RICHARDSON & PATEL, LLP
10900 Wilshire Boulevard, Suite 500
Los Angeles, California, 90024
October 26, 2005
Via EDGAR Transmission and Federal Express
United States Securities and Exchange Commission
Office of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
Attention: Mr. H. Christopher Owings, Assistant Director
Ms. Anita Karu, Attorney Advisor
Re: Comment Letter dated September 2, 2005
File No. 0-52484
Fortune Oil & Gas, Inc.
Registration Statement on Form 10, Amendment No. 1
Dear Mr. Owings:
On behalf of Fortune Oil & Gas, Inc. (the "Company"), we enclose as
supplemental information certain "reserve reports" in connection with our
previously filed response to Staff's comments, filed on October 18, 2005.
The attached supplemental information is responsive to Staff comment
number 29, reprinted below.
29. Please provide us with the reserve report by Petroleum Geo-Services.
In response to Staff Comments, we are attaching the reserve report to this
Response Letter.
We hope that the information contained in this letter completes the
information set forth in the Company's response letter of October 18,
2005. Please do not hesitate to contact the undersigned by telephone at
(310) 208-1182, or by facsimile at (310) 208-1154 for further assistance.
Very truly yours,
RICHARDSON & PATEL LLP
By:
-----------------------
Jennifer A. Post, Esq.
Cc: Mr. James Wensveen
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 1999 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 1.104 0.000 1.104
---------------------------------------------------------
Net to IPRJ 0.983 0.000 0.983
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central
processing platform is located on the southern lobe of the field, and
this platform processes all the field production and pipes the stabilized
oil to the floating storage unit. The platform is unmanned; all
production operations are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty,
although there is a "First Tranche Provision" (FTP) which is a percentage
of the gross production revenue that is shared directly with the
government, before any cost recovery or profit oil is taken. The FTP is
20 percent of the gross production revenue, and the contractor group is
entitled to a 45.45 percent share of it. Allowable costs are recovered
from the remaining 80 percent of the gross production, with any unused
cost oil being shared with the government in the same proportions as the
FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the
average WTI price for the week in which the 31st December falls, and the
fixed and variable operating costs have been estimated from copies of the
financial reports submitted by Indo-Pacific Resources (Java) Ltd. to the
Indonesian authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the
decline trends observed in the historical production data, or result in
any future reserve additions. If the field was shut-in prior to the
year-end, it has been assumed that production would re-commence at the
beginning of the new year.
As of the 31st December 1999, the ultimate recovery and remaining
reserves for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-99 9.467 8.434
31-Dec-00 9.969 0.502 1,372 8.882 0.447 1,222
31-Dec-01 10.276 0.307 840 9.155 0.273 748
31-Dec-02 10.464 0.188 514 9.322 0.167 458
31-Dec-03 10.571 0.107 294 9.418 0.096 261
31-Dec-04 10.571 0.000 0 9.418 0.000 0
Reserves at 31-Dec-99 1.104 mmbbls 0.983 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31 years
of varied petroleum and reservoir engineering experience. He has an MA in
Natural Sciences, and is a Chartered Engineer. Other PGS employees
involved in this work hold at least a bachelor degree (or its equivalent)
in geology, geophysics, petroleum engineering or a related subject and
have at least five years' relevant experience in the practice of geology,
geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks SL6 7AA
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 2000 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 1.119 0.000 1.119
---------------------------------------------------------
Net to IPRJ 0.997 0.000 0.997
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central
processing platform is located on the southern lobe of the field, and
this platform processes all the field production and pipes the stabilized
oil to the floating storage unit. The platform is unmanned; all
production operations are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty,
although there is a "First Tranche Provision" (FTP) which is a percentage
of the gross production revenue that is shared directly with the
government, before any cost recovery or profit oil is taken. The FTP is
20 percent of the gross production revenue, and the contractor group is
entitled to a 45.45 percent share of it. Allowable costs are recovered
from the remaining 80 percent of the gross production, with any unused
cost oil being shared with the government in the same proportions as the
FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the
average WTI price for the week in which the 31st December falls, and the
fixed and variable operating costs have been estimated from copies of the
financial reports submitted by Indo-Pacific Resources (Java) Ltd. to the
Indonesian authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the
decline trends observed in the historical production data, or result in
any future reserve additions. If the field was shut-in prior to the
year-end, it has been assumed that production would re-commence at the
beginning of the new year.
As of the 31st December 2000, the ultimate recovery and remaining
reserves for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-00 9.467 8.434
31-Dec-01 9.968 0.501 1,373 8.881 0.446 1,222
31-Dec-02 10.275 0.307 841 9.154 0.273 749
31-Dec-03 10.463 0.188 515 9.322 0.168 458
31-Dec-04 10.579 0.115 315 9.425 0.103 280
31-Dec-05 10.586 0.007 20 9.431 0.007 18
31-Dec-06 10.586 0.000 0 9.431 0.000 0
Reserves at 31-Dec-00 1.119 mmbbls 0.997 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31
years of varied petroleum and reservoir engineering experience. He
has an MA in Natural Sciences, and is a Chartered Engineer. Other
PGS employees involved in this work hold at least a bachelor degree
(or its equivalent) in geology, geophysics, petroleum engineering or
a related subject and have at least five years' relevant experience
in the practice of geology, geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks SL6 7AA
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 2001 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 0.083 0.000 0.083
---------------------------------------------------------
Net to IPRJ 0.074 0.000 0.074
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central processing
platform is located on the southern lobe of the field, and this platform
processes all the field production and pipes the stabilized oil to the
floating storage unit. The platform is unmanned; all production operations
are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty, although
there is a "First Tranche Provision" (FTP) which is a percentage of the
gross production revenue that is shared directly with the government,
before any cost recovery or profit oil is taken. The FTP is 20 percent of
the gross production revenue, and the contractor group is entitled to a
45.45 percent share of it. Allowable costs are recovered from the
remaining 80 percent of the gross production, with any unused cost oil
being shared with the government in the same proportions as the FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the average
WTI price for the week in which the 31st December falls, and the fixed and
variable operating costs have been estimated from copies of the financial
reports submitted by Indo-Pacific Resources (Java) Ltd. to the Indonesian
authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the decline
trends observed in the historical production data, or result in any future
reserve additions. If the field was shut-in prior to the year-end, it has
been assumed that production would re-commence at the beginning of the new
year.
As of the 31st December 2001, the ultimate recovery and remaining reserves
for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-01 9.767 8.702
31-Dec-02 9.850 0.083 226 8.775 0.074 201
31-Dec-03 9.850 0.000 0 8.775 0.000 0
31-Dec-04 9.850 0.000 0 8.775 0.000 0
31-Dec-05 9.850 0.000 0 8.775 0.000 0
31-Dec-06 9.850 0.000 0 8.775 0.000 0
Reserves at 31-Dec-01 0.083 mmbbls 0.074 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31 years
of varied petroleum and reservoir engineering experience. He has an MA in
Natural Sciences, and is a Chartered Engineer. Other PGS employees
involved in this work hold at least a bachelor degree (or its equivalent)
in geology, geophysics, petroleum engineering or a related subject and
have at least five years' relevant experience in the practice of geology,
geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks SL6 7AA
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 2002 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 0.355 0.000 0.355
---------------------------------------------------------
Net to IPRJ 0.316 0.000 0.316
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central processing
platform is located on the southern lobe of the field, and this platform
processes all the field production and pipes the stabilized oil to the
floating storage unit. The platform is unmanned; all production operations
are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty, although
there is a "First Tranche Provision" (FTP) which is a percentage of the
gross production revenue that is shared directly with the government,
before any cost recovery or profit oil is taken. The FTP is 20 percent of
the gross production revenue, and the contractor group is entitled to a
45.45 percent share of it. Allowable costs are recovered from the
remaining 80 percent of the gross production, with any unused cost oil
being shared with the government in the same proportions as the FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the average
WTI price for the week in which the 31st December falls, and the fixed and
variable operating costs have been estimated from copies of the financial
reports submitted by Indo-Pacific Resources (Java) Ltd. to the Indonesian
authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the decline
trends observed in the historical production data, or result in any future
reserve additions. If the field was shut-in prior to the year-end, it has
been assumed that production would re-commence at the beginning of the new
year.
As of the 31st December 2002, the ultimate recovery and remaining reserves
for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-02 9.872 8.795
31-Dec-03 10.058 0.186 509 8.960 0.165 453
31-Dec-04 10.172 0.114 311 9.062 0.102 277
31-Dec-05 10.227 0.055 151 9.111 0.049 134
31-Dec-06 10.227 0.000 0 9.111 0.000 0
31-Dec-07 10.227 0.000 0 9.111 0.000 0
Reserves at 31-Dec-02 0.355 mmbbls 0.316 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31 years
of varied petroleum and reservoir engineering experience. He has an MA in
Natural Sciences, and is a Chartered Engineer. Other PGS employees
involved in this work hold at least a bachelor degree (or its equivalent)
in geology, geophysics, petroleum engineering or a related subject and
have at least five years' relevant experience in the practice of geology,
geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks SL6 7AA
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 2003 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 0.381 0.000 0.381
---------------------------------------------------------
Net to IPRJ 0.339 0.000 0.339
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central
processing platform is located on the southern lobe of the field, and
this platform processes all the field production and pipes the stabilized
oil to the floating storage unit. The platform is unmanned; all
production operations are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty,
although there is a "First Tranche Provision" (FTP) which is a percentage
of the gross production revenue that is shared directly with the
government, before any cost recovery or profit oil is taken. The FTP is
20 percent of the gross production revenue, and the contractor group is
entitled to a 45.45 percent share of it. Allowable costs are recovered
from the remaining 80 percent of the gross production, with any unused
cost oil being shared with the government in the same proportions as the
FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the
average WTI price for the week in which the 31st December falls, and the
fixed and variable operating costs have been estimated from copies of the
financial reports submitted by Indo-Pacific Resources (Java) Ltd. to the
Indonesian authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the
decline trends observed in the historical production data, or result in
any future reserve additions. If the field was shut-in prior to the
year-end, it has been assumed that production would re-commence at the
beginning of the new year.
As of the 31st December 2003, the ultimate recovery and remaining
reserves for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-03 10.057 8.960
31-Dec-04 10.249 0.192 524 9.131 0.171 467
31-Dec-05 10.366 0.117 321 9.235 0.104 286
31-Dec-06 10.438 0.072 197 9.299 0.064 175
31-Dec-07 10.438 0.000 0 9.299 0.000 0
31-Dec-08 10.438 0.000 0 9.299 0.000 0
Reserves at 31-Dec-03 0.381 mmbbls 0.339 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31 years
of varied petroleum and reservoir engineering experience. He has an MA in
Natural Sciences, and is a Chartered Engineer. Other PGS employees
involved in this work hold at least a bachelor degree (or its equivalent)
in geology, geophysics, petroleum engineering or a related subject and
have at least five years' relevant experience in the practice of geology,
geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
PGS Reservoir Limited
PGS Thames House
17 Marlow Road
Maidenhead
Berks SL6 7AA
The Directors
Fortune Oil & Gas Inc.
Suite # 305 - 1656 Martin Drive
White Rock, B.C. V4A 6E7
CANADA
18th March 2005
Dear Sirs,
Re: Oil & Gas Reserves of the Camar Field, Offshore Indonesia
At your request we have performed an independent assessment of the
reserves of the Camar oilfield, offshore Indonesia. We have conducted the
evaluation in accordance with accepted industry practice, based on
information made available to PGS Reservoir Ltd ("PGS") during a visit to
the offices of Indo-Pacific Resources (Java) Ltd in July 2004.
A summary of the reserves assessment as at 31st December 2004 is presented
below:
---------------------------------------------------------
Reserves Proved Proved Total
Category:- Developed Undeveloped Proved
mmbbls mmbbls mmbbls
---------------------------------------------------------
Gross 0.237 0.000 0.237
---------------------------------------------------------
Net to IPRJ 0.211 0.000 0.211
---------------------------------------------------------
There are currently no gas reserves in the Camar field which can be
admitted to the Proved category.
The reserves have been estimated in accordance with the definition of
Proved Reserves included within Rule 4-10(a) of Regulation S-X of the US
Securities Exchange act of 1934.
Professional Qualifications
PGS Reservoir Limited is an independent consultancy specialising in
petroleum reservoir evaluation and economic analysis. Except for the
provision of professional services on a fee basis, PGS Reservoir Limited,
does not have a commercial arrangement with any other person or company
involved in the interests which are the subject of this letter.
Introduction
In carrying out this evaluation PGS have relied upon information provided
by Fortune Oil & Gas Inc., via its wholly owned subsidiary Indo-Pacific
Resources (Java) Ltd. (IPRJ). This consisted of engineering and
exploration data, technical reports, interpreted data, costs and
commercial data. The interpreted data and technical reports all pre-date
Fortune's involvement in the Bawean Production Sharing Contract area, in
which the Camar field lies.
In estimating the reserves, we have used the standard techniques of
petroleum engineering. The Camar field is relatively mature, and
performance extrapolation methods have primarily been used to estimate
reserves.
It should be noted that whilst the uncertainty in the estimate of ultimate
recovery of a mature field tends to decrease with time, the uncertainty in
the reserves tends to increase in the late stages of the field's life. The
absolute magnitude of the uncertainties may be decreasing, but they
represent an increasing proportion of what remains.
Reserves definitions as they apply to the estimates disclosed in this
letter are presented in Appendix 1.
Camar Field
The Camar field lies approximately 50 miles offshore the northern coast of
eastern Java in the Bawean Production Sharing Contract Area. The discovery
well, JS-1/1 was drilled in 1970 by Cities Service, and two appraisal
wells were also drilled in the early 1970s. The discovery well tested
1,200 b/d of oil from the upper Oligocene Kujung II carbonates, but the
discovery was considered non-commercial at that time, and the contract
area was relinquished.
In 1981, Kerr-McGee were awarded the Bawean Production Sharing Contract
Area, and between 1982 and 1985 they drilled three further Camar field
appraisal wells. Texas Eastern then drilled another two wells in 1986,
having taken over operatorship from Kerr-McGee. Texas Eastern prepared a
development plan for Camar, but were bought by Enterprise Oil before it
was implemented. The development was therefore undertaken by Enterprise,
with six development wells being drilled in 1989- 1990, and first oil
production occurring from the field in 1991.
Field performance did not live up to the operator's expectations, and the
field was shut-in during 1994, due to low reservoir pressure and
increasing water production problems. The Bawean PSC area was then
purchased by Carmanah Resources Limited, through a wholly owned subsidiary
named GFB Resources (Java) Ltd. GFB undertook some additional development
drilling, and added three more development wells during 1997 - 1998. The
field was again shut-in during March 1999.
In May 2000 Fortune Oil & Gas Inc. acquired the Bawean PSC area through
their wholly owned subsidiary Indo-Pacific Resources (Java) Ltd., and the
Camar field was re-activated to commence production again in January 2001.
The field was once again shut-in at the end of March 2004, and has
remained so since then. At that time, four wells from a total of nine were
still on production, with around eighty five percent of the total oil
production coming from one well in the southern lobe.
The Camar field is a twin-lobed structure trending North-East to
South-West, and all the oil production is from the Kujung II (upper
Oligocene) unit. This unit is a complex fractured carbonate at an average
depth of about 3,800 feet, which is sub-divided into upper and lower
intervals, both of which are capped by shales. Oil is present in the upper
limestone interval (the Kujung II Upper zone), but the potential pay zones
of these reservoirs are difficult to correlate and appear to be isolated
from one another. This zone was tested in the Camar 6 well, but it had
poor permeability.
The principal productive zones in the Camar field are in the lower
limestone interval of the Kujung II unit, which are subdivided into the
Kujung II LL1, LL2, LL3, and LL4 zones, from youngest to oldest. The
Kujung II unit is heterogeneous, and was deposited in a low-energy,
carbonate shelf environment. Below the LL4 limestone is a clastic zone -
the LL4 sandstone. This zone has proved reserves in the Camar 6 well over
a limited area of the North-Eastern lobe.
The Kujung II reservoirs are cut by faults and fractures related to the
underlying basement topography that increases original matrix permeability
and improves flow into existing producing wells.
Above the Kujung II unit lies the Kujung I unit, which is a massive,
fractured, shallow marine limestone deposit at a depth of approximately
2,700 feet. It conformably overlies the Kujung II carbonates, and is gas
bearing, although the only production from this unit is gas for use in
gas-lifting wells completed on the Kujung II.
The producing mechanism for the field is a mixture of simple depletion and
natural water influx. However, the natural water drive is not particularly
strong, and reservoir pressures have dropped below the bubble point of the
oil, leading to increased gas-oil ratios. Nevertheless, water is able to
enter the wells via the fracture network, resulting in high producing
water cuts in many of the wells. No secondary recovery projects have been
implemented in the Camar field, and no fluids are injected into the
reservoir.
Camar oil is sweet, with an gravity of around 38(degree) API, and an
initial solution gas-oil ratio of approximately 550 scf/bbl.
The field producing infrastructure consists of three fixed structures,
plus a floating storage vessel named the Fortuna Ayu. A central
processing platform is located on the southern lobe of the field, and
this platform processes all the field production and pipes the stabilized
oil to the floating storage unit. The platform is unmanned; all
production operations are controlled from the Fortuna Ayu.
Two further structures are located in the northern lobe of the field,
these being a wellhead production platform which is host to three
production wells, and a monopod tower which is host to an additional two
wells. Produced fluids from these two platforms are sent to the central
processing platform via a 6" pipeline.
Produced gas in excess of fuel requirements is flared.
Camar is operated under a production sharing contract, which for this
field has relatively straight-forward terms. There is no royalty,
although there is a "First Tranche Provision" (FTP) which is a percentage
of the gross production revenue that is shared directly with the
government, before any cost recovery or profit oil is taken. The FTP is
20 percent of the gross production revenue, and the contractor group is
entitled to a 45.45 percent share of it. Allowable costs are recovered
from the remaining 80 percent of the gross production, with any unused
cost oil being shared with the government in the same proportions as the
FTP.
Because the field has historically not performed as well as the operator
had predicted, there is a large un-recovered cost pool still associated
with the Camar field, and consequently all the permitted cost oil
allowance will revert to the contractor group. Indo-Pacific Resources
(Java) Ltd therefore retains 89.09 percent of the proceeds of the crude
sales. Sales are normally made to Pertamina for US dollars at the
prevailing Indonesian crude price, which tends to approximate the price
received for West Texas Intermediate.
Reserves for the Camar field have been estimated using extrapolations of
existing performance trends, and the predicted profile has been truncated
in the month when the gross revenue is exceeded by the field operating
costs. The oil price used in the economic limit calculation is the
average WTI price for the week in which the 31st December falls, and the
fixed and variable operating costs have been estimated from copies of the
financial reports submitted by Indo-Pacific Resources (Java) Ltd. to the
Indonesian authorities.
There are no further development activities or production enhancement
projects in the future budgets which can be expected to arrest the
decline trends observed in the historical production data, or result in
any future reserve additions. If the field was shut-in prior to the
year-end, it has been assumed that production would re-commence at the
beginning of the new year.
As of the 31st December 2004, the ultimate recovery and remaining
reserves for the Camar field are estimated to be as follows:
Gross Net
Cumulative Annual Average Cumulative Annual Average
Year Production Production Rate Production Production Rate
mmbbls mmbbls bbls/d mmbbls mmbbls bbls/d
31-Dec-04 10.101 8.999
31-Dec-05 10.219 0.118 323 9.104 0.105 287
31-Dec-06 10.291 0.072 198 9.168 0.064 176
31-Dec-07 10.335 0.044 121 9.208 0.039 107
31-Dec-08 10.338 0.003 8 9.210 0.003 7
31-Dec-09 10.338 0.000 0 9.210 0.000 0
Reserves at 31-Dec-04 0.237 mmbbls 0.211 mmbbls net
This evaluation has been supervised by Mr. J. R. Thompson, Head of
Reserves Evaluations for PGS Reservoir Limited. Mr. Thompson has 31 years
of varied petroleum and reservoir engineering experience. He has an MA in
Natural Sciences, and is a Chartered Engineer. Other PGS employees
involved in this work hold at least a bachelor degree (or its equivalent)
in geology, geophysics, petroleum engineering or a related subject and
have at least five years' relevant experience in the practice of geology,
geophysics or petroleum engineering.
Basis of Opinion
The evaluation presented in this letter reflects our informed judgements
based on accepted standards of professional investigation, but is subject
to generally recognised uncertainties associated with the interpretation
of geological, geophysical and engineering data. The valuation has been
conducted within our understanding of the effects of petroleum
legislation, taxation, and other regulations that currently apply to the
Camar Field. However, PGS is not in a position to attest to property
title, financial interest relationships or encumbrances related to these
properties.
It should be understood that any evaluation of hydrocarbon resources, is
subject to government policies and market conditions prevailing at the
time of the evaluation. Future changes can cause the total quantities of
petroleum recovered to vary from those endorsed in this letter.
Yours faithfully
PGS Reservoir Limited.
Jeremy R. Thompson M.A., C.Eng., M.I.M.M.
Head of Reserves Evaluations
Appendix 1: Definitions & Glossary
1) The following reserves definitions are used in this letter. These are
extracted from Rule 4-10(a) of Regulation S-X of the Securities Exchange act of
1934:
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions i.e. prices and
costs as of the data the estimate is made. Prices include consideration of
changes in existing prices provided only be contractual arrangements, but no on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a
reservoir considered proved includes (a) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if any, and (b)
the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
'proved' classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following : (a) oil that
may become available from known reservoirs but is classified separately as
'indicated additional reserves', (b) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable doubt because
of uncertainty as to geology, reservoir characteristics, or economic
factors; (c) crude oil, natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (d) crude oil, natural gas, and natural
gas liquids that may be recovered from oil shales, coal, gilsonite and
other such sources.
Proved Developed Oil and Gas Reserves
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Proved Undeveloped Reserves
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing well where a
relatively major expenditure is required for re-completion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.