Chapman Petroleum Engineering Report dated January 1, 2012 effective December 31, 2011

 

 

 
 

February 15, 2012

200, 625 - 4th Avenue SW

Calgary, AB

T2P 0K2

Dear Sir:

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 in the Tarapur field in India, owned by GeoGlobal Resources Inc. (the "Company") for an effective date of January 1, 2012 (as of December 31, 2011). This report includes all of the reserves owned by the Company.

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 methodology and procedures used for the preparation of this report are appropriate for the purpose of this report.  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. We have used all methods and procedures as considered necessary under the circumstances to prepare the 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 are not aware of any regulatory issues relating to the proved reserves in this report that would cause them to not be recovered. Certain of the probable reserves assigned are waiting on regulatory approvals prior to being placed on production, upon which they would be reclassified as proven reserves. The operation is in the process of seeking the requested approvals.   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,

[Original Signed By:]

C.W. Chapman, P. Eng.,

President

[Original Signed By:]

Roy A. Collver, P. Eng

Petroleum Engineer

 

 

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 15, 2012, 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, P.Eng.

President

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 15, 2012, 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, P. Eng.

Petroleum Engineer

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

Table 1:                             Summary of Company Reserves and Economics Before Tax

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

Ownership

Exploration and Development

Geology

Reserves

Production

Product Prices

Capital Expenditures

Operating Costs

 

 

This evaluation has been authorized by Mr. Sunil Karkera, on behalf of GeoGlobal Resources Inc.   The engineering analysis has been performed during the month of February 2012.

The purpose of this report was to prepare a third party independent appraisal of all 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 for an effective date of December 31, 2011.

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.

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:

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 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 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.

 

(v) 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.

(vi) 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.

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.

 

 

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.

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

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.

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

 

 

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.

 

 

The economic analysis has been performed on a spread sheet format to account for all the terms of the PSC.

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 and are presented in the Summary of Reserves and Economics (SEC).

Table 1
Summary of Company Reserves and Economics
Before Income Tax
January 1, 2012
GeoGlobal Resources Inc
			Net  To  Appraised   Interest
			Reserves									Cumulative Cash Flow (BIT) - M$
				Light and Medium				Sales Gas
				Oil	MSTB			MMscf				Discounted at:
Description				Gross		Net		Gross		Net		Undisc.		5%/year		10%/year		15%/year		20%/year
Proved Developed Producing
	Tarapur wells (Kalol)			23		23		59		59		302		780		940		977		966
Proved Undeveloped
	Tarapur wells (Kalol)			232		228		141		138		14,743		10,142		7,355		5,523		4,239
	Tarapur wells (Kalol)			255		251		200		197		15,036		10,922		8,295		6,500		5,205
Total Proved				255		251		200		197		15,036		10,922		8,295		6,500		5,205
Probable
	Tarapur wells (Kalol)			534		477		658		585		36,469		26,570		20,060		15,574		12,366
Total Probable				534		477		658		585		36,469		26,570		20,060		15,574		12,366
Total Proved Plus Probable				789		728		857		782		51,505		37,492		28,355		22,074		17,571
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
Summary of Company Reserves and Economics
After Income Tax
January 1, 2012
GeoGlobal Resources Inc
				Reserves									Cumulative Cash Flow  - M$
				Light and Medium					Sales Gas
					Oil	MSTB			MMscf				Discounted at:
Description					Gross		Net		Gross		Net		Undisc.		5%/year		10%/year		15%/year		20%/year
Total Proved
	Total Proved (BIT)				255		251		200		197		15,036		10,922		8,295		6,500		5,205
	Company Income Tax				-		-		-		-		-		-		-		-		-
Total Proved (AIT)					255		251		200		197		15,036		10,922		8,295		6,500		5,205
	Total Probable (BIT)				534		477		658		585		36,469		26,570		20,060		15,574		12,366
	Company Income Tax				--		--		--		--		(4,570)		(3,543)		(2,785)		(2,217)		(1,784)
Total Probable (AIT)					534		477		658		585		31,899		23,027		17,275		13,357		10,582
Total Proved Plus Probable (AIT)					789		728		857		782		46,935		33,949		25,570		19,857		15,787
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.

TARAPUR, INDIA

 

 

The Company Geoglobal Resources (Barbados) Inc. owns a 14% participating interest in the TA-1 Development Area (2.14 km2) and a 20% participating interest in the remaining mining lease area (9.7 km2). The TA-1 Development area is currently under commercial development, and the mining lease area remains in the exploration phase.  At present there are six producing wells within the TA-1 development area, and another 10 non-producing wells in the mining lease area waiting to be tied in.

 

A detailed description of the lands, interests and royalty burdens for this property is presented in Table 1.  All royalties and cess fees are paid by the licensee; ONGC.

 

 

Exploration and Development

 

The Production Sharing Contract (PSC) for Block CB-ON/2 was signed on 12th April, 2000 between the Joint Venture Partners, namely, GSPC (Operator)-HOEC-ONGC1 and the Government of India, with GSPC and HOEC each holding a 50% participating interest.  ONGC has exercised the right to take a 30% participating interest as per Article: 13.2 of the PSC, which has reduced each partner’s interest accordingly.

 

A Petroleum Exploration License (PEL) was granted on 22nd November, 2000 and exploration activities committed under Phase-I were completed on 21st November, 2002 when HOEC elected not to proceed to phase II of exploration and relinquished its share without consideration. Hence, after November 22, 2002, the share of GSPC in the Joint Venture was increased to 100%.

 

In April 2005, Geoglobal Resources Inc. purchased a 20% participating interest in this block from GSPC. ONGC maintained an option that allowed them to increase their participating interest by 30%, thereby reducing the interest held by Geoglobal Resources Inc. to 14%. In April 2009, as per article no 13.2 of the PSC, ONGC has exercised their participation right in the Tarapur-1 development area (2.14 km2).

During Phase-II, GSPC drilled the Tarapur # 1 discovery well and then Tarapur # P as an appraisal well.  Both of the wells flowed oil in commercial quantities.

 

GSPC as Operator evaluated the hydrocarbon potential of Block CB-ON/2 using existing 2D seismic data (4200lkm) shot by NOC.  On the basis of this seismic interpretation, six structural and strati-structural leads were identified.

GSPC entered Phase-III on November 22, 2005 to retain the whole block area. GSPC drilled five wells by April, 2006 and then two more exploratory wells identified on the basis of amplitude anomaly.  Tarapur # 5 proved to be oil bearing which established the extent of oil reservoir discovered in Tarapur # 1 whereas Tarapur # 7 did not show any presence of hydrocarbon and was abandoned.

 

 

GSPC acquired, processed and interpreted 560 sq km of additional 3D seismic and identified new leads for future drilling.

 

The Operator’s Phase III development included drilling three additional wells on the main structure encountered by Tarapur # 1, P and 5 and an additional seven wells on the structure encountered by Tarapur # 6.

 

On May 4, 2009 the Management committee approved the Tarapur 1 field development plan which covers an area of approximately 2.14 sq. km. within the Tarapur 1 Discovery Area of approximately 9.7 sq. km. 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 of these wells are tied into the oil tank storage facilities by way of a gathering system.

 

As of the effective date of this report, the operator has successfully initiated production from the six wells on the main structure, but all have encountered significant issues with low permeability and gas breakthrough.  The operator is continuing to review options available to remediate these problems.

 

 

The Company’s lands in this area have oil and gas production from the Tertiary Middle Eocene Kalol formation that is well developed in the North Cambay Basin2.  The Kalol Formation has been subdivided from bottom to top into three members: Sertha, Kansari and Wavel.  The Kalol was deposited under alternating regressive and transgressive regimes in a deltaic environment.  The regressive phases led to the deposition of the Wavel and Sertha members, and the transgressive phase led to the deposition of the Kansari Shale.

 

The Cambay rift Basin, a rich Petroleum Province of India is a narrow, elongated rift graben, extending from Surat in the south to Sanchor in the north.  The general orientation of the basinal axis is NNW-SSE, which swings to north-south in the northern part near Tharad.  Based on major transverse basement ridges and fault systems, the basin is subdivided into five tectonic blocks, one of which is called the Tarapur–Cambay where Block CB-ON/2 is situated.  Each of the five tectonic blocks contains an independent depocenter.

 

The Kalol Formation is the main reservoir in the northern Cambay Basin as seen in Figure 2: Stratigraphy.

 

The Kalol is dominated by argillaceous sediments with only thinly developed sandstones and common oolitic sediments.  These sediments are interbedded with locally well developed coals that show the characteristic low density response on wireline logs.

 

 

The Kalol Formation over most of the area of Block CB-ON/2 is considered to represent a variably condensed horizon deposited in a series of shallow water, restricted lagoons and bays, possibly with an estuarine character.  The oolitic sediments are commonly associated with thin coal horizons and in some cases may even represent pedogenic (soil related) coated grains.  In either case, the oolitic sediments represent iron-rich oolites that occur in a clay matrix and are associated with abundant early diagenetic cements such as siderite and pyrite.  These sediments contain negligible intergranular porosity and they form poor to very poor quality reservoirs.

The net pay in the Kalol varies from 8 to 19 metres, and an average effective porosity of 17% and an average water saturation of 30% have been assigned to this field.  The key to commercial oil production from this Kalol pool is the use infill horizontal wells with multiple stages of hydraulic fracturing treatments to increase permeability and reduce the transient pressure depletion experienced in the region near the wellbore.

 

 

Total proved light and medium oil reserves of 1,610 MSTB have been assigned to this area asfollows:

 

Total proved developed producing light oil reserves of 147 MSTB have been estimated for the six producing wells based on reservoir parameters derived from core data, as well as current production performance.

 

Total proved undeveloped light oil reserves of 1,462 MSTB have been estimated for six 1 km multi-stage frac horizontal development locations planned on the main structure, using average reservoir parameters and analogy to similar areas where multi frac horizontal technology has been applied.

 

Total probable reserves of 3,820 MSTB have been assigned to this area based on the following methodology.

 

Probable developed producing incremental oil reserves of 216 MSTB have been estimated for the six producing wells, assuming slightly improved recovery factors over the proved case.

 

Probable developed non-producing oil reserves of 1,226 MSTB have been assigned to the 8 wells on the Tarapur # 6 structure and the Tarapur # 4 well.  These reserves were assigned based on reservoir parameters derived from core data, and analogy with currently producing wells.

 

Probable developed non-producing marketable non-associated gas reserves of 2,522 MMscf have been assigned to the well Tarapur # G based on reservoir parameters derived from log analysis.

 

Probable additional undeveloped reserves of 486 MSTB have been assigned to the six multi-stage frac horizontal development locations planned for the TA-1 development area, assuming improved recovery factors over the proved case.

 

Probable undeveloped reserves of 1,888 MSTB have been assigned to eight 800m multi-stage frac horizontal development locations planned for the TA-6 development area, using average reservoir parameters and analogy to similar areas where multi frac horizontal technology has been applied.

 

 

Production from this property currently averages 91 STB/d from six producing wells.

 

 

Under the probable forecast, production from the wells on the Tarapur 6 structure is expected to commence in January of 2014 at a combined rate of 600 STB/d.

 

Production from the well Tarapur 4 is expected to start in January of 2014 at a rate of 100STB/d, and production from the gas well Tarapur G is expected to commence in January of 2014 at a rate of 750 Mscf/d.

 

Production from the 6 undeveloped multi frac horizontal locations on the TA-1 structure is expected to commence in January of 2013 at a combined rate of 600 STB/d.

 

Production from the 8 undeveloped multi frac horizontal locations on the TA-6 structures is expected to commence in January of 2015 at a combined rate of 800 STB/d.

 

All production rates are expected to decline over the lives of the wells towards an eventual economic limit.

 

A constant price of $97.52/STB for oil and $7.11/Mscf of gas have been utilized for all years in the economics analysis.

 

The prices have been calculated as follows:

The Company receives revenue based on total monthly production and the average Bonny Light price of that month. Therefore, every day of the month receives the same price, which is at a constant differential to the monthly average of the Bonny Light price index. Under SEC guidelines, the constant price is calculated as the average price differential applied to the unweighted arithmetic average of the first-day-of-the-month price for each of the 12 months proceeding the effective date.

 

 The gas price is based on current contractual arrangement the Company has in place to market the gas produced from this property.

 

These prices were calculated according to the new SEC pricing guidelines

 

Total capital expenditures of $42,000,000 have been anticipated for this property in the proved case, ($5,880,000 net to the Company), as presented in Table 3a.Total capital expenditures of $90,000,000 have been anticipated for this property in the proved plus probable case, ($12,600,000 net to the Company).

 

Abandonment and restoration costs (net of salvage) of $3,000,000 ($420,000 net to the Company) in the proved plus probable case have been estimated for this area.

 

Estimates were based on experience with similar fields in the area, and discussions with the Company.

 

Fixed costs have been estimated at $200,000 per year, plus $100,000 per year per active well.  Variable costs have been estimated at $4.50/STB and $0.35/Mscf.  These estimates are based on revenue statements supplied by the Company.

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