3   Ownership, Obligations and Liabilities

(A)   Unless otherwise provided in this Agreement, all the rights and interests in and under the Contract, all Joint Property, and any Hydrocarbons produced from the Contract Area shall, subject to the terms of the Contract, be owned by the Parties in accordance with their respective Participating Interests.

(B)   Unless otherwise provided in this Agreement, the obligations of the Parties under the Contract and all liabilities and expenses incurred by Operator in connection with Joint Operations shall be charged to the Joint Account and all credits to the Joint Account shall be shared by the Parties, in accordance with their respective Participating Interests.

(C)   Each Party shall pay when due, in accordance with the Accounting Procedure, its Participating Interest share of Joint Account expenses, including cash advances and interest, accrued pursuant to this Agreement.  A Party’s payment of any charge under this Agreement shall be without prejudice to its right to later contest the charge.

ARTICLE 4.

OPERATOR

4.1   Designation of Operator; Management Fee

Adira Geo is designated as Operator and agrees to act as such in accordance with this Agreement. As the Operator, Adira Geo shall be entitled to a “Management Fee” equal to seven and one-half percent (7.5%) of the aggregate direct and indirect expenses incurred in respect of the management and implementation of exploration and production activity conducted by the Parties pursuant to this Agreement.  When calculating the charges of the Operator’s personnel, time-writing of personnel engaged in support of the joint venture shall not be required.  The charges shall be included in monthly billings.  Indirect costs represent the cost of general assistance and support services provided by Operator and its Affiliates.  These costs are such that it is not practical to identify or associate them with specific projects but are for services that provide the Joint Operations with needed and necessary resources which Operator requires and provide a real benefit to Joint Operations. Indirect charges are not subject to audit under the Accounting Procedures, other than to verify that the overhead percentages are applied correctly to the expenditure basis. The Management Fee will be billed to the Joint Account monthly in arrears.

4.2   Rights and Duties of Operator

(A)   Subject to the terms and conditions of this Agreement, Operator shall have all of the rights, functions and duties of Operator under the Contract and shall have exclusive charge of and shall conduct all Joint Operations.  Operator may employ independent contractors and agents (which independent contractors and agents may include an Affiliate of Operator, a Non-Operator, or an Affiliate of a Non-Operator) in such Joint Operations. Where the Operator is comprised of two or more of the Parties hereto or a Party hereto and its Affilliate, the Operator shall

be at liberty to contractually allocate the rights and obligations as Operator in this Agreement and in the Contract, as between themselves, based on their unanimous agreement regarding same.

(B)   In the conduct of Joint Operations Operator shall:

(1)   perform Joint Operations in accordance with the provisions of the Contract, the Laws / Regulations, this Agreement, and the decisions of the Operating Committee not in conflict with this Agreement;

(2)   conduct all Joint Operations in a diligent, safe and efficient manner in accordance with such good and prudent petroleum industry practices and field conservation principles as are generally followed by the international petroleum industry under similar circumstances;

(3)   exercise due care with respect to the receipt, payment and accounting of funds in accordance with good and prudent practices as are generally followed by the international petroleum industry under similar circumstances;

(4)   perform the duties for the Operating Committee set out in Article 5, and prepare and submit to the Operating Committee proposed Work Programs and Budgets and (if required) AFEs, as provided in Article 6;

(5)   acquire all permits, consents, approvals, and surface or other rights that may be required for or in connection with the conduct of Joint Operations;

(6)   upon receipt of reasonable advance notice, permit the representatives of any of the Parties to have at all reasonable times during normal business hours and at their own risk and expense reasonable access to the Joint Operations with the right to observe all Joint Operations and to inspect all Joint Property and to conduct financial audits as provided in the Accounting Procedure;

(7)   undertake to maintain the Contract in full force and effect in accordance with such good and prudent petroleum industry practices as are generally followed by the international petroleum industry under similar circumstances.  Operator shall timely pay and discharge all liabilities and expenses incurred in connection with Joint Operations and use its reasonable endeavors to keep and maintain the Joint Property free from all liens, charges and encumbrances arising out of Joint Operations;

(8)   pay to the Government for the Joint Account, within the periods and in the manner prescribed by the Contract and the Laws / Regulations, all periodic payments, royalties, taxes, fees and other payments pertaining to Joint Operations but excluding any taxes measured by the incomes of the Parties;

(9)   carry out the obligations of Operator pursuant to the Contract and this Agreement, including preparing and furnishing such reports, records and

information as may be required pursuant to the Contract and this Agreement;

(10)   have, in accordance with any decisions of the Operating Committee, the exclusive right and obligation to represent the Parties in all dealings with the Government with respect to matters arising under the Contract and Joint Operations.  Operator shall notify the other Parties as soon as possible of such meetings.  Subject to the Contract and any necessary Government approvals, Non-Operators shall have the right to attend any meetings with the Government with respect to such matters, but only in the capacity of observers;

(11)   in accordance with Article 9.3, assess (to the extent lawful) alternatives for the disposition of Natural Gas from a Discovery;

(12)   in case of an emergency (including a significant fire, explosion, Natural Gas release, Crude Oil release, or sabotage; incident involving loss of life, serious injury to an employee, contractor, or third party, or serious property damage; strikes and riots; or evacuations of Operator personnel): (i) take all necessary and proper measures for the protection of life, health, the environment and property; and (ii) as soon as reasonably practicable, report to Non-Operators the details of such event and any measures Operator has taken or plans to take in response thereto;

(13)   establish and implement pursuant to Article 4.12 an HSE plan to govern Joint Operations which is designed to ensure compliance with applicable HSE laws, rules and regulations and this Agreement;

(14)   include, to the extent practical, in its contracts with independent contractors and to the extent lawful, provisions which:

(a)   establish that such contractors can only enforce their contracts against Operator;

(b)   permit Operator, on behalf of itself and Non-Operators, to enforce contractual indemnities against, and recover losses and damages suffered by them (insofar as recovered under their contracts) from, such contractors; and

(c)   require such contractors to take insurance required by Article 4.7(E).

4.3   Operator Personnel

Operator shall engage or retain such employees, contractors, consultants and agents as are reasonably necessary to conduct Joint Operations.  Subject to the Contract and this Agreement, Operator shall determine the number of employees, contractors, consultants and agents, the selection of such persons, their hours of work, and the compensation to be paid to all such persons in connection with Joint Operations. For the avoidance of doubt, Operator may engage or retain Affiliates of Operator at market rates prevalent in the international petroleum industry for similar work in the Contract Area; provided that in each case Operator provides an explanation of why it elected to retain or engage an Affiliate, and includes reasonable support for Operator’s

position that the rate paid to the Affiliate is a market rate prevalent in the international petroleum industry for similar work in the Contract Area.

4.4   Information Supplied by Operator

(A)   Operator shall provide Non-Operators with the following data and reports (to the extent to be charged to the Joint Account) as they are currently produced or compiled from Joint Operations:

(1)   copies of all logs or surveys, including in digitally recorded format if such exists;

(2)   daily drilling reports;

(3)   copies of all Tests and core data and analysis reports;

(4)   final well recap report;

(5)   copies of plugging reports;

(6)   copies of final geological and geophysical maps, seismic sections and shot point location maps;

(7)   engineering studies, development schedules and [quarterly/annual] progress reports on development projects;

(8)   field and well performance reports, including reservoir studies and reserve estimates;

(9)   as requested by a Non-Operator, (i) copies of all material reports relating to Joint Operations or the Contract Area furnished by Operator to the Government; and (ii) other material studies and reports relating to Joint Operations;

(10)   such additional information as a Non-Operator may reasonably request, provided that the requesting Party or Parties pay the costs of preparation of such information and that the preparation of such information will not unduly burden Operator’s administrative and technical personnel.  Only Non-Operators who pay such costs will receive such additional information; and

(11)   other reasonable reports as directed by the Operating Committee.

(B)   Operator shall give Non-Operators access at all reasonable times during normal business hours to all data and reports (other than data and reports provided to Non-Operators in accordance with Article 4.4(A)) acquired in the conduct of Joint Operations, which a Non-Operator may reasonably request.  Any Non-Operator may make copies of such other data at its sole expense.

4.5   Settlement of Claims and Lawsuits

(A)   Operator shall promptly notify the Parties of any and all material claims or suits that relate in any way to Joint Operations.  Operator shall represent the Parties and defend or oppose the claim or suit.  Operator may in its sole discretion compromise or settle any such claim or suit or any related series of claims or suits for an amount not to exceed the equivalent of $250,000 U.S. dollars exclusive of legal fees. Operator shall obtain the approval and direction of the Operating Committee on amounts in excess of the above-stated amount.  Without prejudice to the foregoing, each Non-Operator shall have the right to be represented by its own counsel at its own expense in the settlement, compromise or defense of such claims or suits.

(B)   Any Non-Operator shall promptly notify the other Parties of any claim made against such Non-Operator by a third party that arises out of or may affect the Joint Operations, and such Non-Operator shall defend or settle the same in accordance with any directions given by the Operating Committee.  Those costs, expenses and damages incurred pursuant to such defense or settlement which are attributable to Joint Operations shall be for the Joint Account.

(C)   Notwithstanding Article 4.5(A) and Article 4.5(B), each Party shall have the right to participate in any such suit, prosecution, defense or settlement conducted in accordance with Article 4.5(A) and Article 4.5(B), at its sole cost and expense; provided always that no Party may settle its Participating Interest share of any claim without first satisfying the Operating Committee that it can do so without prejudicing the interests of the Joint Operations.

4.6   Limitation on Liability of Operator

(A)   Neither Operator nor any other Indemnitee (as defined below) shall bear (except as a Party to the extent of its Participating Interest share) any damage, loss, cost, expense or liability resulting from performing (or failing to perform) the duties and functions of Operator, and the Indemnitees are hereby released from liability to Non-Operators for any and all damages, losses, costs, expenses and liabilities arising out of, incident to or resulting from such performance or failure to perform, even though caused in whole or in part by a pre-existing defect, or the negligence (whether sole, joint or concurrent), gross negligence, willful misconduct, strict liability or other legal fault of Operator (or any such Indemnitee).

(B)   The Parties shall (in proportion to their Participating Interests) defend and indemnify Operator and its Affiliates, and their respective directors, officers, and employees (collectively, the “Indemnitees”), from any and all damages, losses, costs, expenses (including reasonable legal costs, expenses and attorneys’ fees) and liabilities incident to claims, demands or causes of action brought by or on behalf of any person or entity, which claims, demands or causes of action arise out of, are incident to or result from Joint Operations, even though caused in whole or in part by a pre-existing defect, or the negligence (whether sole, joint or

concurrent), gross negligence, willful misconduct, strict liability or other legal fault of Operator (or any such Indemnitee).

(C)   Nothing in this Article 4.6 shall be deemed to relieve Operator from its Participating Interest share of any damage, loss, cost, expense or liability arising out of, incident to, or resulting from Joint Operations.

4.7   Insurance Obtained by Operator

(A)   Operator shall procure and maintain for the Joint Account all insurance (at a minimum) in the types and amounts required by the Contract or the Laws / Regulations.

(B)   Operator shall procure and maintain any further insurance, at reasonable rates, as the Operating Committee may from time to time require.  In the event that such further insurance is, in Operator’s reasonable opinion, unavailable or available only at an unreasonable cost, Operator shall promptly notify the Non-Operators in order to allow the Operating Committee to reconsider such further insurance.

(C)   The cost of insurance shall be for the Joint Account.  The cost of insurance with respect to an Exclusive Operation shall be charged to the Consenting Parties.

(D)   Operator shall, with respect to all insurance obtained under this Article 4.7:

(1)   use reasonable endeavors to procure or cause to be procured such insurance prior to or concurrent with, the commencement of relevant operations and maintain or cause to be maintained such insurance during the term of the relevant operations or any longer term required under the Contract or the Laws / Regulations;

(2)   promptly inform the Parties when such insurance is obtained and supply them with certificates of insurance or copies of the relevant policies when the same are issued;

(3)   arrange for the Parties, according to their respective Participating Interests, to be named as co-insureds on the relevant policies with waivers of subrogation in favor of all the Parties but only with respect to their interests under this Agreement;

(4)   use reasonable endeavors to ensure that each policy shall survive the default or bankruptcy of the insured for claims arising out of an event before such default or bankruptcy and that all rights of the insured shall revert to the Parties not in default or bankruptcy; and

(5)   duly file all claims and take all necessary and proper steps to collect any proceeds and credit any proceeds to the participating Parties in proportion to their respective Participating Interests.

(E)   Operator shall use its reasonable endeavors to require all contractors performing work with respect to Joint Operations to:

(1)   obtain and maintain any and all insurance in the types and amounts required by the Contract, the Laws / Regulations or any direction of Operator consistent with this Agreement;

(2)   name the Parties as additional insureds on the contractor’s insurance policies and obtain from their insurers waivers of all rights of recourse against Operator, Non-Operators and their insurers; and

(3)   provide Operator with certificates reflecting such insurance prior to the commencement of their services.

4.8   Commingling of Funds

Operator may not commingle with Operator’s own funds the monies which Operator receives from or for the Joint Account pursuant to this Agreement. However, Operator reserves the right to make future proposals to the Operating Committee with respect to the commingling of funds to achieve financial efficiency.  The Operating Committee may decide that monies Operator receives for the Joint Account shall be deposited in an interest-bearing account. Interest earned shall be allocated among the Parties on an equitable basis taking into account the date of the funding by each Party and its share of the Joint Account monies.  Operator shall apply such earned interest to the next succeeding cash call or, if directed by the Operating Committee, pay it to the Parties.

4.9   Resignation of Operator

Subject to Article 4.11, Operator may resign as Operator at any time by so notifying the other Parties at least one hundred and twenty (120) Days prior to the effective date of such resignation.

4.10   Removal of Operator

(A)   Subject to Article 4.11, Operator shall be removed upon receipt of notice from any Non-Operator if:

(1)   Operator becomes insolvent or bankrupt, or makes an assignment for the benefit of creditors;

(2)   an order is made by a court or an effective resolution is passed for the reorganization under any bankruptcy law, dissolution, liquidation, or winding up of Operator;

(3)   a receiver is appointed for a substantial part of Operator’s assets; or

(4)   Operator dissolves, liquidates, is wound up, or otherwise terminates its existence.

(B)   Subject to Article 4.11, Operator may be removed by the decision of the Non-Operators if Operator has committed a material breach of this Agreement and has either failed to commence to cure that breach within thirty (30) Days of receipt of a notice from Non-Operators detailing the alleged breach or failed to diligently

pursue the cure to completion.  Any decision of Non-Operators to give notice of breach to Operator to remove Operator under this Article 4.10(B) shall be made by an affirmative vote of two (2) or more of the total number of Non-Operators holding a combined Participating Interest of at least fifty-one percent (51%).  However if Operator disputes such alleged commission of or failure to cure a material breach and dispute resolution proceeds are initiated pursuant to Article 18.2 in relation to such breach, then Operator shall remain appointed and no successor Operator may be appointed pending the conclusion or abandonment of such proceedings, subject to the terms of Article 8.3 with respect to Operator’s breach of its payment obligations.  In any such proceeding, the Non-Operators will advance all costs and expenses of Operator (including reasonable fees and costs of legal counsel selected by Operator) to cover the entirety of such proceedings. Only if the Non-Operators prevail (meaning the allegations of breach and failure to cure are proven and Operator is rightfully removed by binding decision of the Arbitrator) will Operator be required to refund such advances within thirty (30) Days following conclusion of the proceedings and receipt of the arbitral award.

4.11   Appointment of Successor

When a change of Operator occurs pursuant to Article 4.9 or Article 4.10:

(A)   The Operating Committee shall meet as soon as possible to appoint a successor Operator pursuant to the voting procedure of Article 5.9.  No Party may be appointed successor Operator against its will.

(B)   The resigning or removed Operator shall be compensated out of the Joint Account for its reasonable expenses directly related to its resignation or removal, except in the case of Article 4.10(B).

(C)   The resigning or removed Operator and the successor Operator shall arrange for the taking of an inventory of all Joint Property and Hydrocarbons, and an audit of the books and records of the removed Operator.  Such inventory and audit shall be completed, if possible, no later than the effective date of the change of Operator and shall be subject to the approval of the Operating Committee.  The liabilities and expenses of such inventory and audit shall be charged to the Joint Account.

(D)   The resignation or removal of Operator and its replacement by the successor Operator shall not become effective prior to receipt of any necessary Government approvals.

(E)   Upon the effective date of the resignation or removal, the successor Operator shall succeed to all duties, rights and authority prescribed for Operator.  The former Operator shall transfer to the successor Operator custody of all Joint Property, books of account, records and other documents maintained by Operator pertaining to the Contract Area and to Joint Operations.  Upon delivery of the above-described property and data, the former Operator shall be released and discharged from all obligations and liabilities as Operator accruing after such date.

4.12   Health, Safety and Environment (“HSE”)

(A)   With the goal of achieving safe and reliable operations in compliance with applicable HSE laws, rules and regulations (including avoiding significant and unintended impact on the safety or health of people, on property, or on the environment), Operator shall in the conduct of Joint Operations:

(1)   establish and implement an HSE plan in a manner consistent with standards and procedures generally followed in the international petroleum industry under similar circumstances;

(2)   design and operate Joint Property consistent with the HSE plan; and

(3)   conform with locally applicable HSE laws, rules and regulations and other HSE-related statutory requirements that may apply.

(B)   Operator shall submit its HSE plan to the Operating Committee for approval.

(C)   In the conduct of Joint Operations, Operator shall establish and implement a program for regular HSE assessments.  The purpose of such assessments is to periodically review HSE systems and procedures, including actual practice and performance, to verify that the HSE plan is being implemented in accordance with the policies and standards of the HSE plan. Operator shall, at a minimum, conduct such an assessment before entering into significant new Joint Operations and before undertaking any major changes to existing Joint Operations.  Upon reasonable notice given to Operator, Non-Operators shall have the right to participate in such HSE assessments.

(D)   Operator shall require its contractors, consultants and agents undertaking activities for the Joint Account to manage HSE risks in a manner consistent with the requirements of this Article 4.12.

(E)   Operator shall establish and enforce rules consistent with those generally followed in the international petroleum industry under similar circumstances that, at a minimum, prohibit within the Contract Area the following:

(1)   possession, use, distribution or sale of firearms, explosives, or other weapons without the prior written approval of senior management of Operator;

(2)   possession, use, distribution or sale of alcoholic beverages without the prior written approval of senior management of Operator; and

(3)   possession, use, distribution or sale of illicit or non-prescribed controlled substances and the misuse of prescribed drugs.

(F)   Without prejudice to a Party’s rights under Article 4.2(B)(6), with reasonable advance notice, Operator shall permit each Non-Operator to have at all

 reasonable times during normal business hours (and at its own risk and expense) the right to conduct its own HSE audit.

ARTICLE 5.

OPERATING COMMITTEE

5.1   Establishment of Operating Committee

There is established an Operating Committee composed of representatives of each Party holding a Participating Interest of at least five percent (5%).  Each such Party shall appoint one (1) representative and one (1) alternate representative to serve on the Operating Committee.  Each Party shall as soon as possible after the date of this Agreement give notice in writing to the other Parties of the name and address of its representative and alternate representative to serve on the Operating Committee.  Each Party shall have the right to change its representative and alternate at any time by giving notice of such change to the other Parties.

5.2   Powers and Duties of Operating Committee

The Operating Committee shall have power and duty to recommend or authorize Joint Operations that are necessary or desirable to fulfill the Contract and properly explore and exploit the Contract Area in accordance with this Agreement and in a manner appropriate in the circumstances.

5.3   Authority to Vote

The representative of a Party, or in his absence his alternate representative, shall be authorized to represent and bind such Party with respect to any matter which is within the powers of the Operating Committee and is properly brought before the Operating Committee.  Each such representative shall have a vote equal to the Participating Interest of the Party such person represents.  Each alternate representative shall be entitled to attend all Operating Committee meetings but shall have no vote at such meetings except in the absence of the representative for whom he is the alternate.  In addition to the representative and alternate representative, each Party may also bring to any Operating Committee meetings such technical and other advisors as it may deem appropriate.

5.4   Subcommittees

The Operating Committee may establish such subcommittees, including technical subcommittees, as the Operating Committee may deem appropriate.  The functions of such subcommittees shall be in an advisory capacity unless determined otherwise by the Operator. Each Party shall have the right to appoint a representative to each subcommittee.

5.5   Notice of Meeting

(A)   Operator may call a meeting of the Operating Committee by giving notice to the Parties at least fifteen (15) Days in advance of such meeting; provided that a meeting of the Operating Committee must be held at least once each Calendar Quarter.

(B)   Any Non-Operator may request a meeting of the Operating Committee by giving notice to all the other Parties.  Upon receiving such request, Operator shall call

such meeting for a date not less than fifteen (15) Days nor more than twenty (20) Days after receipt of the request.

(C)   The notice periods above may only be waived with the unanimous consent of all the Parties.

5.6   Contents of Meeting Notice

(A)   Each notice of a meeting of the Operating Committee as provided by Operator shall contain:

(1)   the date, time and location of the meeting;

(2)   an agenda of the matters and proposals to be considered and/or voted upon; and

(3)   copies of all proposals to be considered at the meeting (including all appropriate supporting information not previously distributed to the Parties).

(B)   A Party, by written notice to the other Parties given not less than seven (7) Days prior to a meeting, may add additional matters to the agenda for a meeting.

(C)   On the request of a Party, and with the unanimous consent of all Parties, the Operating Committee may consider at a meeting a proposal not contained in such meeting agenda.

5.7   Location of Meetings

All meetings of the Operating Committee shall be held in Tel Aviv, or elsewhere as the Operating Committee may decide.

5.8   Operator’s Duties for Meetings

(A)   With respect to meetings of the Operating Committee and any subcommittee, Operator’s duties shall include:

(1)   timely preparation and distribution of the agenda;

(2)   organization and conduct of the meeting; and

(3)   preparation of a written record or minutes of each meeting.

(B)   Operator shall have the right to appoint the chairman of the Operating Committee and all subcommittees.

5.9   Voting Procedure

Except as otherwise expressly provided in this Agreement, decisions, approvals and other actions of the Operating Committee on all proposals coming before it shall be decided as follows:

(A)   All decisions, approvals and other actions for which column (A) below is checked shall require the affirmative vote of two (2) or more Parties then having collectively more than sixty percent (60%) of the Participating Interests.

(B)   All decisions, approvals and other actions for which column (B) below is checked shall require the affirmative vote of two (2) or more Parties then having collectively at least eighty percent (80%) of the Participating Interests.

	Matter	(A)	(B)
(1)	Drilling, Deepening, Testing, Sidetracking, Plugging Back, Recompleting or Reworking Exploration Wells.	ü
(2)	Drilling, Deepening, Testing, Sidetracking, Plugging Back, Recompleting or Reworking Appraisal Wells.	ü
(3)	Development Plans, including Work Programs and Work Program Budgets for Development Plans.	ü
(4)	Production programs, including Work Programs and Work Program Budgets for Production programs.	ü
(5)	Appraisal Work Program and Budget.	ü
(6)	Completion of a well.	ü
(7)	Plugging and abandoning a well.	ü
(8)	Acquisition of G & G Data.	ü
(9)	Construction of processing, treatment, compression, gathering, transportation and other downstream facilities.	ü
(10)	Contract awards (if approval is required).	ü
(11)	Article 4.11: Appointment of successor Operator	ü
(12)	Unitization under the terms of the Contract with an adjoining contract area.		ü
(13)	Modifications of an approved Development Plan which results in a more than 20% increase in the total cost of the Development Plan.	ü
(14)	Voluntary relinquishment of all or any part of the Contract Area, or voluntary termination of the Contract, including §11.1(A)		ü
(15)	Work Program and Budget, plus any modifications of an approved Work Program and Budget that results in a more than 20% increase in the total cost of the Work Program and Budget, subject in each case to Article 6.1(E).	ü
(16)	Establishment of an interest bearing account for Joint Account monies.	ü
(17)	Acquisition and development of Venture Information under terms other than as specified in Article 15.	ü
(18)	§15.3(A): Licensing Rights	ü
(19)	Article 4.4 (A)(11), 6.2(A)(4) and 6.4(B)(2): Request for Reports or Information	ü
(20)	Article 4.5(A): Settlement of Claims	ü
(21)	§4.5(B) and (C). This item will count only the votes of the disinterested Parties.	ü
(22)	Article 4.7(B): Insurance	ü
(23)	Article 4.12(B): Approval of HSE Plan	ü
(24)	§5.2. Establish committees or sub-committees	ü
(25)	Article 5.7: Alternate location for Operating Committee Meetings	ü
(26)	§6.1(C). Determination of whether to Appraise a Discovery	ü
(27)	§6.5: Whether to Present a Multi-Year Work Program and Budget	ü
(28)	§6.6. Agreements with Affiliates of Operator > $500,000. This item will count only the votes of the disinterested Parties.	ü
(29)	§15.5: Well trades	ü
(30)	All other matters within the Operating Committee’s authority.	ü
(31)	§8.4(F) and 12.2(E)(4): Form of Power of Attorney; Form of Subordination Agreement	ü
(32)	§12.3(B): Decision as to adequacy of Security. This item will count only the votes of the disinterested Parties.	ü

5.10   Record of Votes

The Operator shall appoint a secretary who shall make a record of each proposal voted on and the results of such voting at each Operating Committee meeting. Each representative shall sign and be provided a copy of such record at the end of such meeting, and it shall be considered the final record of the decisions of the Operating Committee.

5.11   Minutes

The secretary shall provide each Party with a copy of the minutes of the Operating Committee meeting within fifteen (15) Business Days after the end of the meeting.  Each Party shall have fifteen (15) Days after receipt of such minutes to give notice to the secretary of its objections to the minutes.  A failure to give notice specifying objection to such minutes within said fifteen (15)

Day period shall be deemed to be approval of such minutes.  In any event, the votes recorded under Article 5.10 shall take precedence over the minutes described above.

5.12   Voting by Notice

(A)   In lieu of a meeting, any Party may submit any proposal to the Operating Committee for a vote by notice.  The proposing Party or Parties shall notify Operator who shall give each Party’s representative notice describing the proposal so submitted and whether Operator considers such operational matter to require urgent determination.  Operator shall include with such notice adequate documentation in connection with such proposal to enable the Parties to make a decision.  Each Party shall communicate its vote by notice to Operator and the other Parties within one of the following appropriate time periods after receipt of Operator’s notice:

(1)   48 hours in the case of operations which involve the use of a drilling rig that is standing by in the Contract Area and such other operational matters reasonably considered by Operator to require by their nature urgent determination (such operations and matters being referred to as “Urgent Operational Matters”); and

(2)   Six (6) Business Days in the case of all other proposals.

(B)   Except in the case of Article 5.12(A)(1), any Party may, by notice delivered to all Parties within two (2) Business Days of receipt of Operator’s notice, request that the proposal be decided at a meeting rather than by notice.  In such an event, that proposal shall be decided at a meeting duly called for that purpose.

(C)   Except as provided in Article 10, any Party failing to communicate its vote in a timely manner shall be deemed to have voted for (in favor of) such proposal.

(D)   If a meeting is not requested, then at the expiration of the appropriate time period, Operator shall give each Party a confirmation notice stating the tabulation and results of the vote.

5.13   Effect of Vote

All decisions taken by the Operating Committee pursuant to this Article 5 shall be conclusive and binding on all the Parties, except in the following cases.

(A)   If pursuant to this Article 5, a Joint Operation has been properly proposed to the Operating Committee and the Operating Committee has not approved such proposal in a timely manner, then any Party that voted in favor of such proposal shall have the right for the appropriate period specified below to propose, in accordance with Article 7, an Exclusive Operation involving operations essentially the same as those proposed for such Joint Operation.

(1)   For proposals related to Urgent Operational Matters, such right shall be exercisable for twenty-four (24) hours after the time specified in Article 5.12(A)(1) has expired or after receipt of Operator’s notice given to the Parties pursuant to Article 5.13(D), as applicable.

(2)   For proposals to develop a Discovery, such right shall be exercisable for ten (10) Business Days after the date the Operating Committee was required to consider such proposal pursuant to Article 5.6 or Article 5.12.

(3)   For all other proposals, such right shall be exercisable for five (5) Business Days after the date the Operating Committee was required to consider such proposal pursuant to Article 5.6 or Article 5.12.

(B)   If a Party voted against any proposal which was approved by the Operating Committee and which could be conducted as an Exclusive Operation pursuant to Article 7, then such Party shall have the right not to participate in the operation contemplated by such approval.  Any such Party wishing to exercise its right of non-consent must give notice of non-consent to all other Parties within five (5) Business Days (or twenty-four (24) hours for Urgent Operational Matters) following Operating Committee approval of such proposal.  If a Party exercises its right of non-consent, the Parties who were not entitled to give or did not give notice of non-consent shall be Consenting Parties as to the operation contemplated by the Operating Committee approval, and shall conduct such operation as an Exclusive Operation under Article 7; provided, however, that any Consenting Party, by notice provided to the other Parties within five (5) Business Days (or twenty-four (24) hours for Urgent Operational Matters) following the notice of non-consent given by any Non-Consenting Party, require that the Operating Committee vote again on the proposal in question. Only the Consenting Parties shall participate in such second vote of the Operating Committee, with voting rights proportional to their respective Participating Interests. If the Operating Committee approves again the contemplated operation, any Party which voted against the contemplated operation in such second vote may elect to be a Non-Consenting Party with respect to such operation, by notice of non-consent provided to all other Parties within five (5) Business Days (or twenty-four (24) hours for Urgent Operational Matters) following the Operating Committee’s second approval of such contemplated operation.

(C)   If the Consenting Parties to an Exclusive Operation under Article 5.13(A) or Article 5.13(B) concur, then the Operating Committee may, at any time, pursuant to this Article 5, reconsider and approve, decide or take action on any proposal that the Operating Committee declined to approve earlier, or modify or revoke an earlier approval, decision or action.

(D)   Once a Joint Operation for the drilling, Deepening, Testing, Sidetracking, Plugging Back, Completing, Recompleting, Reworking, or plugging of a well has been approved and commenced, such operation shall not be discontinued without the consent of the Operating Committee; provided, however, that such operation may be discontinued if:

(1)   an impenetrable substance or other condition in the hole is encountered which in the reasonable judgment of Operator causes the continuation of such operation to be impractical; or

(2)   other circumstances occur which in the reasonable judgment of Operator cause the continuation of such operation to be unwarranted.

On the occurrence of either of the above, Operator shall promptly notify the Parties that such operation is being discontinued pursuant to the foregoing, and any Party shall have the right to propose in accordance with Article 7 an Exclusive Operation to continue such operation.

ARTICLE 6.

WORK PROGRAMS AND BUDGETS

6.1   Exploration and Appraisal

(A)   Within thirty (30) Days after the Effective Date, Operator shall deliver to the Parties a proposed Work Program and Budget detailing the Joint Operations to be performed for the remainder of the current Calendar Year and, if appropriate, for the following Calendar Year. If applicable, the Work Program and Budget will contain Operator's estimate of all applicable costs of plugging and abandoning wells or portions of wells and decommissioning facilities. Within fifteen (15) Days of such delivery, the Operating Committee shall meet to consider and to endeavor to agree on a Work Program and Budget.

(B)   On or before the November 1 of each Calendar Year, Operator shall deliver to the Parties a proposed Work Program and Budget detailing the Joint Operations to be performed for the following Calendar Year.  Within thirty (30) Days of such delivery, the Operating Committee shall meet to consider and to endeavor to agree on a Work Program and Budget.

(C)   If a Discovery is made, Operator shall deliver any notice of Discovery required under the Contract and shall as soon as possible submit to the Parties a report containing available details concerning the Discovery and Operator’s recommendation as to whether the Discovery merits appraisal.  If the Operator determines that the Discovery merits appraisal, Operator within thirty (30) Days shall deliver to the Parties a proposed Work Program and Budget for the appraisal of the Discovery.  Within fifteen (15) Days of such delivery, or earlier if necessary to meet any applicable deadline under the Contract, the Operating Committee shall meet to consider, modify and then either approve or reject the appraisal Work Program and Budget.  If the appraisal Work Program and Budget is approved by the Operating Committee, Operator shall take such steps as may be required under the Contract to secure approval of the appraisal Work Program and Budget by the Government.  In the event the Government requires changes in the appraisal Work Program and Budget, the matter shall be resubmitted to the Operating Committee for further consideration.

(D)   If within the time periods prescribed in this Article 6.1 the Operating Committee is unable to agree on such a Work Program and Budget, then the Work Program and Budget that receives the largest Participating Interest vote (even if less than the applicable percentage under Article 5.9 shall be deemed adopted as part of the annual Work Program and Budget.  If competing proposals receive equal votes, then Operator shall choose between those competing proposals.

(E)   Any approved Work Program and Budget may be revised by the Operating Committee from time to time; provided however that any such revision may not alter previously approved work that has been initiated by the Operator (including any material expenditure incurred by Operator in preparation to conduct such pre-approved work), absent the consent of the Operator in each instance.  To the extent such revisions are approved by the Operating Committee and, if applicable, the Operator, the Work Program and Budget shall be amended accordingly.  Operator shall prepare and submit a corresponding Work Program and Budget amendment to the Government if required by the Contract.

(F)   Subject to Article 6.8, approval of any such Work Program and Budget which includes:

(1)   an Exploration Well, whether by drilling, Deepening or Sidetracking, shall include approval for all expenditures necessary for drilling, Deepening or Sidetracking, as applicable, and Testing and Completing an Exploration Well.

(2)   an Appraisal Well, whether by drilling, Deepening or Sidetracking, shall include approval for: all expenditures necessary for drilling, Deepening or Sidetracking, as applicable, and Testing and Completing such Appraisal Well.

6.2   Development

(A)   If the Operator determines that a Discovery is a Commercial Discovery, Operator shall, as soon as practicable, deliver to the Parties a Development Plan together with the first annual Work Program and Budget (or a multi-year Work Program and Budget pursuant to Article 6.5) and provisional Work Programs and Budgets for the remainder of the development of the Discovery, which shall contain, inter alia:

(1)   details of the proposed work to be undertaken, personnel required and expenditures to be incurred, including the timing of same, on a Calendar Year basis;

(2)   an estimated date for the commencement of production;

(3)   a delineation of the proposed Exploitation Area; and

(4)   any other information reasonably requested by the Operating Committee.

(B)   After receipt of the Development Plan and prior to any applicable deadline under the Contract, the Operating Committee shall meet to consider, modify and then either approve or reject the Development Plan and the first annual Work Program and Budget for the development of a Discovery, as submitted by Operator.  If the Operating Committee approves the Development Plan, Operator shall, as soon as possible, deliver any notice of Commercial Discovery required under the Contract and take such other steps as may be required under the Contract to

secure approval of the Development Plan by the Government.  In the event the Government requires changes in the Development Plan, the matter shall be resubmitted to the Operating Committee for further consideration.

(C)   If the Development Plan is approved, such work shall be incorporated into and form part of annual Work Programs and Budgets, and Operator shall, on or before November 1 of each Calendar Year submit a Work Program and Budget for the Exploitation Area, for the following Calendar Year.  Subject to Article 6.5, within thirty (30) Days after such submittal, the Operating Committee shall endeavor to agree to such Work Program and Budget, including any necessary or appropriate revisions to the Work Program and Budget for the approved Development Plan.

6.3   Production

On or before November 1 of each Calendar Year, Operator shall deliver to the Parties a proposed production Work Program and Budget detailing the Joint Operations to be performed in the Exploitation Area and the projected production schedule for the following Calendar Year.  Within thirty (30) Days of such delivery, the Operating Committee shall agree upon a production Work Program and Budget, failing which the provisions of Article 6.1(D) shall be applied mutatis mutandis.

6.4   Itemization of Expenditures

(A)   During the preparation of the proposed Work Programs and Budgets and Development Plans contemplated in this Article 6, Operator shall consult with the Operating Committee or the appropriate subcommittees regarding the contents of such Work Programs and Budgets and Development Plans.

(B)   Each Work Program and Budget and Development Plan submitted by Operator shall contain an itemized estimate of the costs of Joint Operations and all other expenditures to be made for the Joint Account during the Calendar Year in question and shall, inter alia:

(1)   identify each work category in sufficient detail to afford the ready identification of the nature, scope and duration of the activity in question;

(2)   include such reasonable information regarding Operator’s allocation procedures and estimated manpower costs as the Operating Committee may determine;

(3)   comply with the requirements of the Contract;

(4)   contain an estimate of funds to be expended by Calendar Quarter; and

(5)   during the Exploration Period, provide a forecast of annual expenditures and activities through the end of the Exploration Period.

(C)   The Work Program and Budget shall designate the portion or portions of the Contract Area in which Joint Operations itemized in such Work Program and

Budget are to be conducted and shall specify the kind and extent of such operations in such detail as the Operating Committee may deem suitable.

6.5   Multi-Year Work Program and Budget

Any work that cannot be efficiently completed within a single Calendar Year may be proposed in a multi-year Work Program and Budget.  Upon approval by the Operating Committee, such multi-year Work Program and Budget shall, subject only to revisions approved by the Operating Committee thereafter: (i) remain in effect as between the Parties (and the associated cost estimate shall be a binding pro-rata obligation of each Party) through the completion of the work; and (ii) be reflected in each annual Work Program and Budget.  If the Contract requires that Work Programs and Budgets be submitted to the Government for approval, such multi-year Work Program and Budget shall be submitted to the Government either in a single request for a multi-year approval or as part of the annual approval process, according to the terms of the Contract.

6.6   Contract Awards

Subject to the Contract, Operator shall award the contract to the best qualified contractor as determined by cost and ability to perform the contract without the obligation to tender and without informing or seeking the approval of the Operating Committee, except that before entering into contracts with Affiliates of Operator exceeding $500,000 U.S. dollars, Operator shall obtain the approval of the Operating Committee.

6.7   Authorization for Expenditure (“AFE”) Procedure

(A)   Prior to incurring any commitment or expenditure for the Joint Account, which is estimated to be in excess of $1,000,000 in an exploration or appraisal Work Program and Budget, development Work Program and Budget, or production Work Program and Budget; Operator shall send to each Non-Operator an AFE as described in Article 6.7(C).  Notwithstanding the above, Operator shall not be obliged to furnish an AFE to the Parties with respect to any work-overs of wells and general and administrative costs that are listed as separate line items in an approved Work Program and Budget.

(B)   Notwithstanding any other provision of this Agreement, all AFEs shall be for informational purposes only.  Approval of an operation in the current Work Program and Budget shall authorize Operator to conduct the operation (subject to Article 6.8) without further authorization from the Operating Committee.

(C)   Each AFE proposed by Operator shall:

(1)   identify the operation by reference to the applicable line items in the Work Program and Budget;

(2)   describe the work;

(3)   contain Operator’s estimate of the total funds required to carry out such work;

(4)   outline the proposed work schedule;

(5)   provide a timetable of expenditures, if known; and

(6)   be accompanied by such other supporting information as is necessary for an informed decision.

6.8   Overexpenditures of Work Programs and Budgets

(A)   Operator shall be entitled to incur without further approval of the Operating Committee a cumulative overexpenditure for a Calendar Year not to exceed twenty percent (20%) of the total annual Work Program and Budget in question.

(B)   At such time Operator reasonably anticipates the limits of Article 6.8(A) will be exceeded, Operator shall furnish to the Operating Committee a reasonably detailed estimate for the Operating Committee’s approval.  The Work Program and Budget shall be revised accordingly and the overexpenditures permitted in Article 6.8(A) shall be based on the revised Work Program and Budget.  Operator shall promptly give notice of the amounts of overexpenditures when actually incurred.

(C)   The restrictions contained in this Article 6 shall be without prejudice to Operator’s rights to make expenditures for Urgent Operational Matters and measures set out in Article 13.5 without the Operating Committee’s approval.

ARTICLE 7.

OPERATIONS BY LESS THAN ALL PARTIES

7.1   Limitation on Applicability

(A)   No operations may be conducted in furtherance of the Contract except as Joint Operations under Article 5 or as Exclusive Operations under this Article 7.  No Exclusive Operation shall be conducted (other than the tie-in of Exclusive Operation facilities with existing production facilities pursuant to Article 7.9) which conflicts with a previously approved Joint Operation or with a previously approved Exclusive Operation. Notwithstanding any other provision of this Agreement, Operator may reject any Exclusive Operation proposal by any Party if, in the discretion of the Operator, such proposal could reasonably be expected to interfere with the prospectivity or ability to efficiently pursue and maximize any other Joint Operation or Exclusive Operation, if Operator reasonably believes that any material technical specifications contained in the Exclusive Operation proposal are imprudent or are not supported by the known data about the formation, or if Operator reasonably believes that pursuing the Exclusive Operation presents material safety or environmental hazards or concerns.

(B)   No Party may propose or conduct an Exclusive Operation under this Article 7 (1) unless and until such Party has properly exercised its right to propose an Exclusive Operation pursuant to Article 5.13, or is entitled to conduct an Exclusive Operation pursuant to Article 10; and (2) until the first well drilled in the Contract Area is drilled to its total depth (as determined by the Operator consistent with the drilling plan for that first well) as a Joint Operation.

(C)   The following operations may be proposed and conducted as Exclusive Operations, subject to the terms of this Article 7:

(1)   drilling and/or Testing of Exploration Wells and Appraisal Wells;

(2)   Completion of Exploration Wells and Appraisal Wells not then Completed as productive of Hydrocarbons;

(3)   Deepening, Sidetracking, Plugging Back and/or Recompletion of Exploration Wells and Appraisal Wells;

(4)   development of a Commercial Discovery; and

(5)   any operations specifically authorized to be undertaken as an Exclusive Operation under Article 10.

No other type of operation may be proposed or conducted as an Exclusive Operation.

7.2   Procedure to Propose Exclusive Operations

(A)   Subject to Article 7.1, if any Party proposes to conduct an Exclusive Operation, such Party shall give notice of the proposed operation to all Parties, other than Non-Consenting Parties who have relinquished their rights to participate in such operation pursuant to Article 7.4(B). Such notice shall specify that such operation is proposed as an Exclusive Operation and include the work to be performed, the location, the objectives, and estimated cost of such operation.

(B)   Any Party entitled to receive such notice shall have the right to participate in the proposed operation.

(1)   For proposals to Deepen, Test, Complete, Sidetrack, Plug Back, Recomplete or Rework related to Urgent Operational Matters, any such Party wishing to exercise such right must so notify the proposing Party and Operator within twenty-four (24) hours after receipt of the notice proposing the Exclusive Operation.

(2)   For proposals to develop a Discovery, any Party wishing to exercise such right must so notify Operator and the Party proposing to develop within sixty (60) Days after receipt of the notice proposing the Exclusive Operation.

(3)   For all other proposals, any such Party wishing to exercise such right must so notify the proposing Party and Operator within ten (10) Days after receipt of the notice proposing the Exclusive Operation.

(C)   Failure of a Party to whom a proposal notice is delivered to properly reply within the period specified above shall constitute an election by that Party not to participate in the proposed operation.

(D)   If all Parties properly exercise their rights to participate, then the proposed operation shall be conducted as a Joint Operation.  Operator shall commence such Joint Operation as promptly as practicable and conduct it with due diligence.

(E)   If less than all Parties entitled to receive such proposal notice properly exercise their rights to participate, then:

(1)   Immediately after the expiration of the applicable notice period set out in Article 7.2(B), Operator shall notify all Parties of the names of the Consenting Parties and the recommendation of the proposing Party as to whether the Consenting Parties should proceed with the Exclusive Operation.

(2)   Concurrently, Operator shall request the Consenting Parties to specify the Participating Interest each Consenting Party is willing to bear in the Exclusive Operation.

(3)   Within twenty-four (24) hours after receipt of such notice, each Consenting Party shall respond to Operator stating that it is willing to bear a Participating Interest in such Exclusive Operation equal to:

(a) only its Participating Interest as stated in Article 3.2(A);

(b) a fraction, the numerator of which is such Consenting Party’s Participating Interest as stated in Article 3.2(A) and the denominator of which is the aggregate of the Participating Interests of the Consenting Parties as stated in Article 3.2(A); or

(c) the Participating Interest as contemplated by Article 7.2(E)(3)(b) plus all or any part of the difference between one hundred percent (100%) and the total of the Participating Interests subscribed by the other Consenting Parties. Any portion of such difference claimed by more than one Party shall be distributed to each claimant on a pro-rata basis.

(4)   Any Consenting Party failing to advise Operator within the response period set out above shall be deemed to have elected to bear the Participating Interest set out in Article 7.2(E)(3)(b) as to the Exclusive Operation.

(5)   If, within the response period set out above, the Consenting Parties subscribe less than one hundred percent (100%) of the Participating Interest in the Exclusive Operation, the Party proposing such Exclusive Operation shall be deemed to have withdrawn its proposal for the Exclusive Operation, unless within twenty-four (24) hours of the expiry of the response period set out in Article 7.2(E)(3), the proposing Party notifies the other Consenting Parties that the proposing Party shall bear the unsubscribed Participating Interest.

(6)   If one hundred percent (100%) subscription to the proposed Exclusive Operation is obtained, Operator shall promptly notify the Consenting Parties of their Participating Interests in the Exclusive Operation.

(7)   As soon as any Exclusive Operation is fully subscribed pursuant to Article 7.2(E)(6), Operator, subject to Article 7.12(F), shall commence such Exclusive Operation as promptly as practicable and conduct it with due diligence in accordance with this Agreement.

(8)   If such Exclusive Operation has not been commenced within one hundred eighty (180) Days (excluding any extension specifically agreed by all Parties or allowed by the force majeure provisions of Article 16) after the date of the notice given by Operator under Article 7.2(E)(6), the right to conduct such Exclusive Operation shall terminate.  If any Party still desires to conduct such Exclusive Operation, notice proposing such operation must be resubmitted to the Parties in accordance with Article 5, as if no proposal to conduct an Exclusive Operation had been previously made.

7.3   Responsibility for Exclusive Operations

(A)   The Consenting Parties shall bear in accordance with the Participating Interests agreed under Article 7.2(E) the entire cost and liability of conducting an Exclusive Operation and shall indemnify the Non-Consenting Parties from any and all costs and liabilities incurred incident to such Exclusive Operation (including Consequential Loss and Environmental Loss) and shall keep the Contract Area free and clear of all liens and encumbrances of every kind created by or arising from such Exclusive Operation.

(B)   Notwithstanding Article 7.3(A), each Party shall continue to bear its Participating Interest share of the cost and liability incident to the operations in which it participated, including plugging and abandoning and restoring the surface location, but only to the extent those costs were not increased by the Exclusive Operation.

7.4   Consequences of Exclusive Operations

(A)   Subject to Article 7.4(C) and Articles 7.5(E) and 7.7, if selected, each Non-Consenting Party shall be deemed to have relinquished to the Consenting Parties, and the Consenting Parties shall be deemed to own, in proportion to their respective Participating Interests in any Exclusive Operation:

(1)   all of each such Non-Consenting Party’s right to participate in further operations in the well or Deepened or Sidetracked portion of a well in which the Exclusive Operation was conducted and on any Discovery made or appraised in the course of such Exclusive Operation; and

(2)   all of each such Non-Consenting Party’s right pursuant to the Contract to take and dispose of Hydrocarbons produced and saved:

(a)   from the well or Deepened or Sidetracked portion of a well in which such Exclusive Operation was conducted; and

(b)   from any wells drilled to appraise or develop a Discovery made or appraised in the course of such Exclusive Operation.

(B)   A Non-Consenting Party shall have no option to reinstate the rights it relinquished pursuant to Article 7.4(A) unless the Consenting Parties unanimously agree to permit such reinstatement under terms dictated unanimously by the Consenting Parties. Any such consent may be withheld, conditioned or delayed for any or no reason.

(C)   If the Exclusive Operation is an Exploration Well in an area previously unexplored by the Parties (and outside the applicable acreage around or included in any prior Exclusive Operation) and results in a Discovery, then the Non-Consenting Parties must relinquish all of their rights to an area designated for the Discovery.  The Operator will designate the size of such area in its reasonable discretion; provided that the area will not be larger than the largest reasonable area to be associated with a common source of supply of hydrocarbons in the area to be drilled based on reasonable geophysical and geological interpretation prior to the commencement of the Exclusive Operation. Any dispute over the area designated, including any dispute over whether it overlaps with an area in which a Party claims an interest, shall be resolved by arbitration in accordance with Article 18.2 if the Parties are unable to resolve the matter through discussion and negotiation in less than thirty (30) days or, if sooner, prior to the planned commencement of drilling operations with respect to such Exclusive Operation; provided that Article 18.2(B) will be replaced with the language appearing below clause (D) below. Notwithstanding the foregoing, the area to be relinquished will be reduced in size, if necessary, to include only the boundaries and areas of the applicable Zone inside the area designated for the Discovery.  For the avoidance of doubt, no disagreement regarding: (i) the size of the area to be forfeited, (ii) the identity of the expert discussed in Article 18.2(B), nor (iii) any delay by the expert in rendering a decision, will obviate any provision of this Agreement, or hinder the Consenting Party’s right to drill on schedule as planned.

(D)   If the Exclusive Operation is an Appraisal Well or is Testing, Deepening or Sidetracking and results in a Discovery, then the Non-Consenting Party shall relinquish all of their rights to an area in size agreed by the Parties after good faith consideration of all relevant factors.  If the Parties are not able to agree on the size of the area to be relinquished, then the matter must be settled by binding arbitration as described in Article 18.2; provided that Article 18.2(B) will be replaced with the following:

“(B)           The arbitration shall be heard and determined by one (1) arbitrator, who may only select between the size and scope of the area presented by one (1) of the Parties (i.e. each Party must submit their proposal for the size of the area to be relinquished, and the arbitrator must pick one such proposal without modification).  If the Parties are not able to agree on the arbitrator expert within Five (5) Business Days after drilling commences, then the dispute will be submitted to Ryder Scott Company, who will be asked to select only one of the competing proposals, without modification.  The consenting and non-consenting Parties will share equally in any fees or expenses of the expert.  Any expert will be asked to make a determination in no more than Fifteen (15) Business Days."

7.5   Order of Preference of Operations

(A)   Except as otherwise specifically provided in this Agreement, if any Party desires to propose the conduct of an operation that will conflict with an existing proposal for an Exclusive Operation, such Party shall have the right exercisable for five (5) Days (or twenty-four (24) hours for Urgent Operational Matters) from receipt of the proposal for the Exclusive Operation, to deliver such Party’s alternative proposal to all Parties entitled to participate in the proposed operation.  Such alternative proposal shall contain the information required under Article 7.2(A).

(B)   Each Party receiving such proposals shall elect by delivery of notice to Operator and to the proposing Parties within the appropriate response period set out in Article 7.2(B) to participate in one of the competing proposals.  Any Party not notifying Operator and the proposing Parties within the response period shall be deemed to have voted against the proposals.

(C)   The proposal receiving the largest aggregate Participating Interest vote shall have priority over all other competing proposals.  In the case of a tie vote, Operator shall choose among the proposals receiving the largest aggregate Participating Interest vote.  Operator shall deliver notice of such result to all Parties entitled to participate in the operation within five (5) Days (or twenty-four (24) hours for Urgent Operational Matters).

(D)   Each Party shall then have two (2) Days (or twenty-four (24) hours for Urgent Operational Matters) from receipt of such notice to elect by delivery of notice to Operator and the proposing Parties whether such Party will participate in such Exclusive Operation, or will relinquish its interest pursuant to Article 7.4(B).  Failure by a Party to deliver such notice within such period shall be deemed an election not to participate in the prevailing proposal.

(E)   Notwithstanding the provisions of Article 7.4(B), if for reasons other than the encountering of granite or other practically impenetrable substance or any other condition in the hole rendering further operations impracticable, a well drilled as an Exclusive Operation fails to reach the deepest objective Zone described in the notice proposing such well, Operator shall give notice of such failure to each Non-Consenting Party who submitted or voted for an alternative proposal under this Article 7.5 to drill such well to a shallower Zone than the deepest objective Zone proposed in the notice under which such well was drilled.  Each such Non-Consenting Party shall have the option exercisable for forty-eight (48) hours

from receipt of such notice to participate for its Participating Interest share in the initial proposed Completion of such well.  Each such Non-Consenting Party may exercise such option by notifying Operator that it wishes to participate in such Completion and by paying its Participating Interest share of the cost of drilling such well to its deepest depth drilled in the Zone in which it is Completed.  All liabilities and expenses for drilling and Testing the Exclusive Well below that depth shall be for the sole account of the Consenting Parties.  If any such Non-Consenting Party does not properly elect to participate in the first Completion proposed for such well, the relinquishment provisions of Article 7.4(B) shall continue to apply to such Non-Consenting Party’s interest.

7.6   Stand-By Costs

(A)   When an operation has been performed, all tests have been conducted and the results of such tests furnished to the Parties, stand by costs incurred pending response to any Party’s notice proposing an Exclusive Operation for Deepening, Testing, Sidetracking, Completing, Plugging Back, Recompleting, Reworking or other further operation in such well (including the period required under Article 7.5 to resolve competing proposals) shall be charged and borne as part of the operation just completed. Any and all costs incurred subsequent to all Parties responding, or expiration of the response time permitted, whichever first occurs, shall be charged to and borne by the Parties proposing the Exclusive Operation in proportion to their Participating Interests, regardless of whether such Exclusive Operation is actually conducted.

(B)   If a further operation related to Urgent Operational Matters is proposed while the drilling rig to be utilized is on location, any Party may request and receive up to five (5) additional Days after expiration of the applicable response period specified in Article 7.2(B)(1) within which to respond by notifying Operator that such Party agrees to bear any and all costs incurred during such extended response period.  Operator may require such Party to pay the estimated costs in advance as a condition to extending the response period.  If more than one Party requests such additional time to respond to the notice, costs shall be allocated between such Parties on a Day-to-Day basis in proportion to their Participating Interests.

7.7   Special Considerations Regarding Deepening and Sidetracking

(A)   An Exclusive Well shall not be Deepened or Sidetracked without first affording the Non-Consenting Parties in accordance with this Article 7.7 the opportunity to participate in such operation.

(B)   In the event any Consenting Party desires to Deepen or Sidetrack an Exclusive Well, such Party shall initiate the procedure contemplated by Article 7.2.  If a Deepening or Sidetracking operation is approved pursuant to such provisions, and if any Non-Consenting Party to the Exclusive Well elects to participate in such Deepening or Sidetracking operation, such Non-Consenting Party’s Participating Interest share of the liabilities and expenses shall be as follows:

(1)   five hundred percent (500%) of such Non-Consenting Party's pro rata Participating Interest share of all liabilities and expenses that were

incurred in any Exclusive Operation relating to the obtaining of the portion of the G & G Data which pertains to the Discovery, and that were not previously paid by such Non-Consenting Party; plus

(2)   twelve hundred percent (1200%) of the Non-Consenting Party's pro rata Participating Interest share of al11iabilities and expenses that were incurred in any Exclusive Operation relating to the drilling, Deepening, Testing, Completing, Sidetracking, Plugging Back, Recompleting and Reworking of the Exploration Well which made the Discovery in which the Non-Consenting Patty desires to reinstate the rights it relinquished pursuant to Article 7.4(A), and that were not previously paid by such Non-Consenting Party; plus

(3)   eight hundred percent (800%) of the Non-Consenting Party's Participating Interest share of all liabilities and expenses that were incurred in any Exclusive Operation relating to the drilling, Deepening, Testing, Completing, Sidetracking, Plugging Back, Recompleting and Reworking of the Appraisal Well(s) which delineated the Discovery in which the Non-Consenting Party desires to reinstate the rights it relinquished pursuant to Article 7.4(A), and that were not previously paid by such Non-Consenting Party,

Each such Non-Consenting Party who is liable for such past liabilities must pay in full the amounts in this 7.7(B) as a condition precedent to participation in the Deepening or Sidetracking Operation of the Exclusive Well, payable immediately following the Non-Consenting Parties’ election to participate.

7.8   Use of Property

(A)   The Parties participating in any Deepening, Testing, Completing, Sidetracking, Plugging Back, Recompleting or Reworking of any well drilled under this Agreement shall be permitted to use (free of cost) all casing, tubing and other equipment in the well that is not needed for operations by the owners of the wellbore, but the ownership of all such equipment shall remain unchanged.  On abandonment of a well in which operations with differing participation have been conducted, the Parties abandoning the well shall account for all equipment in the well to the Parties owning such equipment by tendering to them their respective Participating Interest shares of the value of such equipment less the cost of salvage.

(B)   Any Party (whether owning interests in the platform or not) shall be permitted to use spare slots in a platform constructed pursuant to this Agreement for purposes of drilling Exploration Wells and/or Appraisal Wells and running tests in the Contract Area.  No Party except an owner of a platform may drill Development Wells or run production from a well (except production resulting from initial well tests) from the platform without the prior written consent of all platform owners.  If all owners of the platform participate in the drilling of a well, then no fee shall be payable under this Article 7.8(B).  Otherwise, each time a well is drilled from a platform, the Consenting Parties in the well shall pay to the owners of the platform until all wells drilled by such Parties have been plugged and abandoned a monthly fee equal to (1) that portion of the total cost of the platform (including

costs of material, fabrication, transportation and installation), divided by the number of months of useful life established for the platform under the tax law of the host country, that one well slot bears to the total number of slots on the platform plus (2) that proportionate part of the monthly cost of operating, maintaining and financing the platform that the well drilled under this Article 7.8(B) bears to the total number of wells served by such platform.  Consenting Parties who have paid to drill a well from a platform under this Article 7.8(B) shall be entitled to Deepen or Sidetrack that well for no additional charge if done prior to moving the drilling rig off of location.

(C)   Spare capacity in equipment that is constructed pursuant to this Agreement and used for processing or transporting Crude Oil and Natural Gas after it has passed through primary separators and dehydrators (including treatment facilities, gas processing plants and pipelines) shall be available for use by any Party for Hydrocarbon production from the Contract Area on the terms set forth below.  All Parties desiring to use such equipment shall nominate capacity in such equipment on a monthly basis by notice to Operator at least ten (10) Days prior to the beginning of each month.  Operator may nominate capacity for the owners of the equipment if they so elect.  If at any time the capacity nominated exceeds the total capacity of the equipment, the capacity of the equipment shall be allocated in the following priority:  (1) first, to the owners of the equipment up to their respective Participating Interest shares of total capacity, (2) second, to owners of the equipment desiring to use capacity in excess of their Participating Interest shares, in proportion to the Participating Interest of each such Party and (3) third, to Parties not owning interests in the equipment, in proportion to their Participating Interests in the Agreement.  Owners of the equipment shall be entitled to use up to their Participating Interest share of total capacity without payment of a fee under this Article 7.8(C). Otherwise, each Party using equipment pursuant to this Article 7.8(C) shall pay to the owners of the equipment monthly throughout the period of use an arm’s-length fee based upon third party charges for similar services in the vicinity of the Contract Area.  If no arm’s-length rates for such services are available, then the Party desiring to use equipment pursuant to this Article 7.8(C) shall pay to the owners of the equipment a monthly fee equal to (1) that portion of the total cost of the equipment, divided by the number of months of useful life established for such equipment under the tax law of the host country, that the capacity made available to such Party on a fee basis under this Article 7.8(C) bears to the total capacity of the equipment plus (2) that portion of the monthly cost of maintaining, operating and financing the equipment that the capacity made available to such Party on a fee basis under this Article 7.8(C) bears to the total capacity of the equipment.

(D)   Payment for the use of a platform under Article 7.8(B) or the use of equipment under Article 7.8(C) shall not result in an acquisition of any additional interest in the equipment or platform by the paying Parties.

(E)   Parties electing to use spare capacity on platforms or in equipment pursuant to Article 7.8(B) or Article 7.8(C) shall indemnify the owners of the equipment or platform against any and all costs and liabilities incurred as a result of such use (including any Consequential Loss and Environmental Loss).

7.9   Lost Production During Tie-In of Exclusive Operation Facilities

If, during the tie-in of Exclusive Operation facilities with the existing production facilities of another operation, the production of Hydrocarbons from such other pre-existing operations is temporarily lessened as a result, then the Consenting Parties shall compensate the parties to such existing operation for such loss of production in the following manner.  Operator shall determine the amount by which each Day’s production during the tie-in of Exclusive Operation facilities falls below the previous month’s average daily production from the existing production facilities of such operation.  The so-determined amount of lost production shall be recovered by all Parties who experienced such loss and shall be calculated by multiplying their proportionate share of lost production in accordance with their respective Participating Interest by 1.25.  Upon completion of the tie-in, all such lost production shall be recovered in full and satisfied by Operator deducting up to one hundred percent (100%) of the production from the Exclusive Operation for such duration as is necessary, prior to the Consenting Parties being entitled to receive any such production.

7.10   Conduct of Exclusive Operations

(A)   Each Exclusive Operation shall be carried out by the Consenting Parties acting as the Operating Committee, subject to the provisions of this Agreement applied mutatis mutandis to such Exclusive Operation and subject to the terms and conditions of the Contract.

(B)   The computation of liabilities and expenses incurred in Exclusive Operations, including the liabilities and expenses of Operator for conducting such operations, shall be made in accordance with the principles set out in the Accounting Procedure.

(C)   Operator shall maintain separate books, financial records and accounts for Exclusive Operations which shall be subject to the same rights of audit and examination as the Joint Account and related records, all as provided in the Accounting Procedure.  Said rights of audit and examination shall extend to each of the Consenting Parties and each of the Non-Consenting Parties so long as the latter are, or may be, entitled to elect to participate in such Exclusive Operations.

(D)   Operator, if it is conducting an Exclusive Operation for the Consenting Parties, regardless of whether it is participating in that Exclusive Operation, shall be entitled to request cash advances and shall not be required to use its own funds to pay any cost and expense and shall not be obliged to commence or continue Exclusive Operations until cash advances requested have been made, and the Accounting Procedure shall apply to Operator in respect of any Exclusive Operations conducted by it.

(E)   Should the submission of a Development Plan be approved in accordance with Article 6.2, or should any Party propose (but not yet have the right to commence) a development in accordance with this Article 7 where neither the Development Plan nor the development proposal call for the conduct of additional appraisal drilling, and should any Party wish to drill an additional Appraisal Well prior to development, then the Party proposing the Appraisal Well as an Exclusive

Operation shall be entitled to proceed first.  If such an Appraisal Well is produced, any Consenting Party shall own and have the right to take in kind and separately dispose of all of the Non-Consenting Party’s Entitlement from such Appraisal Well until the value received in sales to purchasers in arm-length transactions equals one hundred percent (100%) of such Non-Consenting Party’s Participating Interest shares of all liabilities and expenses that were incurred in any Exclusive Operations relating to the Appraisal Well.  Following the completion of drilling such Appraisal Well as an Exclusive Operation, the Parties may proceed with the Development Plan approved pursuant to Article 5.9, or (if applicable) the Parties may complete the procedures to propose an Exclusive Operation to develop a Discovery.  If, as the result of drilling such Appraisal Well as an Exclusive Operation, the Party or Parties proposing to develop the Discovery decide(s) not to do so, then each Non-Consenting Party who voted in favor of such Development Plan prior to the drilling of such Appraisal Well shall pay to the Consenting Party the amount such Non-Consenting Party would have paid had such Appraisal Well been drilled as a Joint Operation.

(F)   If Operator is a Non-Consenting Party to an Exclusive Operation to develop a Discovery, then Operator may resign as Operator for the Exploitation Area for such Discovery.  If Operator so resigns, the Consenting Parties shall select a Consenting Party to serve as Operator for such Exclusive Operation only.  Any such resignation of Operator and appointment of a Consenting Party to serve as Operator for such Exclusive Operation shall be subject to the Parties having first obtained any necessary Government approvals.

ARTICLE 8.

DEFAULT

8.1   Default and Notice

(A)   Any Party that fails to:

(1)   pay when due its share of Joint Account expenses (including cash advances and interest); or

(2)   obtain and maintain any Security required of such Party under the Contract or this Agreement;

shall be in default under this Agreement (a “Defaulting Party”). Operator, or any non-defaulting Party in case Operator is the Defaulting Party (the “Notifying Party”) shall promptly give notice of such default (the “Default Notice”) to the Defaulting Party and each of the non-defaulting Parties.

(B)   For the purposes of this Article 8, “Default Period” means the period beginning five (5) Business Days from the date that the Default Notice is issued in accordance with this Article 8.1 and ending when all the Defaulting Party’s defaults pursuant to this Article 8.1 have been remedied in full.

8.2   Operating Committee Meetings and Data

(A)   Notwithstanding any other provision of this Agreement, the Defaulting Party shall have no right, during the Default Period, to:

(1)   call or attend Operating Committee or subcommittee meetings;

(2)   vote on any matter coming before the Operating Committee or any subcommittee;

(3)   access any data or information relating to any operations under this Agreement;

(4)   consent to or reject data trades between the Parties and third parties, nor access any data received in such data trades;

(5)   Transfer (as defined in Article 12.1) all or part of its Participating Interest, except to non-defaulting Parties in accordance with this Article 8;

(6)   consent to or reject any Transfer (as defined in Article 12.1) or otherwise exercise any other rights in respect of Transfers under this Article 8 or under Article 12;

(7)   receive its Entitlement in accordance with Article 8.4;

(8)   withdraw from this Agreement under Article 13; or

(9)   take assignment of any portion of another Party’s Participating Interest in the event such other Party is either in default or withdrawing from this Agreement and the Contract.

(B)   Notwithstanding any other provisions in this Agreement, during the Default Period:

(1)   unless agreed otherwise by the non-defaulting Parties, the voting interest of each non-defaulting Party shall be equal to the ratio of such non-defaulting Party’s Participating Interest to the total Participating Interests of the non-defaulting Parties;

(2)   any matters requiring a unanimous vote or approval of the Parties shall not require the vote or approval of the Defaulting Party;

(3)   the Defaulting Party shall be deemed to have elected not to participate in any operations that are voted upon during the Default Period, to the extent such an election would be permitted by Article 5.13 and Article 7; and

(4)   the Defaulting Party shall be deemed to have approved, and shall join with the non-defaulting Parties in taking, any other actions voted on during the Default Period.

8.3   Allocation of Defaulted Accounts

(A)   The Party providing the Default Notice pursuant to Article 8.1 shall include in the Default Notice to each non-defaulting Party a statement of: (i) the sum of money that the non-defaulting Party shall pay as its portion of the Amount in Default; and (ii) if the Defaulting Party has failed to obtain or maintain any Security required of such Party in order to maintain the Contract in full force and effect, the type and amount of the Security the non-defaulting Parties shall post or the funds they shall pay in order to allow Operator, or (if Operator is in default) the Notifying Party, to post and maintain such Security.  Unless otherwise agreed, the obligations for which the Defaulting Party is in default shall be satisfied by the non-defaulting Parties in proportion to the ratio that each non-defaulting Party's Participating Interest bears to the Participating Interests of all non-defaulting Parties.  For the purposes of this Article 8:

“Amount in Default” means the Defaulting Party’s share of Joint Account expenses which the Defaulting Party has failed to pay when due pursuant to the terms of this Agreement (but excluding any interest owed on such amount); and

“Total Amount in Default” means the following amounts: (i) the Amount in Default; (ii) third-party costs of obtaining and maintaining any Security incurred by the non-defaulting Parties or the funds paid by such Parties in order to allow Operator to obtain or maintain Security, in accordance with Article 8.3(A)(ii); plus (iii) any interest at the Agreed Interest Rate accrued on the amount under (i) from the date this amount is due by the Defaulting Party until paid in full by the Defaulting Party and on the amount under (ii) from the date this amount is incurred by the non-defaulting Parties until paid in full by the Defaulting Party.

(B)   If the Defaulting Party remedies its default in full before the Default Period commences, the Notifying Party shall promptly notify each non-defaulting Party by telephone and by email, and the non-defaulting Parties shall be relieved of their obligations under Article 8.3(A).  Otherwise, each non-defaulting Party shall satisfy its obligations under Article 8.3(A)(i) before the Default Period commences and its obligations under Article 8.3(A)(ii) within ten (10) Days following the Default Notice.  If any non-defaulting Party fails to timely satisfy such obligations, such Party shall thereupon be a Defaulting Party subject to the provisions of this Article 8.  The non-defaulting Parties shall be entitled to receive their respective shares of the Total Amount in Default payable by such Defaulting Party pursuant to this Article 8.

(C)   If Operator is a Defaulting Party, then all payments otherwise payable to Operator for Joint Account costs pursuant to this Agreement shall be made to the Notifying Party instead until the default is cured or a successor Operator appointed.  The Notifying Party shall maintain such funds in a segregated account separate from its own funds and shall apply such funds to third party

 claims due and payable from the Joint Account of which it has notice, to the extent Operator would be authorized to make such payments under the terms of this Agreement.  The Notifying Party shall be entitled to bill or cash call the other Parties in accordance with the Accounting Procedure for proper third party charges that become due and payable during such period to the extent sufficient funds are not available.  When Operator has cured its default or a successor Operator is appointed, the Notifying Party shall turn over all remaining funds in the account to Operator and shall provide Operator and the other Parties with a detailed accounting of the funds received and expended during this period.  The Notifying Party shall not be liable for damages, losses, costs, expenses or liabilities arising as a result of its actions under this Article 8.3(C), except to the extent Operator would be liable under Article 4.6.

8.4   Remedies

(A)   During the Default Period, the Defaulting Party shall not have a right to its Entitlement, which shall vest in and be the property of the non-defaulting Parties.  Operator (or the Notifying Party if Operator is a Defaulting Party) shall be authorized to sell such Entitlement in an arm’s-length sale on terms that are commercially reasonable under the circumstances and, after deducting all costs, charges and expenses incurred in connection with such sale, pay the net proceeds to the non-defaulting Parties in proportion to the amounts they are owed by the Defaulting Party as a part of the Total Amount in Default (in payment of first the interest and then the principal) and apply such net proceeds toward the establishment of the Reserve Fund (as defined in Article 8.4(C)), if applicable, until all such Total Amount in Default is recovered and such Reserve Fund is established.  Any surplus remaining shall be paid to the Defaulting Party, and any deficiency shall remain a debt due from the Defaulting Party to the non-defaulting Parties.  When making sales under this Article 8.4(A), the non-defaulting Parties shall have no obligation to share any existing market or obtain a price equal to the price at which their own production is sold.

(B)   If Operator disposes of any Joint Property or if any other credit or adjustment is made to the Joint Account during the Default Period, Operator (or the Notifying Party if Operator is a Defaulting Party) shall be entitled to apply the Defaulting Party’s Participating Interest share of the proceeds of such disposal, credit or adjustment against the Total Amount in Default (against first the interest and then the principal) and toward the establishment of the Reserve Fund (as defined in Article 8.4(C)), if applicable.  Any surplus remaining shall be paid to the Defaulting Party, and any deficiency shall remain a debt due from the Defaulting Party to the non-defaulting Parties.

(C)   The non-defaulting Parties shall be entitled to apply the net proceeds received under Articles 8.4(A) and 8.4(B) toward the creation of a reserve fund (the “Reserve Fund”) in an amount equal to the Defaulting Party’s Participating Interest share of: (i) the estimated cost to abandon any wells and other property in which the Defaulting Party participated; (ii) the estimated cost of severance benefits for local employees upon cessation of operations; and (iii) any other identifiable costs that the non-defaulting Parties anticipate will be incurred in connection with the cessation of operations. Upon the conclusion of the Default Period by way of the Defaulting Party curing its Default, all amounts held in the

Reserve Fund shall be returned to the Defaulting Party previously in Default, less any and all amounts allocated under Article 8.4 and all costs and fees incurred in the enforcement of this Article 8.4, including all legal costs and fees.

(D)   If a Defaulting Party fails to fully remedy all its defaults by the thirtieth (30th) Day following the date of the Default Notice, then, without prejudice to any other rights available to each non-defaulting Party to recover its portion of the Total Amount in Default, a majority in interest of the non-defaulting Parties (after excluding Affiliates of the Defaulting Party) shall have the option, exercisable at anytime thereafter during the Default Period, to require that the Defaulting Party completely withdraw from this Agreement and the Contract.  Such option shall be exercised by notice to the Defaulting Party and each non-defaulting Party.  If such option is exercised, the Defaulting Party shall be deemed to have transferred, pursuant to Article 13.6, effective on the date of the non-defaulting Party’s or Parties’ notice, its Participating Interest to the non-defaulting Parties.  Notwithstanding the terms of Article 13, in the absence of an agreement among the non-defaulting Parties to the contrary, any transfer to the non-defaulting Parties following a withdrawal pursuant to this Article 8.4(D)(1) shall be in proportion to the Participating Interests of the non-defaulting Parties.

(E)   In addition to the other remedies available to the non-defaulting Parties under this Article 8 and any other rights available to each non-defaulting Party to recover its portion of the Total Amount in Default, in the event a Defaulting Party fails to remedy its default within thirty (30) Days of the Default Notice, the non-Defaulting Parties may elect to enforce a mortgage and security interest on the Defaulting Party’s Participating Interest as set forth below, subject to the Contract and the Laws / Regulations. 

(1)   Each Party grants to each of the other Parties, in pro rata shares based on their relative Participating Interests, a mortgage and security interest on its Participating Interest, whether now owned or hereafter acquired, together with all products and proceeds derived from that Participating Interest (collectively, the “Collateral”) as security for (i) the payment of all amounts owing by such Party (including interest and costs of collection) under this Agreement; and (ii) any Security which such Party is required to provide under the Contract. 

(2)   Should a Defaulting Party fail to remedy its default by the thirtieth (30th) Day following the date of the Default Notice, then, each non-defaulting Party shall have the option, exercisable at any time thereafter during the Default Period, to foreclose its mortgage and security interest against its prorata share of the Collateral by any means permitted under the Contract and the Laws / Regulations and to sell all or any part of that Collateral in public or private sale after providing the Defaulting Party and other creditors with any notice required by the Contract or the Laws / Regulations, and subject to the provisions of Article 12.   Except as may be prohibited by the Contract or the Laws / Regulations, the non-defaulting Party that forecloses its mortgage and security interest shall be entitled to become the purchaser of the Collateral sold and shall have the right to credit toward the purchase price the amount to which it is entitled under Article 8.4.   Any deficiency in the amounts received by the

foreclosing party shall remain a debt due by the Defaulting Party.  The foreclosure of mortgages and security interests by one non-defaulting Party shall neither affect the amounts owed by the Defaulting Party to the other non-defaulting Parties nor in any way limit the rights or remedies available to them.  Each Party agrees that, should it become a Defaulting Party, it waives the benefit of any appraisal, valuation, stay, extension or redemption law and any other debtor protection law that otherwise could be invoked to prevent or hinder the enforcement of the mortgage and security interest granted above.

(3)   Each Party agrees to execute such memoranda, financing statements and other documents, and make such filings and registrations, as may be reasonably necessary to perfect, validate and provide notice of the mortgages and security interests granted by this Article 8.4(E). 

(F)   For purposes of Articles 8.4(D) and 8.4(E), the Defaulting Party shall, without delay following any request from the non-defaulting Parties, do any act required to be done by the Laws / Regulations and any other applicable laws in order to render the transfer of its Participating Interest legally valid, including obtaining all governmental consents and approvals, and shall execute any document and take such other actions as may be necessary in order to effect a prompt and valid transfer.  The Defaulting Party shall be obligated to promptly remove any liens and encumbrances which may exist on its assigned Participating Interests.  In the event all Government approvals are not timely obtained, the Defaulting Party shall hold the assigned Participating Interest in trust for the non-defaulting Parties who are entitled to receive it.  Each Party constitutes and appoints each other Party its true and lawful attorney to execute such instruments and make such filings and applications as may be necessary to make such transfer legally effective and to obtain any necessary consents of the Government.  Actions under this power of attorney may be taken by any Party individually without the joinder of the others.  This power of attorney is irrevocable for the term of this Agreement and is coupled with an interest.  If requested, each Party shall execute a form prescribed by the Operating Committee setting forth this power of attorney in more detail.

(G)   The non-defaulting Parties shall be entitled to recover from the Defaulting Party all reasonable attorneys’ fees and all other reasonable costs sustained in the collection of amounts owing by the Defaulting Party.

(H)   The rights and remedies granted to the non-defaulting Parties in this Article 8 shall be cumulative, not exclusive, and shall be in addition to any other rights and remedies that may be available to the non-defaulting Parties, whether at law, in equity or otherwise.  Each right and remedy available to the non-defaulting Parties may be exercised from time to time and so often and in such order as may be considered expedient by the non-defaulting Parties in their sole discretion.

8.5   Survival

The obligations of the Defaulting Party and the rights of the non-defaulting Parties shall survive the surrender of the Contract, abandonment of Joint Operations and termination of this Agreement.

8.6   No Right of Set Off

Each Party acknowledges and accepts that a fundamental principle of this Agreement is that each Party pays its Participating Interest share of all amounts due under this Agreement as and when required.  Accordingly, any Party which becomes a Defaulting Party undertakes that, in respect of either any exercise by the non-defaulting Parties of any rights under or the application of any of the provisions of this Article 8, such Party hereby waives any right to raise by way of set off or invoke as a defense, whether in law or equity, any failure by any other Party to pay amounts due and owing under this Agreement or any alleged claim that such Party may have against Operator or any Non-Operator, whether such claim arises under this Agreement or otherwise.  Each Party further agrees that the nature and the amount of the remedies granted to the non-defaulting Parties hereunder are reasonable and appropriate in the circumstances.

ARTICLE 9.

DISPOSITION OF PRODUCTION

9.1   No Right or Obligation to Take in Kind

If Crude Oil or Natural Gas is to be produced, then the Operator will market the production on behalf of the Parties, such that all Parties will, to the extent commercially and operationally practicable, enjoy the same economic benefits of any such marketing and further that no Party will benefit to the detriment of any other Party as a result of Operator’s marketing efforts. Any Party represented at the Operating Committee may, at any time, inform the Operator that it takes objection to the proposed terms to dispose of Crude Oil or Natural Gas, and the Operating Committee shall consider promptly those concerns; provided that the plan of disposition presented by the Operator shall control in the absence of unanimous agreement, subject to the dispute resolution provisions of this Agreement. No Party will have the option to take its Participating Interest share in kind without the Operator’s prior written consent. If mutually desired, the Parties will negotiate and conclude the terms of an agreement to cover the offtake of Crude Oil or Natural Gas produced under the License.

9.2   Disposition of Crude Oil

The Parties shall in good faith, and not less than three (3) months prior to the anticipated first delivery of Crude Oil, as promptly notified by Operator, negotiate and endeavor to conclude the terms of a lifting agreement to cover the offtake of Crude Oil produced under the Contract.

9.3   Disposition of Natural Gas

The Parties recognize that if Natural Gas is discovered it may be necessary for the Parties to enter into special arrangements for the disposal of the Natural Gas, which are consistent with the Development Plan and subject to the terms of the Contract.

ARTICLE 10.

ABANDONMENT

10.1   Abandonment of Wells Drilled as Joint Operations

(A)   A decision to plug and abandon any well which has been drilled as a Joint Operation shall require the approval of the Operating Committee.

(B)   Should any Party fail to reply within the period prescribed in Article 5.12(A)(1) or Article 5.12(A)(2), whichever is applicable, after delivery of notice of Operator’s proposal to plug and abandon such well, such Party shall be deemed to have consented to the proposed abandonment.

(C)   If the Operating Committee approves a decision to plug and abandon an Exploration Well or Appraisal Well, subject to the Laws / Regulations, any Party voting against such decision may propose (within the time periods allowed by Article 5.13(A)) to conduct an alternate Exclusive Operation in the wellbore.  If no Exclusive Operation is timely proposed, or if an Exclusive Operation is timely proposed but is not commenced within the applicable time periods under Article 7.2, such well shall be plugged and abandoned.

(D)   Any well plugged and abandoned under this Agreement shall be plugged and abandoned in accordance with the Laws / Regulations and at the cost, risk and expense of the Parties who participated in the cost of drilling such well.

(E)   Notwithstanding anything to the contrary in this Article 10.1:

(1)   If the Operating Committee approves a decision to plug and abandon a well from which Hydrocarbons have been produced and sold, subject to the Laws / Regulations, any Party voting against the decision may propose (within five (5) Days after the time specified in Article 5.6, Article 5.12(A)(1) or Article 5.12(A)(2), whichever is applicable, has expired) to take over the entire well as an Exclusive Operation.  Any Party originally participating in the well shall be entitled to participate in the operation of the well as an Exclusive Operation by response notice within ten (10) Days after receipt of the notice proposing the Exclusive Operation. In such event, the Consenting Parties shall be entitled to conduct an Exclusive Operation in the well; provided that the proposed operation may not be in the same Zone from which production was previously obtained nor be in a Zone which is produced by any other Joint Operation wells.

(2)   Each Non-Consenting Party shall be deemed to have relinquished free of cost to the Consenting Parties in proportion to their Participating Interests all of its interest in the wellbore of a produced well and related equipment in accordance with Article 7.4(B).  The Consenting Parties shall thereafter bear all cost and liability of plugging and abandoning such well in accordance with the Laws / Regulations, to the extent the Parties are or become obligated to contribute to such costs and liabilities,

and shall indemnify the Non-Consenting Parties against all such costs and liabilities.

(3)   Subject to Article 7.12(F), Operator shall continue to operate a produced well for the account of the Consenting Parties at the rates and charges contemplated by this Agreement, plus any additional cost and charges which may arise as the result of the separate allocation of interest in such well.

10.2   Abandonment of Exclusive Operations

This Article 10 shall apply mutatis mutandis to the abandonment of an Exclusive Well or any well in which an Exclusive Operation has been conducted (in which event all Parties having the right to conduct further operations in such well shall be notified and have the opportunity to conduct Exclusive Operations in the well in accordance with the provisions of this Article 10).

10.3   Abandonment Security

If under the Contract or the Laws / Regulations, the Parties are or become obliged to pay or contribute to the cost of ceasing operations, then during preparation of a Development Plan, the Parties shall negotiate a security agreement, which shall be completed and executed by all Parties participating in such Development Plan prior to application for an Exploitation Area.  The security agreement shall incorporate the following principles:

(A)   a Security shall be provided by each such Party for each Calendar Year commencing with the Calendar Year in which the Discounted Net Value equals one hundred fifty percent (150%) of the Discounted Net Cost; and

(B)   the amount of the Security required to be provided by each such Party in any Calendar Year (including any security previously provided which will still be current throughout such Calendar Year) shall be equal to the amount by which one hundred fifty percent (150%) of the Discounted Net Cost exceeds the Discounted Net Value.

“Discounted Net Cost” means that portion of each Party’s anticipated before tax cost of ceasing operations in accordance with the Laws / Regulations which remains after deduction of salvage value.  Such portion should be calculated at the anticipated time of ceasing operations and discounted at the Discount Rate to December 31 of the Calendar Year in question.

“Discounted Net Value” means the value of each Party’s estimated Entitlement which remains after payment of estimated liabilities and expenses required to win, save and transport such production to the delivery point and after deduction of estimated applicable taxes, royalties, imposts and levies on such production.  Such Entitlement shall be calculated using estimated market prices and including taxes on income, discounted at the Discount Rate to December 31 of the Calendar Year in question.  No account shall be taken of tax allowances expected to be available in respect of the costs of ceasing operations.

“Discount Rate” means the rate per annum equal to the one (1) month term, London Interbank Offered Rate (LIBOR rate) for U.S. dollar deposits applicable to the date

falling thirty (30) Business Days prior to the start of a Calendar Year as published in London by the Financial Times or if not published then by The Wall Street Journal.

ARTICLE 11.

SURRENDER, EXTENSIONS AND RENEWALS

11.1   Surrender

(A)   If the Contract requires the Parties to surrender any portion of the Contract Area, Operator shall advise the Operating Committee of such requirement at least one hundred and twenty (120) Days in advance of the earlier of the date for filing irrevocable notice of such surrender or the date of such surrender.  Prior to the end of such period, the Operating Committee shall determine pursuant to Article 5 the size and shape of the surrendered area, consistent with the requirements of the Contract.  If a sufficient vote of the Operating Committee cannot be attained, then the proposal supported by a simple majority of the Participating Interests shall be adopted.  If no proposal attains the support of a simple majority of the Participating Interests, then the proposal receiving the largest aggregate Participating Interest vote shall be adopted.  In the event of a tie, Operator shall choose among the proposals receiving the largest aggregate Participating Interest vote.  The Parties shall execute any and all documents and take such other actions as may be necessary to effect the surrender.  Each Party renounces all claims and causes of action against Operator and any other Parties on account of any area surrendered in accordance with the foregoing but against its recommendation if Hydrocarbons are subsequently discovered under the surrendered area.

(B)   A surrender of all or any part of the Contract Area which is not required by the Contract shall require the unanimous consent of the Parties.

11.2   Extension of the Term

(A)   A proposal by any Party to enter into or extend the term of any Exploration or Exploitation Period or any phase of the Contract, or a proposal to extend the term of the Contract, shall be brought before the Operating Committee pursuant to Article 5.

(B)   Any Party shall have the right to enter into or extend the term of any Exploration or Exploitation Period or any phase of the Contract or to extend the term of the Contract, regardless of the level of support in the Operating Committee.  If any Party takes such action, any Party not wishing to extend shall have a right to withdraw, subject to the requirements of Article 13.

ARTICLE 12.

TRANSFER OF INTEREST OR RIGHTS

12.1   Obligations

Subject to the requirements of the Contract, any Transfer (except Transfers pursuant to Article 7, Article 8 or Article 13) shall be effective only if it satisfies the terms and conditions of this Article 12.  Should a Transfer subject to this Article or a Change in Control occur without

satisfaction (in all material respects) by the transferor or the Party subject to the Change in Control, as applicable, of the requirements hereof, then: each other Party shall be entitled to enforce specific performance of the terms of this Article, in addition to any other remedies (including damages) to which it may be entitled.  Each Party agrees that monetary damages alone would not be an adequate remedy for the breach of any Party's obligations under this Article.

“Change in Control” means any direct or indirect change in Control of a Party (whether through merger, sale of shares or other equity interests, or otherwise) through a single transaction or series of related transactions, from one or more transferors to one or more transferees, in which the market value of the Party's Participating Interest represents more than fifty percent (50%) of the aggregate market value of the assets of such Party and its Affiliates that are subject to the change in Control.   For the purposes of this definition, market value shall be determined based upon the amount in cash a willing buyer would pay a willing seller in an arm's length transaction.

“Encumbrance” means a mortgage, lien, pledge, charge or other encumbrance.  “Encumber” and other derivatives shall be construed accordingly.

12.2   Transfer

(A)   Except in the case of a Party transferring all of its Participating Interest, no Transfer shall be made by any Party which results in the transferor or the transferee holding a Participating Interest of less than five percent (5%) or any interest other than a Participating Interest in the Contract and this Agreement. If a Party holds a Participating Interest of five percent (5%) or less prior to any Transfer, then such Party may only Transfer to an existing Party, unless each other Party consents in advance to a Transfer to a person or entity that is not at the time a Party, which consent may be withheld, conditioned or delayed for any or no reason.

(B)   Subject to the terms of Articles 4.9 and 4.10, the Party serving as Operator shall remain Operator following Transfer of a portion of its Participating Interest. If Operator transfers all of its Participating Interest to an Affiliate, that Affiliate shall automatically become the successor Operator, provided that the transferring Operator shall remain liable for its Affiliate's performance of its obligations.

(C)   Both the transferee, and, notwithstanding the Transfer, the transferring Party, shall be liable to the other Parties for the transferring Party’s Participating Interest share of any obligations (financial or otherwise) which have vested, matured or accrued under the provisions of the Contract or this Agreement prior to such Transfer.  Such obligations, shall include any proposed expenditure approved by the Operating Committee prior to the transferring Party notifying the other Parties of its proposed Transfer and shall also include costs of plugging and abandoning wells or portions of wells and decommissioning facilities in which the transferring Party participated (or with respect to which it was required to bear a share of the costs pursuant to this sentence) to the extent such costs are payable by the Parties under the Contract.

(D)   A transferee shall have no rights in the Contract or this Agreement (except any notice and cure rights or similar rights that may be provided to a Lien Holder (as defined in Article 12.2(E)) by separate instrument signed by all Parties) unless and until:

(1)   it expressly undertakes in an instrument reasonably satisfactory to the other Parties to perform the obligations of the transferor under the Contract and this Agreement in respect of the Participating Interest being transferred and obtains any necessary Government approval for the Transfer and furnishes any guarantees required by the Government or the Contract on or before the applicable deadlines; and

(2)   except in the case of a Transfer to an Affiliate, each Party has consented in writing to such Transfer, which consent shall be denied only if the transferee fails to establish to the reasonable satisfaction of each Party its financial capability to perform its payment obligations under the Contract and this Agreement.

No consent shall be required under Article 12.2(D)(2) for a Transfer to an Affiliate if the transferring Party agrees in an instrument reasonably satisfactory to the other Parties to remain liable for its Affiliate’s performance of its obligations.

(E)   Nothing contained in this Article 12 shall prevent a Party from Encumbering all or any undivided share of its Participating Interest to a third party (a “LienHolder”) for the purpose of security relating to finance, provided that:

(1)   such Party shall remain liable for all obligations relating to such interest;

(2)   the Encumbrance shall be subject to any necessary approval of the Government expressly subordinated to the rights of the other Parties under this Agreement;

(3)   such Party shall ensure that any Encumbrance shall be expressed to be without prejudice to the provisions of this Agreement; and

(4)   the Lien Holder shall first enter into and deliver a subordination agreement in favor of the other Parties, in substantially the form approved by the Operating Committee in consultation with legal counsel.

12.3   Change in Control

(A)   A Party subject to a Change in Control shall obtain any necessary Government approval with respect to the Change in Control and furnish any replacement Security required by the Government or the Contract on or before the applicable deadlines.

(B)   A Party subject to a Change in Control shall provide evidence reasonably satisfactory to the Operating Committee that following the Change in Control such Party shall continue to have the financial capability to satisfy its payment obligations under the Contract and this Agreement.  Should the Party that is subject to the Change in Control fail to provide such evidence as determined by the Operating Committee, any other Party, by notice to such Party, may require such Party to provide Security satisfactory to the other Parties with respect to its

Participating Interest share of any obligations or liabilities which the Parties may reasonably be expected to incur under the Contract and this Agreement during the then-current Exploration or Exploitation Period or phase of the Contract.

ARTICLE 13.

WITHDRAWAL FROM AGREEMENT

13.1   Right of Withdrawal

(A)   Subject to the provisions of this Article 13 and the Contract, any Party not in default may at its option withdraw from this Agreement and the Contract by giving notice to all other Parties stating its decision to withdraw.  Such notice shall be unconditional and irrevocable when given, except as may be provided in Article 13.7.

(B)   The effective date of withdrawal for a withdrawing Party shall be the end of the third (3rd) calendar month following the calendar month in which the notice of withdrawal is given, provided that if all Parties elect to withdraw, the effective date of withdrawal for each Party shall be the date determined by Article 13.9.

13.2   Partial or Complete Withdrawal

(A)   Within thirty (30) Days of receipt of each withdrawing Party’s notification, each of the other Parties may also give notice that it desires to withdraw from this Agreement and the Contract.  Should all Parties give notice of withdrawal, the Parties shall proceed to abandon the Contract Area and terminate the Contract and this Agreement.  If less than all of the Parties give such notice of withdrawal, then the withdrawing Parties shall take all steps to withdraw from the Contract and this Agreement on the earliest possible date and execute and deliver all necessary instruments and documents to assign their Participating Interest to the Parties which are not withdrawing, without any compensation whatsoever, in accordance with the provisions of Article 13.6.

(B)   Any Party withdrawing under Article 11.2 or under this Article 13 shall withdraw from the entirety of the Contract Area, including all Exploitation Areas and all Discoveries made prior to such withdrawal, and thus abandon to the other Parties not joining in its withdrawal all its rights to the production generated by operations after the effective date of such withdrawal and all rights in associated Joint Property.

13.3   Rights of a Withdrawing Party

Subject to Article 13.8 and any other provision of this Agreement, a withdrawing Party shall have the right to receive its Entitlement produced through the effective date of its withdrawal.  The withdrawing Party shall be entitled to receive all information to which such Party is otherwise entitled under this Agreement until the effective date of its withdrawal.  After giving its notification of withdrawal, a Party shall not be entitled to vote on any matters coming before the Operating Committee, other than matters for which such Party has financial responsibility.

13.4   Obligations and Liabilities of a Withdrawing Party

(A)   A withdrawing Party shall, following its notification of withdrawal, remain liable only for its share of the following:

(1)   costs of Joint Operations, and Exclusive Operations in which it has agreed to participate, that were approved by the Operating Committee or Consenting Parties as part of a Work Program and Budget (including a multi-year Work Program and Budget under Article 6.5) prior to such Party’s notification of withdrawal, regardless of when they are incurred;

(2)   expenditures described in Articles 4.2(B)(13) and 13.5 related to an emergency occurring prior to the effective date of a Party’s withdrawal, regardless of when such expenditures are incurred;

(3)   all other obligations and liabilities of the Parties or Consenting Parties, as applicable, with respect to acts or omissions under this Agreement prior to the effective date of such Party’s withdrawal for which such Party would have been liable, had it not withdrawn from this Agreement; and

(4)   in the case of a partially withdrawing Party, any costs and liabilities with respect to Exploitation Areas, Commercial Discoveries and Discoveries from which it has not withdrawn.

The obligations and liabilities for which a withdrawing Party remains liable shall specifically include its share of any costs of plugging and abandoning wells or portions of wells in which it participated (or was required to bear a share of the costs pursuant to Article 13.4(A)(1)) to the extent such costs of plugging and abandoning are payable by the Parties under the Contract.  Any mortgages, liens, pledges, charges or other encumbrances which were placed on the withdrawing Party’s Participating Interest prior to such Party’s withdrawal shall be fully satisfied or released, at the withdrawing Party’s expense, prior to its withdrawal.  A Party’s withdrawal shall not relieve it from liability to the non-withdrawing Parties with respect to any obligations or liabilities attributable to the withdrawing Party under this Article 13 merely because they are not identified or identifiable at the time of withdrawal.

(B)   Notwithstanding the foregoing, a Party shall not be liable for any operations or expenditures it voted against (other than operations and expenditures described in Article 13.4(A)(2) or Article 13.4(A)(3)) if it sends notification of its withdrawal within five (5) Days (or within twenty-four (24) hours for Urgent Operational Matters) of the Operating Committee vote approving such operation or expenditure.

13.5   Emergency

If a well goes out of control or a fire, blow out, sabotage or other emergency occurs prior to the effective date of a Party’s withdrawal, the withdrawing Party shall remain liable for its Participating Interest share of the costs of such emergency, regardless of when they are incurred.

13.6   Assignment

A withdrawing Party shall assign its Participating Interest free of cost to each of the non-withdrawing Parties in the proportion which each of their Participating Interests (prior to the withdrawal) bears to the total Participating Interests of all the non-withdrawing Parties (prior to the withdrawal), unless the non-withdrawing Parties agree otherwise.  The expenses associated with the withdrawal and assignments shall be borne by the withdrawing Party.

13.7   Approvals

A withdrawing Party shall promptly join in such actions as may be necessary or desirable to obtain any Government approvals required in connection with the withdrawal and assignments.  The non-withdrawing Parties shall use reasonable endeavors to assist the withdrawing Party in obtaining such approvals.  Any penalties or expenses incurred by the Parties in connection with such withdrawal shall be borne by the withdrawing Party.  If the Government does not approve a Party’s withdrawal and assignment to the other Parties, then the withdrawing Party shall at its option either (1) retract its notice of withdrawal by notice to the other Parties and remain a Party as if such notice of withdrawal had never been sent, or (2) hold its Participating Interest in trust for the sole and exclusive benefit of the non-withdrawing Parties with the right to be reimbursed by the non-withdrawing Parties for any subsequent costs and liabilities incurred by it for which it would not have been liable, had it successfully withdrawn.

13.8   Security

Prior to a Party withdrawing from this Agreement and the Contract pursuant to this Article 13, the withdrawing party shall provide Security satisfactory to the other Parties to satisfy any obligations or liabilities for which the withdrawing Party remains liable in accordance with Article 13.4, but which may become due after the withdrawing Party’s withdrawal, including but not limited to Security to cover the costs of an abandonment, if applicable.  Until the form of Security is approved by the non-withdrawing Parties and thereafter obtained by the withdrawing Party:

(A)   the Entitlements of the withdrawing Party shall be withheld from the withdrawing Party and may be accumulated to satisfy the Security or set-off as against those costs referenced in Article 13.4; and

(B)   the withdrawing Party constitutes and appoints each other non-withdrawing Party its true and lawful attorney to execute such instruments and make such filings and applications as may be necessary to make such Security legally effective and to obtain any necessary consents of the Government and other agencies.  Actions under this power of attorney may be taken by any Party individually without the joinder of the others.  This power of attorney is irrevocable for the term of this Agreement and is coupled with an interest.  If requested, each Party shall execute a form prescribed by the Operating Committee setting forth this power of attorney in more detail

13.9   Withdrawal or Abandonment by All Parties

In the event all Parties decide to withdraw, the Parties agree that they shall be bound by the terms and conditions of this Agreement for so long as may be necessary to wind up the affairs of the Parties with the Government, to satisfy any requirements of the Laws / Regulations and to facilitate the sale, disposition or abandonment of property or interests held by the Joint Account, all in accordance with Article 2.

ARTICLE 14.

RELATIONSHIP OF PARTIES AND TAX

14.1   Relationship of Parties

The rights, duties, obligations and liabilities of the Parties under this Agreement shall be individual, not joint or collective.  It is not the intention of the Parties to create, nor shall this Agreement be deemed or construed to create, a mining or other partnership, joint venture or association or (except as explicitly provided in this Agreement) a trust.  This Agreement shall not be deemed or construed to authorize any Party to act as an agent, servant or employee for any other Party for any purpose whatsoever except as explicitly set forth in this Agreement.  In their relations with each other under this Agreement, the Parties shall not be considered fiduciaries except as expressly provided in this Agreement.

14.2   Royalty

(A)   The Parties other than Adira and GGR must pay to each of Adira and GGR (or their respective designees) an overriding royalty payment of 1.5% calculated as follows:

(1)   On oil (including any distillate and condensate), the applicable royalty percentage is calculated before payment on any and all royalties payable to the Government of oil produced and saved from the Contract, delivery of such oil to be made free of all costs and expenses in developing and operating and all costs of production, and before all separation, dehydration, cleaning, treating, storage, and transportation costs.

(2)   On gas, including casinghead gas or other gaseous substances and liquid constituents of said gas, produced from and sold or used, or for the extraction of gasoline or other products therefrom, the applicable royalty percentage is calculated before payment of any and all royalties payable to the Government, based on the market value at the well or wells of gas so produced and sold or utilized. The royalty will not bear any share of separation, dehydration, sweetening, processing, treatment, storage, transportation, and marketing costs.

(3)   Notwithstanding anything in this Agreement to the contrary, if the price of any substance upon which the “royalty” is payable is regulated by any Government agency, the market value of such substance for the purpose of computing the royalty shall not exceed the price which a party may lawfully receive.

(4)   Fuel oil and gas for operations (including operations on lands pooled with Contract lands), and for treating and handling the production and products therefrom (and the proportionate part of fuel oil and gas consumed in a central plant, should the assets be operated jointly with other premises through the use of such plant) shall not be deducted before the royalty is computed.

(B)   Regarding any royalty payable to the Government, Operator will pay from the Joint Account all ad valorem, production, severance, gathering, and windfall profits taxes, gift tax, and any other taxes chargeable against the royalty or measured by or related to oil, gas or other hydrocarbon substances produced from the Contract and attributable to the royalty.

(C)   In the event of expropriation of the Contract, Adira shall be entitled to an equitable allocation of any award or compensation collected by the Parties from the Government pursuant to administrative or legal proceedings, but only on that portion of said award or compensation in excess of each Party’s investment (net of any carried interest obligations) as of the date of expropriation and then Adira will be allocated and receive an amount equal to the royalty. The Parties will endeavor to agree on a calculation methodology to apply this Article 4.1(D) for allocation of Adira’s royalty rights following the expropriation award or compensation consistent with the above principle.

14.3   Tax

(A)Each Party shall be responsible for reporting and discharging its own tax measured by the profit or income of the Party and the satisfaction of such Party’s share of all contract obligations under the Contract and under this Agreement.  Each Party shall protect, defend and indemnify each other Party from any and all loss, cost or liability arising from the indemnifying Party’s failure to report and discharge such taxes or satisfy such obligations.  The Parties intend that all income and all tax benefits (including deductions, depreciation, credits and capitalization) with respect to the expenditures made by the Parties hereunder will be allocated by the Government tax authorities to the Parties based on the share of each tax item actually received or borne by each Party.  If such allocation is not accomplished due to the application of the Laws / Regulations or other Government action, the Parties shall attempt to adopt mutually agreeable arrangements that will allow the Parties to achieve the financial results intended.  Operator shall provide each Party, in a timely manner and at such Party’s sole expense, with such information with respect to Joint Operations as such Party may reasonably request for preparation of its tax returns or responding to any audit or other tax proceeding.

(B)   It may be advantageous (for some or all of the Parties) to restructure the ownership of the Contract to maximize tax planning and liability protection in the future.  The Parties will meet and consider tax planning opportunities (including offshore holding company arrangements) from time to time; provided that no Party will be required to incur material, additional or accelerated taxes without its express approval of any plan or reorganization.  The Operator will cause a “Joint

Operating” (“Iska Meshutefet” [phonetic spelling]) or joint venture under Israeli law to provide for the mutual benefit of all Parties with respect to the collection, payment, and reimbursement of VAT under Israel law.

14.4   United States Tax Election

(A)   If, for United States federal income tax purposes, this Agreement and the operations under this Agreement are regarded as a partnership and if the Parties have not agreed to form a tax partnership, each U.S. Party elects to be excluded from the application of all of the provisions of Subchapter “K”, Chapter 1, Subtitle “A” of the United States Internal Revenue Code of 1986, as amended (the “Code”), to the extent permitted and authorized by Section 761(a) of the Code and the regulations promulgated under the Code.  Operator, if it is a U.S. Party, is authorized and directed to execute and file for each U.S. Party such evidence of this election as may be required by the Internal Revenue Service, including all of the returns, statements, and data required by United States Treasury Regulations Sections 1.761-2 and 1.6031(a)-1(b)(5) and shall provide a copy thereof to each U.S. Party.  However, if Operator is not a U.S. Party, the Party who holds the greatest Participating Interest among the U.S. Parties shall fulfill the obligations of Operator under this Article 14.3.  Should there be any requirement that any U.S. Party give further evidence of this election, each U.S. Party shall execute such documents and furnish such other evidence as may be required by the Internal Revenue Service or as may be necessary to evidence this election.

(B)   No Party shall give any notice or take any other action inconsistent with the foregoing election.  If any income tax laws of any state or other political subdivision of the United States or any future income tax laws of the United States or any such political subdivision contain provisions similar to those in Subchapter “K”, Chapter 1, Subtitle “A” of the Code, under which an election similar to that provided by Section 761(a) of the Code is permitted, each U.S. Party shall make such election as may be permitted or required by such laws.  In making the foregoing election or elections, each U.S. Party states that the income derived by it from operations under this Agreement can be adequately determined without the computation of partnership taxable income.

(C)   Unless approved by every Non-U.S. Party, no activity shall be conducted under this Agreement that would cause any Non-U.S. Party to be deemed to be engaged in a trade or business within the United States under United States income tax laws and regulations.

(D)   A Non-U.S. Party shall not be required to do any act or execute any instrument which might subject it to the taxation jurisdiction of the United States.

(E)   For the purposes of this Article 14.3, “U.S. Party” shall mean any Party that is subject to the income tax law of the United States in respect with operations under this Agreement.  “Non-U.S. Party” shall mean any Party that is not subject to such income tax law.

ARTICLE 15.

VENTURE INFORMATION - CONFIDENTIALITY - INTELLECTUAL PROPERTY

15.1   Venture Information

(A)   Except as otherwise provided in this Article 15 or in Articles 4.4 and 8.4(A), each Party will be entitled to receive all Venture Information related to operations in which such party is a participant.  “Venture Information”means any information and results developed or acquired as a result of Joint Operations and shall be Joint Property, unless provided otherwise in accordance with this Agreement and the Contract.  Each Party shall have the right to use all Venture Information it receives without accounting to any other Party, subject to any applicable patents and any limitations set forth in this Agreement and the Contract. For purposes of this Article 15, such right to use shall include, the rights to copy, prepare derivative works, disclose, license, distribute, and sell.

(B)   Each Party may, subject to any applicable restrictions and limitations set forth in the Contract, extend the right to use Venture Information to each of its Affiliates which are obligated to terms not less restrictive that this Article 15. Except as otherwise provided in the Contract, each Party may extend the right to use Venture Information to members of joint ventures or production sharing arrangements in which such Party or its Affiliates have an ownership or equity interest, provided that each such member agrees in writing to keep the Venture Information in confidence at least to the same extent as required in Article 15.2 and to use the Venture Information only for the benefit of that joint venture or production sharing arrangement.

(C)   The acquisition or development of Venture Information under terms other than as specified in this Article 15 shall require the approval of the Operating Committee.  The request for approval submitted by a Party shall be accompanied by a description of, and summary of the use and disclosure restrictions which would be applicable to, the Venture Information, and any such Party will be obligated to use all reasonable efforts to arrange for rights to use which are not less restrictive than specified in this Article 15.

(D)   All Venture Information received by a Party under this Agreement is received on an “as is” basis without warranties, express or implied, of any kind. Any use of such Venture Information by a Party shall be at such Party’s sole risk.

15.2   Confidentiality

(A)   Subject to the provisions of the Contract and this Article 15, the Parties agree that all information in relation with Joint Operations or Exclusive Operations shall be considered confidential and shall be kept confidential and not be disclosed during the term of the Contract and for a period of five (5) years thereafter to any person or entity not a Party to this Agreement, except:

(1)   to an Affiliate pursuant to Article 15.1(B);

(2)   to a governmental agency or other entity when required by the Contract;

(3)   to the extent such information is required to be furnished in compliance with the applicable law or regulations, or pursuant to any legal proceedings or because of any order of any court binding upon a Party;

(4)   to prospective or actual attorneys engaged by any Party where disclosure of such information is essential to such attorney’s work for such Party;

(5)   to prospective or actual contractors and consultants engaged by any Party where disclosure of such information is essential to such contractor’s or consultant’s work for such Party;

(6)   to a bona fide prospective transferee of a Party’s Participating Interest to the extent appropriate in order to allow the assessment of such Participating Interest (including an entity with whom a Party and/or its Affiliates are conducting bona fide negotiations directed toward a merger, consolidation or the sale of a majority of its or an Affiliate's shares);

(7)   to a bank or other financial institution to the extent appropriate to a Party arranging for funding;

(8)   to the extent such information must be disclosed pursuant to any rules or requirements of any government or stock exchange having jurisdiction over such Party, or its Affiliates; provided that if any Party desires to disclose information in an annual or periodic report to its or its Affiliates' shareholders and to the public and such disclosure is not required pursuant to any rules or requirements of any government or stock exchange, then such Party shall comply with Article 19.3;

(9)   to its respective employees for the purposes of Joint Operations or Exclusive Operations as the case may be, subject to each Party taking customary precautions to ensure such information is kept confidential; and

(10)   any information which, through no fault of a Party, becomes a part of the public domain.

(B)   Disclosure as pursuant to Articles 15.2(A)(5), (6), and (7) shall not be made unless prior to such disclosure the disclosing Party has obtained a written undertaking from the recipient party to keep the information strictly confidential for at least as long as the period set out in Article 15.2(A).  and to use the information for the sole purpose described in Articles 15.2(A)(5), (6), and (7), whichever is applicable, with respect to the disclosing Party.

15.3   Intellectual Property

(A)   Subject to Articles 15.3(C) and 15.5 and unless provided otherwise in the Contract, all intellectual property rights in the Venture Information shall be Joint Property.  Each Party and its Affiliates have the right to use all such intellectual property rights in their own operations (including joint operations or a production sharing arrangement in which the Party or its Affiliates has an ownership or equity interest) without the approval of any other Party.  Decisions regarding obtaining, maintaining and licensing such intellectual property rights shall be made by the Operating Committee, and the costs thereof shall be for the Joint Account.  Upon unanimous consent of the Operating Committee as to ownership, licensing rights, and income distribution, the ownership of intellectual property rights in the Venture Information may be assigned to the Operator or to a Party.

(B)   Nothing in this Agreement shall be deemed to require a Party to (i) divulge proprietary technology to any of the other Parties; or (ii) grant a license or other rights under any intellectual property rights owned or controlled by such Party or its Affiliates to any of the other Parties.

(C)   If a Party or an Affiliate of a Party has proprietary technology applicable to activities carried out under this Agreement which the Party or its Affiliate desires to make available on terms and conditions other than as specified in Article 15.3(A), the Party or Affiliate may, with the prior approval of the Operator, make the proprietary technology available on terms to be agreed.  If the proprietary technology is so made available, then any inventions, discoveries, or improvements which relate to such proprietary technology and which result from Joint Account expenditures shall belong to such Party or Affiliate.  In such case, each other Party shall have a perpetual, royalty-free, irrevocable license to practice such inventions, discoveries, or improvements, but only in connection with the Joint Operations.

(D)   Subject to Article 4.6(B), all costs and expenses of defending, settling or otherwise handling any claim which is based on the actual or alleged infringement of any intellectual property right shall be for the account of the operation from which the claim arose, whether Joint Operations or Exclusive Operations.

15.4   Continuing Obligations

Any Party ceasing to own a Participating Interest during the term of this Agreement shall nonetheless remain bound by the obligations of confidentiality in Article 15.2, and any disputes in relation thereto shall be resolved in accordance with Article 18.2.

15.5   Trades

Operator may, with approval of the Operating Committee, make well trades and data trades for the benefit of the Parties, with any data so obtained to be furnished to all Parties who participated in the cost of the data that was traded.  Operator shall cause any third party to such trade to enter into an undertaking to keep the traded data confidential.

ARTICLE 16.

FORCE MAJEURE

16.1   Obligations

If as a result of Force Majeure any Party is rendered unable, wholly or in part, to carry out its obligations under this Agreement, other than the obligation to pay any amounts due or to furnish Security, then the obligations of the Party giving such notice, so far as and to the extent that the obligations are affected by such Force Majeure, shall be suspended during the continuance of any inability so caused and for such reasonable period thereafter as may be necessary for the Party to put itself in the same position that it occupied prior to the Force Majeure, but for no longer period.  The Party claiming Force Majeure shall notify the other Parties of the Force Majeure within a reasonable time after the occurrence of the facts relied on and shall keep all Parties informed of all significant developments.  Such notice shall give reasonably full particulars of the Force Majeure and also estimate the period of time which the Party will probably require to remedy the Force Majeure.  The affected Party shall use all reasonable diligence to remove or overcome the Force Majeure situation as quickly as possible in an economic manner but shall not be obligated to settle any labor dispute except on terms acceptable to it, and all such disputes shall be handled within the sole discretion of the affected Party.

16.2   Definition of Force Majeure

For the purposes of this Agreement, “Force Majeure” means any cause beyond the reasonable control of a Party, and which such Party by the exercise of all reasonable endeavors is unable to prevent, avoid or remove whether similar to the causes specified herein or not, including (insofar as beyond such control but without prejudice to the generality of the foregoing expression) Acts of God, strikes, lockouts, acts of the public enemy, Laws / Regulations, wars or warlike action (whether actual or impending) restraints of government (civil or military), acts of terrorism or sabotage, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, sabotage, tropical storms and hurricanes, civil disturbances, tidal waves, explosions, confiscation or seizure by any government or other public authority, and any other causes, whether of the kind herein enumerated or otherwise, that are not reasonably within the control of the party claiming a suspension and that could not have been overcome by the exercise of ordinary diligence; provided that a lack of funds shall not constitute “Force Majeure.”

ARTICLE 17.

NOTICES

Except as otherwise specifically provided, all notices authorized or required between the Parties by any of the provisions of this Agreement shall be in writing (in English) and delivered in person or by courier service or by any electronic means of transmitting written communications which provides written confirmation of complete transmission, and addressed to such Parties, including email only if written confirmation of complete transmission of the email message to the intended recipient can be verified.  Oral communication does not constitute notice for purposes of this Agreement, and e-mail addresses (other than as stated herein) and telephone numbers for the Parties are listed below as a matter of convenience only.  A notice given under any provision of this Agreement shall be deemed delivered only when received by the Party to whom such notice is directed, and the time for such Party to deliver any notice in response to such originating notice shall run from the date the originating notice is received.  “Received” for purposes of this Article 17 shall mean actual delivery of the notice to the address of the

Party specified hereunder or to be thereafter notified in accordance with this Article 17.  Each Party shall have the right to change its address at any time and/or designate that copies of all such notices be directed to another person at another address, by giving written notice thereof to all other Parties.

Name of Party	Copies Provided To (which copies shall not constitute notice)
For Adira: ØAdira Energy Israel, Ltd. or Adira Energy Israel Services Ltd (as applicable) Ilan Diamond Amot Investments Tower, 2 Weitzman St, P.O. Box 33123. Tel-Aviv 64239, Israel Email:  ilan@adiraenergy.com ØAdira Energy Ltd. Colin Kinley 7400 West 132 Street Suite 160 Overland Park, KS  66213 Email:  CKinley@adiraenergy.com	ØHusch Blackwell LLP Robert Attai 1700 Lincoln Street, Suite 4700 Denver, Colorado  80202 USA Email:  robert.attai@huschblackwell.com Telephone:  +1 303.749.7213 Facsimile:  +1 303.749.7272 ØAlan Friedman 120 Adelaide St. W., Richmond Adelaide Centre, M5H, 1T1 Canada Telephone: +1 416.250-6500 Ext. 1955 Facsimile: +1 416.361.6455
For Geoglobal Resources Inc.: ØGeoGlobal Resources Inc. Suite 200, 625 – 4th Avenue S.W. ØCalgary, AB T2P 0K2 Telephone: (403) 777-9250 Fax: (403) 777-9199 Email: paul.miller@geoglobal.com	ØShea Nerland Calnan LLP 2800, 715 – 5th Avenue SW Calgary, Alberta T2P 2X6 Telephone: 403-299-9629 Facsimile: 403-299-9601 Email: dmylrea@snclaw.com Ø[Company/ Name] [TBD] [Address]: [Telephone]: [Fax]: [Email]:
For Pinetree: Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]:	Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]: Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]:
For Brownstone: Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]:	Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]: Ø[Company/ Name] [Address]: [Telephone]: [Fax]: [Email]:

ARTICLE 18.

APPLICABLE LAW - DISPUTE RESOLUTION

18.1   Applicable Law

This Agreement shall be governed by, construed, interpreted and applied in accordance with Israeli law, excluding any choice of law rules which would refer the matter to the laws of another jurisdiction.

18.2   Dispute Resolution

(A)   Any dispute, controversy or claim arising out of or in relation to or in connection with this Agreement or the operations carried out under this Agreement, including without limitation any dispute as to the construction validity, interpretation, enforceability or breach of this Agreement, shall be exclusively and finally settled by arbitration, and any Party may submit such a dispute, controversy or claim to arbitration.  The dispute resolution will be in accordance with the Commercial Rules of the London Court of International Arbitration (LCIA), as amended from time to time.

(B)   The arbitration will be conducted by one arbitrator mutually agreed upon by the Parties. If the Parties are not able to agree, at any time either Party will select one arbitrator and demand that the other Party select one arbitrator.  Those two selected arbitrators will then select a third arbitrator, who will conduct the arbitration by him- or herself.  The third arbitrator will only have the power to select one of the positions, without modification, proffered by the disputing Parties.  The arbitrator will have at least Fifteen (15) years of experience in the international (non U.S.) oil and natural gas industry, and have had no material social or business dealings with any of the Parties during the Ten (10) years prior to the dispute.  If the two arbitrators selected by the Parties are not able to select

the third arbitrator within Ten (10) Days of their appointment, then the LCIA will select the third arbitrator.

(C)   The Parties will pay their chosen arbitrator and split equally the cost of the third arbitrator; however the arbitrator may, in its discretion, award costs and/or attorneys’ fees to the Party deemed to be the prevailing party.

(D)   The place of arbitration will be Toronto, Canada, and the proceedings will be in the English language.  The laws of Israel will be applied in any arbitration proceedings, without regard to principles of conflict of laws.

(E)   A dispute will be deemed to have arisen when either Party notifies the other Party in writing to that effect.

(F)   The resulting arbitral award will be final, non-appealable and binding, and judgment upon such award may be entered in any court having jurisdiction.  Any monetary award issued by the arbitrator will be payable in United States Dollars.  The award shall include interest from the date of any breach or violation of this Agreement, as determined by the arbitral award, and from the date of the award until paid in full, at the Agreed Interest Rate; and

(G)   It is expressly agreed that the arbitrator will have no authority to award special, indirect, consequential, exemplary or punitive damages.

(H)   The Parties acknowledge that remedies at law may be inadequate to protect against breach of this Agreement.  The third arbitrator may therefore award both monetary and equitable relief, including injunctive relief and specific performance.

(I)   A Party may apply to any competent judicial authority for interim or conservatory relief.  The application for such measure or for the enforcement of such measures ordered by the arbitrator will not be deemed an infringement or waiver of the agreement to arbitrate and will not affect the powers of the arbitrator.

(J)   The Parties acknowledge that remedies at law may be inadequate to protect against breach of this Agreement.  The third arbitrator may therefore award both monetary and equitable relief, including injunctive relief and specific performance.

(K)   A Party may apply to any competent judicial authority for interim or conservatory relief.  The application for such measure or for the enforcement of such measures ordered by the arbitrator will not be deemed an infringement or waiver of the agreement to arbitrate and will not affect the powers of the arbitrator.

ARTICLE 19.

GENERAL PROVISIONS

19.1   Conduct of the Parties

(A)   Each Party warrants that it and its Affiliates have not made, offered, or authorized and will not make, offer, or authorize with respect to the matters which are the subject of this Agreement, any payment, gift, promise or other advantage, whether directly or through any other person or entity, to or for the use or benefit of any public official (i.e., any person holding a legislative, administrative or judicial office, including any person employed by or acting on behalf of a public agency, a public enterprise or a public international organization) or any political party or political party official or candidate for office, where such payment, gift, promise or advantage would violate (i) the applicable laws of Israel; (ii) the laws of the country of incorporation or formation of such Party or such Party’s ultimate parent company and of the principal place of business of such ultimate parent company; or (iii) the principles described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions, signed in Paris on December 17, 1997, which entered into force on February 15, 1999, and the Convention’s Commentaries.  Each Party shall defend, indemnify and hold the other Parties harmless from and against any and all claims, damages, losses, penalties, costs and expenses arising from or related to, any breach by such first Party of such warranty.  Such indemnity obligation shall survive termination or expiration of this Agreement.  Each Party shall in good time (i) respond in reasonable detail to any notice from any other Party reasonably connected with the above-stated warranty; and (ii) furnish applicable documentary support for such response upon request from such other Party.

(B)   Each Party agrees to (i) maintain adequate internal controls; (ii) properly record and report all transactions; and (iii) comply with the laws applicable to it.  Each Party must rely on the other Parties’ system of internal controls, and on the adequacy of full disclosure of the facts, and of financial and other data regarding the Joint Operations undertaken under this Agreement.  No Party is in any way authorized to take any action on behalf of another Party that would result in an inadequate or inaccurate recording and reporting of assets, liabilities or any other transaction, or which would put such Party in violation of its obligations under the laws applicable to the operations under this Agreement.

19.2   Conflicts of Interest

Except as otherwise provided in this Agreement or conduct by the Operator that is in accordance with the preference laws or published policies of the Government:

(A)   Operator undertakes that it shall avoid any conflict of interest between its own interests (including the interests of Affiliates) and the interests of the other Parties in dealing with suppliers, customers and all other organizations or individuals doing or seeking to do business with the Parties in connection with activities contemplated under this Agreement.

(B)   Unless otherwise agreed, the Parties and their Affiliates are free to engage or invest (directly or indirectly) in an unlimited number of activities or businesses, any one or more of which may be related to or in competition with the business activities contemplated under this Agreement, without having or incurring any obligation to offer any interest in such business activities to any Party.

19.3   Public Announcements

(A)   Operator shall be responsible for the preparation and release of all public announcements and statements regarding this Agreement or the Joint Operations; provided that no public announcement or statement shall be issued or made unless, prior to its release, all the Parties have been furnished with a copy of such statement or announcement and the approval of at least two (2) Parties holding fifty percent (50%) or more of the Participating Interests not held by Operator or its Affiliates has been obtained.  Where a public announcement or statement becomes necessary or desirable because of danger to or loss of life, damage to property or pollution as a result of activities arising under this Agreement, Operator is authorized to issue and make such announcement or statement without prior approval of the Parties, but shall promptly furnish all the Parties with a copy of such announcement or statement.

(B)   If a Party wishes to issue or make any public announcement or statement regarding this Agreement or the Joint Operations, it shall not do so unless, prior to the release of the public announcement or statement, such Party furnishes all the Parties with a copy of such announcement or statement, and obtains the approval of at least two (2) Parties holding fifty percent (50%) or more of the Participating Interests not held by such announcing Party or its Affiliates; provided that, notwithstanding any failure to obtain such approval, no Party shall be prohibited from issuing or making any such public announcement or statement if it is necessary to do so in order to comply with the applicable laws, rules or regulations of any government, legal proceedings or stock exchange having jurisdiction over such Party or its Affiliates as set forth in Article 15.2.

19.4   Successors and Assigns

Subject to the limitations on Transfer contained in Article 12, this Agreement shall inure to the benefit of and be binding upon the successors and assigns of the Parties.

19.5   Waiver

No waiver by any Party of any one or more defaults by another Party in the performance of any provision of this Agreement shall operate or be construed as a waiver of any future default or defaults by the same Party, whether of a like or of a different character.  Except as expressly provided in this Agreement no Party shall be deemed to have waived, released or modified any of its rights under this Agreement unless such Party has expressly stated, in writing, that it does waive, release or modify such right.

19.6   No Third Party Beneficiaries

Except as provided under Article 4.6(B), the interpretation of this Agreement shall exclude any rights under legislative provisions conferring rights under a contract to persons not a party to that contract.

19.7   Joint Preparation

Each provision of this Agreement shall be construed as though all Parties participated equally in the drafting of the same.  Consequently, the Parties acknowledge and agree that any rule of construction that a document is to be construed against the drafting party shall not be applicable to this Agreement.

19.8   Severance of Invalid Provisions

If and for so long as any provision of this Agreement shall be deemed to be judged invalid for any reason whatsoever, such invalidity shall not affect the validity or operation of any other provision of this Agreement except only so far as shall be necessary to give effect to the construction of such invalidity, and any such invalid provision shall be deemed severed from this Agreement without affecting the validity of the balance of this Agreement.

19.9   Modifications

Except as is provided in Articles 11.2(B) and 20.8, there shall be no modification of this Agreement or the Contract except by written consent of all Parties.

19.10   Interpretation

(A)   Headings.  The topical headings used in this Agreement are for convenience only and shall not be construed as having any substantive significance or as indicating that all of the provisions of this Agreement relating to any topic are to be found in any particular Article.

(B)   Singular and Plural.  Reference to the singular includes a reference to the plural and vice versa.

(C)   Gender.  Reference to any gender includes a reference to all other genders.

(D)   Article.  Unless otherwise provided, reference to any Article or an Exhibit means an Article or Exhibit of this Agreement.

(E)   Include.  “include” and “including” shall mean include or including without limiting the generality of the description preceding such term and are used in an illustrative sense and not a limiting sense.

19.11   Counterpart Execution

This Agreement may be executed in any number of counterparts and each such counterpart shall be deemed an original Agreement for all purposes; provided that no Party shall be bound to this Agreement unless and until all Parties have executed a counterpart.  For purposes of assembling

all counterparts into one document, Operator is authorized to detach the signature page from one or more counterparts and, after signature thereof by the respective Party, attach each signed signature page to a counterpart.

19.12   Entirety

With respect to the subject matter contained herein, this Agreement (i) is the entire agreement of the Parties; and (ii) supersedes all prior understandings and negotiations of the Parties.

***the remainder of this page intentionally left blank**

IN WITNESS of their agreement each Party has caused its duly authorized representative to sign this instrument on the date indicated below such representative’s signature.

GeoGlobal Resources (India) Inc.

By:       /s/ GeoGlobal Resources (India) Inc.

Name

Title:

Date:

Adira Geo Global Ltd.

By:       /s/ Adira Geo Global Ltd.

(Print or type name)

Title:

Date:

Adira Oil Technologies Ltd.

By:       /s/ Adira Oil Technologies Ltd.

(Print or type name)

Title:

Date:

Brownstone Venture Inc.

By:       /s/ Brownstone Venture Inc.

(Print or type name)

Title:

Date:

Pinetree Capital Ltd.

By:       /s/ Pinetree Capital Ltd.

(Print or type name)

Title:

Date:

EXHIBIT “A”

ACCOUNTING PROCEDURE – SAMUEL

ARTICLE 1.

GENERAL PROVISIONS

1.1   Purpose.

(A)   The purpose of this Accounting Procedure is to establish methods for determining charges and credits applicable to operations under the Agreement.

(B)   The Parties agree, however, that if the methods prove unfair or inequitable to Operator or Non-Operators, the Parties shall meet and in good faith endeavor to agree on changes in methods deemed necessary to correct any unfairness or inequity.

1.2   Conflict with Agreement.

In the event of a conflict between the provisions of this Accounting Procedure and the provisions of the Agreement to which this Accounting Procedure is attached, the provisions of the Agreement shall prevail.

1.3   Definitions.

The definitions contained in the Agreement to which this Accounting Procedure is attached shall apply to this Accounting Procedure and have the same meanings when used herein.  Certain terms used herein are defined as follows:

“Accrual basis” means that basis of accounting under which costs and benefits are regarded as applicable to the period in which the liability for the cost is incurred or the right to the benefit arises, regardless of when invoiced, paid, or received.

“Cash basis” means that basis of accounting under which only costs actually paid and revenue actually received are included for any period.

“Country of Operations” means Israel.

“Material” means machinery, equipment and supplies acquired and held for use in Joint Operations.

“Section” means a section of this Accounting Procedure.

1.4   Joint Account Records and Currency Exchange.

(A)   Operator shall at all times maintain and keep true and correct records of the production and disposition of all liquid and gaseous Hydrocarbons, and of all costs and expenditures under the Agreement, as well as other data necessary or proper for the settlement of accounts between the Parties hereto in connection with their rights and obligations under the Agreement and to enable Parties to comply with their respective applicable income tax and other laws.

(B)   Operator shall maintain accounting records pertaining to Joint Operations in accordance with generally accepted accounting practices used in the international petroleum industry and any applicable statutory obligations of the Country of Operations as well as the provisions of the Contract and the Agreement.

(C)   The Joint Account shall be maintained by Operator in the English language and in United States of America (“U.S.”) and Israeli currency and in such other language and currency as may be required by the laws of the Country of Operations or the Contract.  Conversions of currency shall be recorded at the rate actually experienced in that conversion.  Currency translations are used to express the amount of expenditures and receipts for which a currency conversion has not actually occurred. Currency translations for expenditures and receipts shall be recorded in accordance with Operator’s normal practice.  A statement describing the practice will be provided to the Non-Operators upon request.

(D)   Any currency exchange gains or losses shall be credited or charged to the Joint Account, except as otherwise specified in this Accounting Procedure.  Any such exchange gains or losses shall be separately identified as such.

(E)   This Accounting Procedure shall apply, mutatis mutandis, to Exclusive Operations in the same manner that it applies to Joint Operations; provided, however, that the charges and credits applicable to Consenting Parties shall be separately maintained.  For the purpose of determining and calculating the remuneration of the Consenting Parties, the costs and expenditures shall be expressed in U.S. currency and Israeli currency (irrespective of the currency in which the expenditure was incurred).

(F)   The Accrual basis for accounting shall be used in preparing accounts concerning the Joint Operations.  If a Cash basis for accounting is used, Operator shall show accruals as memorandum items.

1.5   Statements and Billings.

(A)   Unless otherwise agreed by the Parties, Operator shall submit monthly to each Party, on or before the 21st Day of each month, statements of the costs and expenditures incurred during the prior month, indicating by appropriate classification the nature thereof, the corresponding budget category, and the portion of such costs charged to each of the Parties.

These statements, as a minimum, shall contain the following information:

advances of funds setting forth the currencies received from each Party,

the share of each Party in total expenditures,

the accrued expenditures,

the current account balance of each Party,

summary of costs, credits, and expenditures on a current month, year-to-date, and inception-to-date basis or other periodic basis, as agreed by Parties (such expenditures shall be grouped by the categories and line items designated in the approved Work Program and Budget submitted by Operator in accordance with Article 6.4 of the Agreement so as to facilitate comparison of actual expenditures against that Work Program and Budget), and

details of unusual charges and credits in excess of  U.S. $50,000.

(B)   Operator shall provide the Parties with annual financial statements (prepared in accordance with International Financial Reporting Standards or "IFRS") within sixty (60) Days after the end of each Calendar Year, audited by a recognized independent public accounting firm in Israel; and with unaudited, quarterly financial statements (prepared in accordance with IFRS, but without footnote disclosure) within thirty (30) days after the end of each Calendar Quarter reviewed by a recognized independent public accounting firm in Israel.  The abovementioned accounting firm shall provide the Non-Operators’ auditors all documents, including comfort letter, questionnaires, etc. in accordance with accepted auditing standards.  The cost of providing the financial statements shall be charged to the Joint Account. Any costs incurred by the abovementioned accounting firm to prepare a  reconciliation to Generally Accepted Accounting Standards shall be charged to the Non-Operators who request such reconciliation.

(C)   Unless otherwise agreed by the Parties, Operator shall submit to each Party, on or before the 30th day after the end of each Calendar Quarter, statements of changes in Advances, expenditures and credits, made, incurred or due to each Party from the Joint Operations, including

(a)   Advances received from each Party during such Calendar Quarter and cumulatively from the beginning of the Calendar Year;

(b)   The share of each Party in total expenditures incurred during such Calendar Quarter and cumulatively from the beginning of the Calendar Year;

(c)   The current account balance of each Party as at the end of such Calendar Quarter; and

(d)   A summary of costs, credits, investments and expenditures incurred during such Calendar Quarter and cumulatively from the beginning of the Calendar Year and from inception, or such other periodic basis as agreed by Parties (such expenditures shall be sorted into items that in accordance to IFRS are to be capitalized and items that are included in the profits and losses.

(D)   Operator shall, upon request, furnish a description of the accounting classifications used by it.

(E)   Amounts included in the statements and billings shall be expressed in U.S. Dollars and Shekles and reconciled to the currencies advanced.

(F)   Each Party shall be responsible for preparing its own accounting and tax reports to meet the requirements of the Country of Operations and of all other countries to which it may be subject.  Operator, to the extent that the information is reasonably available from the Joint Account records, shall endeavor to provide Non-Operators within thirty (30) Days from the end of each Calendar Quarter (and within sixty (60) Days from the end of each Calendar Year) with the necessary information to facilitate the discharge of such responsibility.

1.6   Payments and Advances.

(A)   Upon approval of any Work Program and Budget, if Operator so requests, each Non-Operator shall advance its share of estimated cash requirements for the succeeding 90 Days' operations, or on such accelerated schedule or for such longer period as the Operator dictates based on Operator's obligation and need to diligently pursue operations and make timely payment to any third party servicing the Operation (including Operator’s costs).

(1)   For informational purposes the cash call shall contain an estimate of the funds required for the succeeding 90 Days’ operations, or on such accelerated schedule or for such longer period as the Operator dictates based on Operator’s obligation and need to diligently pursue operations and make timely payment to any third party servicing the Operation (including Operator’s costs).

(2)   The intent of the Parties is that the Operator will at all times have on hand cash in an amount equal to Operator’s estimated cash flow needs for 90 Days’ worth of general and administrative, based on a good faith estimate that shall be updated monthly and reported to the Parties pursuant to Section 1.5.1; and for project work in the Contract Area (including any Joint Operation or Exclusive Operation), the intent of the Parties is that the Operator will have no obligation to commence work or incur any material expenditure unless and until the expenses of completing such work (including third party costs and expenses according to service contracts required to be entered into in connection with such work) have been funded in full by each Party participating in such operation.

(B)   Each such cash call, detailed by the categories designated in the approved Work Program and Budget submitted by Operator in accordance with Article 6.4 of the Agreement, shall be made in writing and delivered to all Non-Operators not less than 15 Days before the payment due date.  The due date for payment of such advances shall be set by Operator but shall be no sooner than the first Business Day of the month for which the advances are required.  All advances shall be made without bank charges.  Any charges related to receipt of advances from a Non-Operator shall be borne by that Non-Operator.

(C)   Each Non-Operator shall wire transfer its share of the full amount of each such cash call to Operator on or before the due date, in the currencies requested or any other currencies acceptable to Operator and at a bank designated by Operator.  If currency provided by a Non-Operator is other than the requested currency, then the entire cost of converting to the requested currency shall be charged to that Non-Operator.

(D)   Notwithstanding the provisions of Section 1.6.2, should Operator be required to pay any sums of money for the Joint Operations which were unforeseen at the time of providing the Non-Operators with said estimates of its requirements, Operator may make a written request of the Non-Operators for special advances covering the Non-Operators’ share of such payments.  Each such Non-Operator shall make its proportional special advances within 10 Days after receipt of such notice.

(E)   If a Non-Operator’s advances exceed its share of cash expenditures, the next succeeding cash advance requirements, after such determination, shall be reduced accordingly.  However, if the amount of such excess advance is greater than the cash requirements for such Non-Operator, the Non-Operator may request a refund of the difference, which refund shall be made by Operator within 10 Days after receipt of the Non-Operator’s request.

(F)   If, under the provisions of the Agreement, Operator is required to segregate funds received from the Parties, any interest received on such funds shall be applied against the next succeeding cash call or, if directed by the Operating Committee, distributed quarterly.  The interest thus received shall be allocated to the Parties on an equitable basis taking into consideration date of funding by each Party to the accounts in proportion to the total funding into the account.  A monthly statement summarizing receipts, disbursements, transfers to each joint bank account and beginning and ending balances thereof shall be provided by Operator to the Parties.

(G)   Any interest received by Operator from interest-bearing accounts containing commingled funds received from the Parties shall be credited to the Parties in accordance with the allocation procedure as set forth above.

(H)   If Operator does not request Non-Operators to advance their share of estimated cash requirements, each Non-Operator shall pay its share of cash expenditures within 10 Days following receipt of Operator’s billing.

(I)   Payments of advances or billings shall be made on or before the due date. In accordance with Article 8 of the Agreement, if these payments are not received by the due date the unpaid balance shall bear and accrue interest from the due date until the payment is received by Operator at the Agreed Interest Rate.  For the purpose of determining the unpaid balance and interest owed, Operator shall translate to U.S. currency all amounts owed in other currencies using the currency exchange rate, determined in accordance with Section 1.4.3, at the close of the last Business Day prior to the due date for the unpaid balance.

(J)   Subject to governmental regulation, Operator shall have the right, at any time and from time to time, to convert the funds advanced or any part thereof to other currencies to the extent that such currencies are then required for operations.  The cost of any such conversion shall be charged to the Joint Account.

(K)   Operator shall endeavor to maintain funds held for the Joint Account in bank accounts at a level consistent with that required for the prudent conduct of Joint Operations.

(L)   If under the Agreement, Operator is required to segregate funds received from or for the Joint Account, the provisions under Section 1.6 for payments and advances by Non-Operators shall apply also to Operator.  Operator may at all times maintain a balance of $50,000 in U.S. currency equivalent value in a bank account in Israel to secure payment of credit card obligations incurred in the ordinary course of operations.

1.7   Adjustments.

Payments of any advances or billings shall not prejudice the right of any Non-Operator to protest or question the correctness thereof; provided, however, all bills and statements rendered to Non-Operators by Operator during any Calendar Year shall conclusively be presumed to be true and correct after 90 Days absent manifest error and unless within the said 90 Day period a Non-Operator takes written exception thereto and makes claim on Operator for adjustment, subject to the rights of each Party under Section 1.8 below.  Failure on the part of a Non-Operator to make claim on Operator for adjustment within such period shall establish the correctness thereof and preclude the filing of exceptions thereto or making claims for adjustment thereon.  The provisions of this paragraph shall not prevent adjustments resulting from a physical inventory of the Material as provided for in Section 6.  Operator shall be allowed to make adjustments to the Joint Account after such 90 Day period if these adjustments result from audit exceptions outside of this Accounting Procedure, third party claims, or Government or Government Oil & Gas Company requirements.  Any such adjustments shall be subject to audit within the time period specified in Section 1.8.1.

1.8   Audits.

(A)   A Non-Operator, upon at least 60 Days advance notice in writing to Operator and all other Non-Operators, shall have the right to audit the Joint Accounts and records of Operator relating to the accounting hereunder for any Calendar Year within the 24 month period following the end of such Calendar Year except as otherwise provided in Section 3.1. Non-Operators shall have reasonable access to Operator’s personnel and to the facilities, warehouses, and offices directly serving Joint Operations. The cost of each such audit shall be borne by Non-Operators participating in the audit.  Where there are two or more Non-Operators, the Non-Operators shall make a reasonable effort to conduct joint or simultaneous audits in a manner that will result in a minimum of inconvenience to the Operator.  Non-Operators must take written exception to and make claim upon the Operator for all discrepancies disclosed by said audit within said 24 month period.  Non-Operators may request information from the Operator prior to the commencement of the audit. Operator will provide the information in electronic format or hard copy documents, if electronic format is not available.  Operator will provide the information requested within 30 Days before commencement of the audit but in no event sooner than 30 Days after the written request.  The information requested shall be limited to that normally used for pre-audit work such as trial balance, general ledger, and sub-ledger data.  A Non Operator must use an independent public accounting firm that is generally recognized in Israel, and only 1 audit may be conducted by the Non Operators (whether acting alone or in concert) every 12 months.

(B)   Operator shall endeavor to produce information from its Affiliates reasonably necessary to support charges from those Affiliates to the Joint Account other than those charges referred to in Section 3.1.

(C)   Except for charges under Section 2.7.1, the following provisions apply to all charges from Operator for its Affiliates. The internal records of an Operator’s Affiliate providing services to the Joint Operations may not be audited by the Non-Operator.  However, in addition to the information provided by the Operator under Section 1.8.2, and upon request by a Non-Operator within 24 months following the end of the same Calendar Year as provided in Section 1.8.1 above Operator will cause its Affiliate to provide Non-Operator an annual report (internally prepared).  The report will attest that charges billed from such Affiliate to the Joint Account represent a complete and accurate allocation of its costs to the Joint Operations.  The report will be furnished by the Operator within 12 months of the request from the Non-Operator.  The cost of providing the annual report shall be borne by the Non-Operator who requested the report.

(D)   The Operator may audit the records of an Affiliate of another Party relating to that Affiliate’s charges under Section 2.7.1.  The provisions of Section 1.8.3 shall apply mutatis mutandis to such audits unless otherwise agreed by the Parties. Should such charges be rejected under the provisions of 1.8.3, such charges shall be charged back to the Party whose Affiliate provided the service. Any Party may audit the records of a Non-Operator or its Affiliate relating to charges under Section 2.7.3.  The provisions of Section 1.8.3 shall apply mutatis mutandis to such audit, unless otherwise agreed by the Parties.  Should such charges be rejected under the provisions of 1.8.3, such charges shall be charged back to the Party whose Affiliate provided the service.

(E)   Any information obtained by a Party under the provisions of Section 1.8 which does not relate directly to the Joint Operations shall be kept confidential and shall not be disclosed to any party, except as would otherwise be permitted by Article 15.2(A)(3) and (10) of the Agreement.

(F)   In the event that the Operator is required by law or the Contract to employ a public accounting firm to audit the Joint Account and records of Operator relating to the accounting hereunder, or if the Operator elects to conduct an audit in its sole discretion, then the cost thereof shall be a charge against the Joint Account, and a copy of the audit shall be furnished to each Party.  If the Operator conducts an audit, then notwithstanding any other provision of the Agreement or these Accounting Procedures, no Non Operator will have the right to conduct an audit covering any time period addressed by the Operator’s audit.

(G)   At the conclusion of each audit, the Parties shall endeavor to settle outstanding matters expeditiously.  To this end the Parties conducting the audit will make a reasonable effort to prepare and distribute a written report to the Operator and all the Parties who participated in the audit as soon as possible and in any event within 90 Days after the conclusion of each audit.  The report shall include all claims, with supporting documentation, arising from such audit together with comments pertinent to the operation of the accounts and records.  Operator shall make a reasonable effort to reply to the report in writing as soon as possible and in any event no later than 90 Days after receipt of the report.  Should the Non-Operators consider that the report or reply requires further investigation of any item therein, the Non-Operators shall have the right to conduct further investigation in relation to such matter notwithstanding the provisions of Sections 1.7 and 1.8.1 that the period of 24 months may have expired.  However, conducting such further investigation shall not extend the 24 month period for taking written exception to and making a claim upon the Operator for all discrepancies disclosed by said audit. Such further investigations shall be commenced within 30 Days and be concluded within 60 Days after the receipt of such report or reply, as the case may be.

(H)   All adjustments resulting from an audit agreed between the Operator and the Non-Operator conducting the audit shall be reflected promptly in the Joint Account by the Operator and reported to the Non-Operator(s).  If any dispute shall arise in connection with an audit, it shall be reported to and discussed by the Operating Committee, and, unless otherwise agreed by the parties to the dispute, resolved in accordance with the provisions of Article 18 of the Agreement, if the dispute involves an amount in excess of $2,000,000.  If all the parties to the dispute so agree, the adjustment(s) may be referred to an independent expert agreed to by the parties to the dispute e.g. an independent accounting firm.  At the election of the parties to the dispute, the decision of the expert will be binding upon such parties.  Unless otherwise agreed, the cost of such expert will be shared equally by all parties to the dispute.

(I)   The provisions of this Section 1.8 apply to audits conducted under Article 4.12(C) of the Agreement except that the 60 Day advance notice and the advance information provisions of Section 1.8.1 shall not apply.

1.9   Allocations.

If it becomes necessary to allocate any costs or expenditures to or between Joint Operations and any other operations, such allocation shall be made on an equitable basis.  For informational purposes only, Operator shall furnish a description of its allocation procedures pertaining to these costs and expenditures and its rates for personnel and other charges, along with each proposed Work Program and Budget. Such allocation basis shall be subject to audit under Section 1.8.

ARTICLE 2.

CHARGES

Operator shall charge the Joint Account for all costs and expenditures incurred by Operator and its Affiliates for the conduct of Joint Operations within the limits of approved Work Programs and Budgets or as otherwise specified in the Agreement.

The costs and expenditures shall be recorded as required for the settlement of accounts between the Parties hereto in connection with the rights and obligations under the Agreement and for purposes of complying with the tax laws of the Country of Operations and of such other countries to which any of the Parties may be subject.

Chargeable costs and expenditures may include:

2.1   Licenses, Permits, Etc.

All costs, if any, attributable to the acquisition, maintenance, renewal or relinquishment of licenses, permits, contractual and/or surface rights acquired for Joint Operations and bonuses paid in accordance with the Contract when paid by Operator in accordance with the provisions of the Agreement.

2.2   Salaries, Wages and Related Costs.

Salaries, wages and related costs include everything constituting the employees’ total compensation, as well as the cost to Operator of holiday, vacation, sickness, disability benefits, living and housing allowances, travel time, bonuses, and other customary allowances applicable to the salaries and wages chargeable hereunder, as well as the costs to Operator for employee benefits, including but not limited to employee group life insurance, group medical insurance, hospitalization, retirement, severance payments required by the laws or regulations of the Country of Operations. Approval of the Operating Committee shall be required to charge the Joint Account with any severance payments in excess of those provided by the laws or regulations of the Country of Operations, and other benefit plans of a like nature applicable to labor costs of Operator.

All costs associated with organizational restructuring (e.g., separation benefits, relocation costs, asset disposition costs) of Operator or its Affiliates, other than those costs which are directly related to employees of Operator who are directly engaged in Joint Operations, will require the approval of the Parties to be chargeable to the Joint Account.

Any costs associated with Country of Operations benefit plans may be charged at a percentage rate to reflect payments or accruals made by Operator applicable to such employees.  Such accruals for Country of Operations benefit plans shall not be paid by Non Operators, unless otherwise approved by the Operating Committee, until the same are due and payable to the employee, upon withdrawal of a Party pursuant to the Agreement, or upon termination of the Agreement, whichever occurs first.

Expenditures or contributions made pursuant to assessments imposed by governmental authority for payments with respect to or on account of employees described in Section 2.2.1 and Section 2.2.2 shall be chargeable to the Joint Account.

(A)   Costs for salaries, wages and related costs of employees of Operator and its Affiliates temporarily or permanently assigned in or outside the Country of Operations may be charged to the Joint Account based upon Operator’s good faith determination (which may be an estimate) of the reasonably anticipated cost for comparably experienced talent specialized in the requirements of the Operator, in this Area of Operations.  It is acknowledged by all parties that the Operator’s cost may be less than the fee charged; however, the rate charged to the Operations will be commensurate with equitable and comparable specialists within the industry as defined by Operator’s sole judgment.

(B)   Reasonable expenses (including related travel costs) of those employees whose salaries and wages are chargeable to the Joint Account under Sections 2.2.1 and 2.2.2 and for which expenses the employees are reimbursed under the usual practice of Operator shall be chargeable to the Joint Account.

(C)   If employees are engaged in other activities in addition to the Joint Operations, the cost of such employees shall be allocated on an equitable basis.

2.3   Employee Relocation Costs.

(A)   Except as provided in Section 2.3.3, Operator’s cost of employees’ relocation to or from an assignment with the Joint Operations, whether within or outside the Country of Operations and whether permanently or temporarily assigned to the Joint Operations, shall be chargeable to the Joint Account. If such employee works on other activities in addition to Joint Operations, such relocation costs shall be allocated on an equitable basis.

(B)   Such relocation costs shall include transportation of employees, families, personal and household effects of the employee and family, transit expenses, and all other related costs in accordance with Operator’s usual practice.

(C)   Relocation costs to an assignment that is not with the Joint Operations shall not be chargeable to the Joint Account unless the place of the new assignment is the point of origin of the employee or unless otherwise agreed by the Operating Committee.

2.4   Offices, Camps, Hotels, and Miscellaneous Facilities.

Cost of maintaining any offices, sub offices, camps, warehouses, housing, and other facilities of the Operator and/or Affiliates directly serving the Joint Operations, including hotels and per diem costs for meals and other expenses for employees and contractors.  If such facilities serve operations in addition to the Joint Operations, the costs shall be allocated to the properties served on an equitable basis.

2.5   Material.

Cost, net of discounts taken by Operator, of Material purchased or furnished by Operator.  Such costs shall include, but are not limited to, export brokers’ fees, transportation charges, loading, unloading fees, export and import duties and license fees associated with the procurement of Material and in-transit losses, if any, not covered by insurance.  So far as it is reasonably practical and consistent with efficient and economical operation, only such Material shall be purchased for, and the cost thereof charged to, the Joint Account as may be required for immediate use.

2.6   Exclusively Owned Equipment and Facilities of Operator and Affiliates.

Charges for exclusively owned equipment, facilities, and utilities of Operator or any of its Affiliates at rates not to exceed the average commercial rates of non-affiliated third parties then prevailing for like equipment, facilities, and utilities for use in the area where the same are used hereunder.  On request, Operator shall furnish Non-Operators a list of rates and the basis of application.  Such rates shall be revised from time to time if found to be either excessive or insufficient, but not more than once every six months.

Exclusively owned drilling tools and other equipment lost in the hole or damaged beyond repair may be charged at replacement cost less depreciation plus transportation costs to deliver like equipment to the location where used.

2.7   Services.

(A)   The charges for services provided by third parties, shall be chargeable to the Joint Account.  Such charges for services by the Affiliates of the respective Parties shall not exceed those currently prevailing if performed by non-affiliated third parties, considering quality and availability of services, as determined by Operator in its reasonable discretion.

(B)   The cost of services performed by Operator’s Affiliates technical and professional staffs shall be chargeable to the Joint Account in a manner consistent with Section 2.2.1. The individual rates shall include salaries and wages of such technical and professional personnel, lost time, governmental assessments, and employee benefits.  Costs shall also include all support costs necessary for such technical and professional personnel to perform such services, such as, but not limited to, rent, hotels, per diem, utilities, support staff, drafting, software, computer facilities, telephone and other communication expenses, computer support, supplies, depreciation, and other reasonable expenses.  Examples of such services include the following:

Geologic Studies and Interpretation

Seismic Data Processing

Well Log Analysis, Correlation and Interpretation

Laboratory Services

Ecological and Environmental Engineering

Decommissioning (Abandonment) and Reclamation

Well Site Geology

Project Management and Engineering

Source Rock Analysis

Petrophysical Analysis

Geochemical Analysis

Drilling Supervision

Development Evaluation

Project Accounting and Professional Services

Other Data Processing

Costs incurred as payment for access to, and use of, technical data, intellectual property and know-how of the Operator’s group of Affiliates.  Such costs shall be included in annual Work Program and Budgets as a separate line item.

(C)   The cost of services performed by the technical and professional staffs (or otherwise) of the Non-Operators and the Affiliates of the respective Non-Operators (which services require the prior consent of the Operator in each instance), shall be chargeable to the Joint Account on terms approved in the sole discretion of the Operator in each instance. If the provision of such services is approved by the Operator, then the individual rates shall only include salaries and wages of such technical and professional personnel.

(D)   A Non-Operator shall bill Operator for direct costs of services charged under the provisions of Section 2.7.3 on or before the last Day of each month for charges for the preceding month, to which charges Non-Operator shall not add an administrative overhead rate.  Within 30 Days after receipt of a bill for such charges, Operator shall pay the amount due thereon; provided that each Party has advanced its pro rata share of such billed charges.

2.8   Insurance.

Premiums paid for insurance required by law, the Contract or the Agreement to be carried for the benefit of the Joint Operations.

2.9   Damages and Losses to Property.

(A)   All costs or expenditures necessary to replace or repair damages or losses incurred by fire, flood, storm, theft, accident, or any other cause shall be chargeable to the Joint Account.  Operator shall furnish Non-Operators written notice of damages or losses incurred in excess of U.S. $50,000 as soon as practical after report of the same has been received by Operator.  All losses in excess of U.S. $50,000 shall be listed separately in the monthly statement of costs and expenditures.

(B)   Credits for settlements received from insurance carried for the benefit of Joint Operations and from others for losses or damages to Joint Property or Materials shall be chargeable to the Joint Account.  Each Party shall be credited with its Participating Interest share thereof except where such receipts are derived from insurance purchased by Operator for less than all Parties in which event such proceeds shall be credited to those Parties for whom the insurance was purchased in the proportion of their respective contributions toward the insurance coverage.

(C)   Expenditures incurred in the settlement of all losses, claims, damages, judgments, and other expenses for the account of Joint Operations shall be chargeable to the Joint Account.

2.10   Litigation, Contracts, Dispute Resolution and Associated Legal Expenses.

Legal services necessary or expedient for the management and protection of the Joint Operations, and all costs and expenses of agreement drafting and negotiation, litigation, arbitration or other alternative dispute resolution procedure, including reasonable attorneys’ fees and expenses, together with all judgments obtained against the Parties or any of them arising from the Joint Operations.

2.11   Taxes and Duties.

All taxes, duties, assessments and governmental charges, of every kind and nature, assessed or levied upon or in connection with the Joint Operations, other than any that are measured by or based upon the revenues, income and net worth of a Party.

If Operator or an Affiliate is subject to income or withholding tax as a result of services performed at cost for the operations under the Agreement, its charges for such services may be increased (grossed up) by the amount of such taxes incurred.

2.12   Ecological and Environmental.

Costs incurred on the Joint Property as a result of statutory regulations for archaeological and geophysical surveys relative to identification and protection of cultural resources and/or other environmental or ecological surveys as may be required by any regulatory authority.  Also, costs to provide or have available pollution containment and removal equipment plus costs of actual control, clean up and remediation resulting from responsibilities associated with Hydrocarbon contamination as required by all applicable laws and regulations.

2.13   Decommissioning (Abandonment) and Reclamation.

Costs incurred for decommissioning (abandonment) and reclamation of the Joint Property, including costs required by governmental or other regulatory authority or by the Contract.

2.14   Other Expenditures.

Any other costs and expenditures incurred by Operator for the necessary and proper conduct of the Joint Operations in accordance with approved Work Programs and Budgets or as otherwise specified in the Agreement and not covered in Section 2.

ARTICLE 3.

ACQUISITION OF MATERIAL

3.1   Acquisitions.

Materials purchased for the Joint Account shall be charged at net cost paid by the Operator.  The price of Materials purchased shall include, but shall not be limited to export broker’s fees, insurance, transportation charges, loading and unloading fees, import duties, license fees, and demurrage (retention charges) associated with the procurement of Materials, and applicable taxes, less all discounts taken.

3.2   Materials Furnished by Operator.

Materials required for operations shall be purchased for direct charge to the Joint Account whenever practicable, except the Operator may furnish such Materials from its stock under the following conditions:

(A)   New Materials (Condition “A”).

New Materials transferred from the warehouse or other properties of Operator shall be priced at net cost determined in accordance with Section 4.1 as if Operator had purchased such new Material just prior to its transfer on terms that include delivery to the Contact Area in Israel.

Such net costs shall in no event exceed the then current market price.

(B)   Used Materials (Conditions “B” and “C”).

(1)   Material which is in sound and serviceable condition and suitable for use without repair or reconditioning shall be classed as Condition “B” and priced at 75% of such new purchase net cost at the time of transfer.

(2)   Materials not meeting the requirements of Section 4.2.2.1, but which can be made suitable for use after being repaired or reconditioned, shall be classed as Condition “C” and priced at 50% of such new purchase net cost at the time of transfer.  The cost of reconditioning shall also be charged to the Joint Account provided the Condition “C” price, plus cost of reconditioning, does not exceed the Condition “B” price; and provided that Material so classified meet the requirements for Condition “B” Material upon being repaired or reconditioned.

(3)   Material, which cannot be classified as Condition “B” or Condition “C”, shall be priced at a value commensurate with its use.

(4)   Tanks, derricks, buildings, and other items of Material involving erection costs, if transferred in knocked-down condition, shall be graded as to condition as provided in Section 4.2.2, and priced on the basis of knocked-down price of like new Material.

(5)   Material including drill pipe, casing and tubing, which is no longer useable for its original purpose but is useable for some other purpose, shall be graded as to condition as provided in Section 4.2.2.  Such Material shall be priced on the basis of the current price of items normally used for such other purpose if sold to third parties.

3.3   Premium Prices.

Whenever Material is not readily obtainable at prices specified in Sections 4.1 and 4.2 because of national emergencies, strikes or other unusual causes over which Operator has no control, Operator may charge the Joint Account for the required Material at Operator’s actual cost incurred procuring such Material, in making it suitable for use, and moving it to the Contract Area, provided that notice in writing, including a detailed description of the Material required and the required delivery date, is furnished to Non-Operators of the proposed charge at least thirty (30) Days (or such shorter period as may be specified by Operator) before the Material is projected to be needed for operations and prior to billing Non-Operators for such Material the cost of which exceeds U.S. $500,000.  Each Non-Operator shall have the right, by so electing and notifying Operator within ten (10) Days (or such shorter period as may be specified by Operator) after receiving notice from Operator, to furnish in kind all or part of his share of such Material per the terms of the notice which is suitable for use and acceptable to Operator both as to quality and time of delivery.  Such acceptance by Operator shall not be unreasonably withheld.  If Material furnished is deemed unsuitable for use by Operator, all costs incurred in disposing of such Material or returning Material to owner shall be borne by the Non-Operator furnishing the same unless otherwise agreed by the Parties.  If a Non-Operator fails to properly submit an election notification within the designated period, Operator is not required to accept Material furnished in kind by that Non-Operator.  If Operator fails to submit proper notification prior to billing Non-Operators for such Material, Operator shall only charge the Joint Account on the basis of the price allowed during a “normal” pricing period in effect at time of movement.

3.4   Warranty of Material Furnished by Operator.

Operator does not warrant the condition or fitness for the purpose intended of the Material furnished. In case defective Material is furnished by Operator for the Joint Account, credit shall not be passed to the Joint Account until adjustment has been received by Operator from the manufacturers or their agents.

ARTICLE 4.

DISPOSAL OF MATERIALS

4.1   Disposal.

Operator shall be under no obligation to purchase the interest of Non-Operators in new or used surplus Materials.  Operator shall have the right to dispose of Materials but shall advise and secure prior agreement of the Operating Committee of any proposed disposition of Materials having an original cost to the Joint Account either individually or in the aggregate of U.S. $500,000 or more.  When Joint Operations are relieved of Material charged to the Joint Account, Operator shall advise each Non-Operator of the original cost of such Material to the Joint Account so that the Parties may eliminate such costs from their asset records.  Credits for Material sold by Operator shall be made to the Joint Account in the month in which payment is received for the Material.  Any Material sold or disposed of under this Section 5 shall be on an “as is, where is” basis without guarantees or warranties of any kind or nature.  Costs and expenditures incurred by Operator in the disposition of Materials shall be charged to the Joint Account.

4.2   Material Purchased by a Party or Affiliate.

Proceeds received from Material purchased from the Joint Property by a Party or an Affiliate thereof shall be credited by Operator to the Joint Account, with new Material valued in the same manner as new Material under Section 4.2.1 and used Material valued in the same manner as used Material under Section 4.2.2, unless otherwise agreed by the Operating Committee.

4.3   Division In Kind.

Division of Material in kind, if made between the Parties, shall be in proportion to their respective interests in such Material.  Each Party will thereupon be charged individually with the value (determined in accordance with the procedure set forth in Section 5.2) of the Material received or receivable by it, net of all applicable costs of transportation and handling.

4.4   Sales to Third Parties.

Proceeds received from Material purchased from the Joint Property by third parties shall be credited by Operator to the Joint Account at the net amount collected by Operator from the buyer.  If the sales price is more than 15% less than the value determined in accordance with the procedure set forth in Section 5.2, then approval by the Operating Committee shall be required prior to the sale.  Any claims by the buyer for defective materials or otherwise shall be charged back to the Joint Account if and when paid by Operator.

ARTICLE 5.

INVENTORIES

5.1   Periodic Inventories - Notice and Representation.

At reasonable intervals, but at least annually, inventories shall be taken by Operator of all Material held in warehouse stock on which detailed accounting records are normally maintained.  The expense of conducting periodic inventories shall be charged to the Joint Account.  Operator shall give Non-Operators written notice at least 60 Days in advance of its intention to take inventory, and Non-Operators, at their sole cost and expense, shall each be entitled to have a representative present.  The failure of any Non-Operator to be represented at such inventory shall bind such Non-Operator to accept the inventory taken by Operator.  Operator shall in any event furnish each Non-Operator with a reconciliation of overages and shortages.  Inventory adjustments to the Joint Account shall be made for overages and shortages.  Any adjustment equivalent to U.S. $100,000 or more shall be brought to the attention of the Operating Committee.

5.2   Special Inventories.

Whenever there is a sale or change of a Participating Interest in the Agreement, a special inventory may be taken by the Operator provided the seller and/or purchaser of such interest agrees to bear all of the expense thereof.  In such cases, both the seller and the purchaser shall be entitled to be represented and shall be governed by the inventory so taken.

Exhibit B

Contract Area

From location 173874/653751 along the shoreline toward south-west to location 158667/622000

From location 158667/622000 toward north-west to location 147358/624522

From location 147358/624522 toward north-east to location 149885/628153

From location 149885/628153 toward north-north-east to location 153474/637592

From location 153474/637592 toward south-east to location 159833/634744

From location 159833/634744 toward north-east to location 162631/641203

From location 162631/641203 toward north-west to location 159880/642935

From location 159880/642935 toward north to location 159758/653564

From location 159758/653564 toward south-east to location 160513/653323

From location 160513/653323 toward north-east to location 162218/658154

From location 162218/658154 toward south-east back to location 173874/653751 on shoreline

(Total area approximately 361,000 dunam (approximately 361.000 sq. km) The coordinates based on the new Israeli network)

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

GeoGlobal Resources Inc.

We consent to the incorporation by reference in the registration statement (Forms S-8 Nos. 333-74245, 333-39450, 333-67720, 333-130135, 333-136065 and 333-156429; Forms S-3 Nos. 333-168031, 333-145529 and 333-129225) of GeoGlobal Resources Inc. of our reports dated March 31, 2011, with respect to the consolidated balance sheets of GeoGlobal Resources Inc. as of December 31, 2010 and 2009, and the related consolidated statements of earnings, stockholders’ equity, cash flows, and comprehensive income for each of the years in the three-year period ended December 31, 2010 and for the period from August 21, 2002 (inception) to December 31, 2010, and the effectiveness of internal control over financial reporting as of December 31, 2010, which reports appear in the December 31, 2010 annual report on Form 10-K of GeoGlobal Resources Inc..

Our report dated March 31, 2011 contains an explanatory paragraph that states that the Company has suffered recurring losses from operations and a deficit accumulated during the development stage, which raise substantial doubt about its ability to continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of that uncertainty.

(Signed) KPMG LLP

Calgary, Alberta

March 31, 2011

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our firm under the caption "Experts" and to the use of our report dated March 23, 2007 (except Note 8 as to which the date is June 5, 2008) with respect to the consolidated results of operations, changes in shareholders’ equity and cash flows for the cumulative period from inception on August 21, 2002 to December 31, 2006 (not separately presented herein) of GeoGlobal Resources Inc., included in the Annual Report (Form 10-K) for 2010 filed with the Securities and Exchange Commission.

CALGARY, ALBERTA                                                                                                          Ernst & Young LLP

March 23, 2007 except for Note 8,                                                                                        CHARTERED ACCOUNTANTS

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Paul B. Miller, certify that:

1.      I have reviewed this Annual Report on Form 10-K of GeoGlobal Resources Inc.;

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.      The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles:

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.      The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2011                                            /s/ Paul B. Miller

---------------------------

Paul B. Miller

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF THE

SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Sunil Karkera, certify that:

1.      I have reviewed this Annual Report on Form 10-K of GeoGlobal Resources Inc.;

2.      Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.      Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.              The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles:

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.      The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 31, 2011                                            /s/ Sunil Karkera

---------------------------

Sunil Karkera

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of GeoGlobal Resources Inc. (the “Company”) on Form 10-K for the year ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Paul B. Miller, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Paul B. Miller

---------------------------

Paul B. Miller

President and Chief Executive Officer

March 31, 2011

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of GeoGlobal Resources Inc. (the “Company”) on Form 10-K for the year ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Sunil Karkera, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Sunil Karkera

------------------------

Sunil Karkera

Chief Financial Officer

March 31, 2011