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RPS Reserves Certification Report
UCV02179 1 March 2012
RESERVES CERTIFICATION REPORT
Songkhla A Field Bau Ban North Field – Songkhla D and E
Songkhla H Discovery G5/43 Concession Economic Evaluation
Songkhla Basin, Thailand
As of January 1, 2012
Prepared For: Coastal Energy Company
March 2012
RPS Report Number: UCV 02179
411 North Sam Houston Parkway E., Suite 400, Houston, Texas 77060-3545 T +1 281 448 6188 F +1 281 448 6189
E [email protected] W www.rpsgroup.com
RPS Reserves Certification Report
RESERVES CERTIFICATION REPORT
Songkhla A Field Bau Ban North Field – Songkhla D and E
Songkhla H Discovery G5/43 Concession Economic Evaluation
Songkhla Basin, Thailand
As of January 1, 2012
Prepared for Coastal Energy Company
DISCLAIMER The opinions and interpretations presented in this report represent our best technical interpretation of the data made available to us. However, due to the uncertainty inherent in the estimation of all sub-surface parameters, we cannot and do not guarantee the accuracy or correctness of any interpretation and we shall not, except in the case of gross or wilful negligence on our part, be liable or responsible for any loss, cost damages or expenses incurred or sustained by anyone resulting from any interpretation made by any of our officers, agents or employees.
Except for the provision of professional services on a fee basis, RPS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report.
COPYRIGHT © RPS
The material presented in this report is confidential. This report has been prepared for the exclusive use of Coastal Energy and the report nor its contents shall not be distributed or made available to any other company or person
without the knowledge and written consent of RPS.
REPORT NUMBER: UCV 02179
REPORT TITLE: Reserves Certification Report
DATE March 27, 2012 PROJECT REFERENCE: UCV 02179
PREPARED: CHECKED: APPROVED:
NAME Jim Haag, P.E. Andy Kirchin David Guise, P. Eng.
SENT EDITION DESCRIPTION COMMENT
March 27, 2012
Final
FILE LOCATION: U:/Coastal Energy/YE2011 Houston Report/Final Report
UCV02179 2 March 2012
RPS Reserves Certification Report
UCV02179 3 March 2012
Table of Contents
1.0 EXECUTIVE SUMMARY .................................................................................................... 5
2.0 FIELD OVERVIEW ............................................................................................................. 8
2.1 COMPANY OWNERSHIP AND LOCATION .............................................................................. 8 2.2 EXPLORATION AND APPRAISAL HISTORY ........................................................................... 8 2.3 DEVELOPMENT HISTORY ................................................................................................... 9
3.0 GEOSCIENCE .................................................................................................................. 10
3.1 GEOPHYSICS .................................................................................................................. 10 3.2 GEOLOGY ....................................................................................................................... 10 3.3 PETROPHYSICS .............................................................................................................. 11
4.0 PRODUCTION ANALYSIS ............................................................................................... 14
4.1 SONGKHLA A FIELD ........................................................................................................ 14 4.2 BUA BAN FIELD – SONGKHLA C ....................................................................................... 14 4.3 BAU BAN NORTH FIELD, SONGKHLA D AND E AREAS ....................................................... 15 4.4 SONGKHLA H DISCOVERY ............................................................................................... 16
5.0 RESERVES DETERMINATION ........................................................................................ 17
5.1 RESERVOIR CHARACTERIZATION ..................................................................................... 18 5.2 RECOVERY FACTOR ....................................................................................................... 18 5.3 RESERVOIR VOLUMES .................................................................................................... 18 5.4 STOIIP AND RECOVERABLE OIL VOLUMES ...................................................................... 19
6.0 RESERVES DISCUSSION ............................................................................................... 20
6.1 MIOCENE RESERVOIRS ................................................................................................... 20 6.1.1 SONGKHLA A FIELD ........................................................................................................ 20 6.1.2 BAU BAN NORTH FIELD, D AREA ..................................................................................... 20 6.1.3 BAU BAN NORTH FIELD, E AREA ..................................................................................... 25 6.1.4 SONGKHLA H DISCOVERY ............................................................................................... 31 6.2 OLIGOCENE RESERVOIRS ............................................................................................... 31 6.2.1 SONGKHLA A FIELD ........................................................................................................ 31 6.2.2 BUA BAN NORTH FIELD, D AREA ..................................................................................... 32 6.2.3 BUA BAN NORTH FIELD, E AREA ..................................................................................... 32 6.2.4 SONGKHLA H DISCOVERY ............................................................................................... 35
7.0 ECONOMIC EVALUATION .............................................................................................. 36
7.1 ANALYSIS PARAMETERS ................................................................................................. 36 7.2 COASTAL ECONOMIC MODEL .......................................................................................... 37 7.3 ASSESSED VALUE ........................................................................................................... 38
8.0 QUALIFICATIONS AND LIMITATIONS ........................................................................... 40
8.1 INDEPENDENCE AND CONFLICT OF INTEREST ................................................................... 40 8.2 PURPOSE, SCOPE AND USE OF THIS REPORT .................................................................. 40 8.3 AVAILABLE DATA ............................................................................................................ 40 8.4 PROFESSIONAL QUALIFICATIONS ..................................................................................... 40 8.5 RESERVES ESTIMATES ................................................................................................... 40 8.6 CONCLUSIONS ................................................................................................................ 41 8.7 FIELD VISIT AND INSPECTION .......................................................................................... 41 8.8 LIABILITY WAIVER ........................................................................................................... 41
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List of Figures Figure 2.1 Property Location Map Figure 2.2 Concession and Basin Areas Figure 3.1 Type Log – Well E-6 M100 / M200 / M300 Sands Figure 3.2 Type Log – Well E-6 M400 / M500 Sands Figure 3.3 Type Log – Well E-1 Upper Oligocene Sand Figure 3.4 Type Log – Well E-1 Lower Oligocene / Oligocene Sandstone / Eocene Sands Figure 3.5 3D Arbitrary SW-NE Line – E Area Figure 3.6 Type Log – Well H-1 Lower Oligocene Sand Figure 3.7 Miocene and Oligocene Reservoirs – Porosity vs. Permeability Plots Figure 3.8 Petrophysical Evaluation – M100 Sand – D Area – Eastern and Southern Fault Blocks Figure 4.1 Bua Ban Field – Well C-11 Performance – Miocene Sand Figure 4.2 Bua Ban North Field – E Area Production Figure 4.3 Bua Ban North Field – Well E-1 Production – Lower Oligocene Sand Figure 4.4 Bua Ban North Field – Well E-2 Production – M100 and M200 Sands Figure 4.5 Bua Ban North Field – Well E-3 Production – M100 Sand Figure 4.6 Bua Ban North Field – Well E-4 Production – M100 Sand Figure 4.7 Bua Ban North Field – Well E-5 Production – M100, M200, M300 and M500 Sands Figure 4.8 Bua Ban North Field – Well E-6 Production – M100 Sand Figure 4.9 Bua Ban North Field – Well E-8 Performance – M100 Sand Figure 4.10 Bua Ban North Field – Well E-7 Water Injection – M100 Sand Figure 6.1 Bua Ban North Field – D Area Wells - MDT Plot Figure 6.2 Bua Ban North Field – E Area Wells - MDT Plot Figure 6.3 H Discovery - MDT Plot Figure 7.1 G5/43 Concession Development Plan
List of Tables Table 3.1 Bua Ban North Field - D Area - Well Tops and Net Pay Data Table 3.2 Bua Ban North Field - E Area - Well Tops and Net Pay Data Table 3.3 H Discovery – Well Tops and Net Pay Data Table 4.1 Production Well Tests – Songkhla A, D and E Areas Table 5.1 Bua Ban North Field – D Area Wells - Rock and Fluid Properties Table 5.2 Bua Ban North Field – D Area Wells - Recovery Factor Calculations Table 5.3 Bua Ban North Field – D Area Wells - Reservoir Volume and Estimated Ultimate Recovery Calculations Table 5.4 Bua Ban North Field – E Area Wells - Rock and Fluid Properties Table 5.5 Bua Ban North Field – E Area Wells - Recovery Factor Calculations Table 5.6 Bua Ban North Field – E Area Wells - Reservoir Volume and Estimated Ultimate Recovery Calculations Table 5.7 H Discovery - Rock and Fluid Properties Table 5.8 H Discovery - Recovery Factor Calculations Table 5.9 H Discovery - Reservoir Volume and Estimated Ultimate Recovery Calculations Table 7.1 A Area – Production, Operating Expense and Capital Investment Forecasts Table 7.2 C Area – Production, Operating Expense and Capital Investment Forecasts Table 7.3 D and E Areas – Production, Operating Expense and Capital Investment Forecasts Table 7.4 H Discovery – Production, Operating Expense and Capital Investment Forecasts
List of Appendices Appendix 1 – Petroleum Resource Management System Guidelines Appendix 2 – Glossary of Terms and Abbreviations Appendix 3 – G5/43 Concession – BT Cash Flow Analysis by Reserves Category Appendix 4 – G5/43 Concession – AT Cash Flow Analysis by Reserves Category
RPS Reserves Certification Report
UCV02179 5 March 2012
1.0 EXECUTIVE SUMMARY
RPS was engaged on December 13, 2011 by Coastal Energy Company (Coastal) to issue this Reserves
Certification Report on the Songkhla A Field, the Bau Ban North Field (Songkhla D and E), and the
Songkhla H discovery in the Songkhla Basin, offshore Thailand. The technical analyses performed by
Coastal to date were audited according to Canadian National Instrument NI-51-101 and the Canadian Oil
and Gas Evaluation Handbook. After conducting the audit RPS performed supplemental analysis to
independently review the seismic data, study the PETRELTM static and NEXUSTM dynamic models,
evaluate rock and fluid properties, estimate the stock tank oil initially in place (STOIIP) and determine the
associated oil recovery by reservoir. The development plans provided by Coastal include infill drilling,
pressure maintenance by water injection, new pipelines and the Songkhla H discovery production
facilities. Economic analyses including the above fields in addition to the Bau Ban Field (Songkhla C)
were then performed to generate cash flow forecasts and net present values for the G5/43 concession by
field area, reserves category and reserves class.
The data provided by Coastal was the sole source of information for this report. The Reserves estimates
in this report were determined using standard petroleum engineering techniques and are compliant with
Canadian National Instrument NI-51-101 and the Canadian Oil and Gas Evaluation Handbook. The March
2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) guidelines which were
published by the Society of Petroleum Engineers in 2007 were also referenced (excerpt provided as
Appendix 1). A glossary of terms and abbreviations is provided as Appendix 2.
The Songkhla A field was developed beginning in 2008 by Coastal and has twelve wells at this time. The
last four wells drilled in 2010 extended the productive area to the east of the Main fault block in the
Oligocene and Eocene formations. Four additional wells are planned to be drilled in the field during 2012
to increase recovery from two producing fault blocks and to test the NE fault block that holds significant
Prospective Resources.
During May 2011, oil Reserves as well as additional Resources were discovered in the Bua Ban North
field (Songkhla D and E areas) in Tertiary age Miocene, Oligocene and Eocene sandstones that range in
depth from – 2,885 ft to -7,750 ft (TVD SS). The 3D seismic data and well log analysis is the basis for
reservoir definition. For evaluation purposes the horizons are split into the Western, Central and Eastern
fault blocks. The sand development varies greatly within well defined sand packages. Several MDT tests
have been conducted on potential completion zones, with results indicating the oil accumulation is in
communication between several fault blocks and generally from north to south across the Bua Ban North
field area. For this reason, the evaluation of the D and E areas are combined into a single analysis.
A successful drilling campaign has identified oil bearing reservoirs in several formations. Eleven wells
have been drilled in both the D and the E areas to year-end 2011. Each well was drilled from one of the
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two centrally located platform templates directionally to selected targets. The D-2 well did not encounter
sufficient pay thickness to be commercial and the D-9 well had mechanical problems; the D-2 well will be
converted to a water injection well and the D-9 well has been temporarily abandoned pending a possible
sidetrack operation. The E-7 well penetrated an oil water contact and was completed as a water injection
well. Each of the other 19 wells has utility and is either producing or will be completed as a producing
well. The D and E area producing facilities were installed in water depths of 59 ft and 67 ft, respectively.
Production was initiated from the E facility on July 22, 2011 from well E-6. Production was initiated from
the D facility on December 24, 2011 from well D-10. Production history from both facilities has supported
the current Reserves volumes which are still based on volumetric calculations.
The Songkhla H discovery development will produce from a single Lower Oligocene age sandstone
reservoir that was discovered in July 2011 in well H-1. The development is planned to include two or three
producing wells with one water injection well and is scheduled for initial production in July 2013. The 1P
(Proved Reserves) case is not profitable on a stand-alone basis, but is noted in this report because the
project will be undertaken by Coastal as the royalty and tax regime for the concession combines the
production from all the platforms into a single economic analysis.
The following table presents a summary of Coastal’s estimated net recoverable oil Reserves and the
associated net present value (@ 10% discount rate) for the G5/43 concession. Although the royalty is
paid in cash, Coastal’s net Reserves are shown as a reduction to the working interest Reserves.
Reserves Classification Remaining Reserves Net Present Value @ 10%
Gross Net Before Tax After Tax
Mbbl Mbbl $MM $MM
PROVED
Developed Producing 25,115 22,910 1,140 886
Developed Shut In 17,171 15,627 864 297
Developed Non-Producing 467 427 23 6
Undeveloped 19,736 17,999 882 303
TOTAL PROVED 62,489 56,963 2,909 1,492
PROBABLE 17,453 15,805 506 176
TOTAL PROVED PLUS
PROBABLE
79,942 72,768 3,415 1,668
POSSIBLE 7,125 6,363 258 74
TOTAL PROVED PLUS
PROBABLE PLUS POSSIBLE
87,068 79,131 3,673 1,742
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Natural gas production is minor because the produced oil has a low GOR. The gas is consumed on the
platforms or flared. Because the oil is produced by pump, the gas production is not metered. There are
no gas sales and the quantity of anticipated gas production has not been calculated.
All reported depths in the report that reference a sand top or bottom in a well, or a lowest known oil or oil
water contact in a reservoir, are TVDSS (true vertical depth subsea) measurements.
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2.0 FIELD OVERVIEW
2.1 Company Ownership and Location
The Songkhla basin is located in offshore Thailand as shown on the location map, Figure 2.1. Productive
reservoirs are found in Tertiary age sandstones along the western margin of the Gulf of Thailand. Block
G5/43 was awarded on July 17, 2003 to NuCoastal (Thailand) Limited, a wholly owned subsidiary of
Coastal Energy Company (“Coastal”). Nearby basins and other concessions are indicated in Figure 2.2,
which shows the Nakhon and Ko Kra Basins to the north of the Songkhla Basin. Coastal owns a 100%
working interest in the block.
2.2 Exploration and Appraisal History
The Songkhla A field was discovered by Premier Oil Pacific Limited in 1988. Later, Coastal acquired the
concession and began development of the field in 2008. There have been several drilling campaigns in
the field since that have resulted in twelve wells drilled from a central facility area. The Oligocene
formation is the primary producing zone with the Eocene currently having a minor contribution to field
production. Additional locations are planned to improve recovery from two reservoirs that were discovered
with new wells that were drilled in 2010 and to test the NE fault block to the east.
Shallow Miocene oil sands were discovered in the Songkhla C-3 well (TD at 9,034 ft MD) on July 5, 2010
and the Songkhla C-11 well (TD at 5,943 ft MD) on September 27, 2010 to the south of the Bua Ban North
field and were completed as Miocene producers. Well C-3 has produced nearly 15,000 barrels of oil at
low rates since September 2010 from a small reservoir, while well C-11 has produced over 108,000
barrels of oil since October 2010 from a much larger reservoir at rates up to 400 bopd. The discovery of
Miocene production in the Songkhla C field gave encouragement that the formation would be productive in
the undrilled prospective area to the north which would become the Bua Ban North field.
The Miocene, Oligocene and Eocene sand discoveries were made in wells directionally drilled from the E
Rig location in 67 ft water depth and from the D Rig location in 59 ft water depth with a well KB of 96 ft.
Each of the wells logged pay sands; most of the pay sands were full to base and established lowest
known oil limits in the penetrated reservoirs. Down-dip limits in some reservoirs were established by oil
water contacts or the presence of limited productive sand thickness.
The Lower Oligocene sand discovery to be developed by the H facility was made in July 2011 by well
H-1. The H-1 well was sidetracked in August 2011 to a down-dip position in the reservoir in an attempt to
extend the oil water contact. The well penetrated the Oligocene sand package but only discovered a few
feet of scattered oil pay and no pay in the Lower Oligocene section. The well was abandoned and new
wells will be drilled up-dip where the sand is well developed to maximize reservoir sweep efficiency.
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2.3 Development History
The Songkhla A field has been developed in three phases. Wells A-1, A-3 and A-7 were drilled first and
were producing at year-end 2008. Next the A-2, A-4 and A-8 wells were drilled and placed on production
in October and November, 2009. These wells further delineated the Main Fault block and adjacent
reservoirs. In late 2010, the A-9, A-11 and A-12 ST wells were drilled which resulted in the discovery of
three new Oligocene reservoirs and one new Eocene reservoir to the east of established production.
These new wells were producing at the start of 2011. There was no drilling during 2011 while the rigs
under contract concentrated on the development and appraisal of the Bua Ban North field. A four well
drilling campaign for additional recovery from the Oligocene formation is planned for August and
September of 2012. The program is slated to include water injection wells into the reservoirs being
produced by A-9 and A-12 ST, an additional producing well in the A-12 ST reservoir, and a test well in the
NE reservoir which currently has a significant volume of Prospective Resources.
The Songkhla D area was developed by eleven wells, D-1 through D-11, that were drilled from February to
December, 2011 with total depths ranging from 3,750 ft to 8,553 ft MD. The Songkhla E area was
developed by eleven wells, E-1 through E-12 (no E-11), that were drilled from April to June, 2011 and in
December 2011, with total depths ranging from 4,320 ft to 7,870 ft MD. Future wells in the Bua Ban North
field are intended to improve sweep efficiency in the larger reservoirs to maximize oil recovery. The E
producing facility was set first and the existing eight wells were completed. Seven of the wells are
producing oil, and the E-7 well is a water injection well for pressure maintenance in the western fault block
of the M100 sand. The D facility was installed in November 2011, followed by the completion of nine
producing wells and one water disposal well. Initial production from the D facility at year end 2011 was
from the completions in the D-6 and D-10 wells. The Reserves associated with the remaining D wells are
classified as proved shut-in pending completion in 2012.
Development of the Songkhla H discovery is scheduled to begin in April 2013 with the drilling of two or
three producing wells and one water injection well. The producing facility is scheduled for installation in
June 2013, with first oil production following in July.
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3.0 GEOSCIENCE
3.1 Geophysics
Two surveys were shot in the Songkhla basin area, one on the west side and one on the east side. The
western 390 sq km was shot in 2006 by PGS Geophysical for the operator, Nucoastal Thailand. This
survey covers the Bua Ban North area. To the east, covering the producing Songkhla A field, 316 sq km
of seismic data was shot in 1989 by Premier Oil and the operator was Western Geophysical. Both
3D seismic datasets were processed by WesternGeco during 2009 and 2010 and are now merged into
one dataset.
RPS reviewed the 3D seismic data interpretation of the Bua Ban North field discovery by Coastal in the
offshore waters of Thailand. The audit was designed to verify the seismic interpretation, depth maps, and
net pay maps created from the interpretation in multiple sands across the project area.
The geophysical interpretation was verified by reviewing every 5th cross line and every 10th inline of the
seismic data for accuracy and continuity of horizon and fault interpretation. Net pay maps, synthetic ties,
directional control, and velocity control were reviewed for errors and accuracy. A geologic cross section
was created and a geologic interpretation was originated for the purpose of establishing a seismic map
datum. The interpretation incorporates several Miocene horizons; the M100, M200, M300, M400, and
M500. Overall the horizon interpretations are accurate and consistent between the Songkhla D and E
areas. The net pay maps were reviewed for accuracy and compared to interval isopach maps created
from the supplied depth map grids. Synthetics were generated for all wells except the D-7, D-8 and E-5.
In summary, the interpreted horizons are consistent and reasonable, the fault interpretation has an
acceptable margin of error at the various levels, and the velocity control while not correlated directly
between the wells and seismic, is continuous across the interpretation.
RPS also reviewed the seismic data in the vicinity of the Songkhla H discovery while in Coastal’s office.
The structure map matches regional geology. RPS placed the OWC at two depths on the map to create
the isopach maps that reflect the 1P and the 2P / 3P reserves cases.
3.2 Geology
Tertiary Miocene, Oligocene and Eocene fluvial/deltaic sands were deposited in the G5/43 concession
area as stacked and amalgamated sands with associated lacustrine silt, shale and fresh water limestone
deposits. This is shown in the type log of well E-6 in Figures 3.1 and 3.2 which show the M100 / M200 /
M300 and M400 / M500 sands, respectively, and in the type log of well E-1 showing the Upper Oligocene
and the Lower Oligocene / Oligocene Sandstone / Eocene sands, respectively, in Figures 3.3 and 3.4.
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Grabens in the Gulf of Thailand are the result of the collision of India with Central Asia that began in
Eocene time. Strike-slip faults with right-lateral movements resulted from movement of the area west of
the Gulf of Thailand to the north and west forming grabens and en-echelon normal faults, generally
trending north-south. Rifting also created tilted fault block half-grabens with anticlinal folds related to roll-
over into the faults. An arbitrary 3D seismic line (Figure 3.5) through the E platform area shows the typical
fault traps that occur in the fields. Traps for oil are generally 3-way closures against normal and antithetic
faults as shown on the depth structure maps.
Coastal had defined the interval tops from correlation of the D-1 through D-9 and E-1 through E-8 well
logs. A complete listing of tops and bases for the sands for each field with gross and net pay sand counts
are shown in Tables 3.1 and 3.2, respectively. These tops are also good 3D seismic reflectors. RPS
reviewed and audited the data and found it to be reasonable.
The Lower Oligocene sand that was discovered in the H-1 well is shown as a type log in Figure 3.6. The
listing of tops and bases for the sands logged in the H-1 well is shown in Table 3.3. The H-1 ST well data
shown in the table is for the thin pay sand that was logged in the Oligocene Sandstone.
The TVT net oil pay isopach maps were generated for all horizons using the appropriate depth structure
maps and the fluid contacts in each fault block. The mapped areas reflect 1P, 2P and 3P drainage areas
in each fault block. Mapping of the full potential used the spill point (lowest closing contour), MDT
calculated oil water contact or a lowest known oil (LKO) plus 2 gross sand thicknesses.
3.3 Petrophysics
Data, Parameters and Models
The Miocene and Oligocene sands in the fields contain fresh connate water having a salinity of
approximately 3,000 ppm. The Eocene sand has a higher salinity, estimated to be 13,000 ppm, based on
production data from offset fields. The oil pay intervals generally exceed 20 ohms resistivity. The
petrophysical evaluation to determine net pay sand was based on the following:
Sw was calculated using the Archie equation for relatively clean sands.
Rw ranged from 1.15 ohms in the Upper Miocene to 0.30 ohms in the Eocene.
An m (cementation factor) of 1.65 to 1.70 was used.
An n (saturation exponent) of 1.90 to 2.00 was used.
A 10% porosity cutoff is matched to approximately 1 mD permeability for the sands on cross plots.
The typical net oil pay sand has a porosity that greatly exceeds 10% porosity. Porosity was
typically based on the Density and Neutron logs, on a rare occasion porosity depended on Density
log quality.
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The Sw and VCL cutoffs used were < 0.6 and < 0.4 respectively, and are reasonable for these
type sands. The VCL calculation was based on a gamma ray curve.
Reservoir and pay TVD thickness were calculated with a wellbore deviation correction to the MD
thickness. The reservoir thickness was calculated using the VCL and porosity cutoffs. Pay
thickness was calculated using the VCL, porosity and the Sw cutoffs.
RPS reviewed the petrophysical analysis and accepted the net oil pays, average effective porosities and
water saturations provided by Coastal as reasonable. The TVD net oil pays were used by RPS to
calculate TVT (true vertical thickness) thicknesses which were used to generate the isopach maps and the
volumetric calculations. TVT calculated net pays used log measured thickness pay corrected for the
wellbore deviation and formation bed dip and azimuth.
Porosity and Permeability
A limited core analysis was performed by Weatherford Laboratories in July 2011 on 22 samples that were
obtained from well E-6. The core analysis provided porosity and permeability values under both ambient
and overburden conditions for the Miocene (16 samples) and Oligocene (6 samples) reservoirs. Porosity
versus permeability plots were constructed for each reservoir type and are shown on Figure 3.7. Porosity
and permeability values for reservoir analysis were estimated from the Weatherford report, the plots, log
analysis and discussions with Coastal.
Water Saturation
It was noted previously that the water saturation cut off for pay sand was 60%. Recovery from reservoirs
having 55% to 60% water saturation is dependent upon having a high effective porosity and permeability.
The Miocene sand members that have this high water saturation and a low porosity may recover less oil
than calculated, despite encouraging DST flow test results.
M100 Sand – Oil Water Contact in D and E Platform Areas
Five of the wells that were drilled on the eastern and southern flank of the structure were reviewed to
determine the oil water contacts in the M100 interval. The wells are D-3, D-5 ST, D-7, E-2 and E-5. Each
well is discussed below with the key log section shown on Figure 3.8; all depths noted are TVD SS.
Well D-3 The M100 interval penetrated by this well is wet in an updip structural position. The gross section
between the Top at 3,630 ft and the Base at 3,788 ft is 158 ft. The average resistivity is about 10 Ohm-m
and no shows are described in the samples or the mud log. Above the clean sands the effective porosity
derived from Density-Neutron logs indicates values between 25% and 30%.
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Well D-5 ST Well D-5 ST, located approximately 1.3 miles to the north of D-7 in the same reservoir, penetrated the
complete section of the M100 interval and identified an OWC at 3,784 ft supported by the reduction in
resistivity from about 150 Ohm-m to 20 Ohm-m, and the MDT test run above and below the OWC. The
Density-Neutron derived effective porosity averages 35%.
Well D-7 The drilling of the D-7 well resulted in a partial penetration of the M100 interval from the Top at 3,680 ft to
last reading of the deep resistivity curve at 3,741 ft (LKO) for a total penetrated gross section of 61 ft. All
the sand in this interval was penetrated as oil bearing. The Density-Neutron derived effective porosity
ranges between 25% and 30%. Well D-5 ST, located in the same reservoir, identified an OWC at 3,784 ft
in the M100 interval. Assuming a common OWC at 3,784 ft, the section in well D-7 that was not
penetrated to the OWC would be 43 ft.
Well E-2 Well E-2 logged the Top of the M100 interval at 3,641 ft. The sands in the M100 interval in the well are oil
bearing down to the Base at 3,685 ft (LKO). The lower section of the interval is represented by a
characteristic shale neck that extends to the base of the interval at 3,724 ft. The Density-Neutron derived
effective porosity ranges between 25% and 30%.
Well E-5 Well E-5 logged the Top of the M100 interval at 3,725 ft. The sands in the interval are oil bearing down to
the base of the sand at 3,753 ft (LKO). The lower section of the M100 interval is represented by a
characteristic shale neck that extends to the base of the interval at 3,800 ft. The Density-Neutron derived
effective porosity ranges between 25% and 30%.
Based on the well log and MDT analysis, the OWC in the M100 sand in the D area is estimated to be at
3,784 ft and in the E area is estimated to be at 3,810 ft. Production performance from wells E-3 and E-8
will help in better determining the original OWC downdip of these wells. Due to the different fluid contacts
and sand development across the structure, there is a basis to believe that there is a sand discontinuity
between the D and E areas.
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4.0 PRODUCTION ANALYSIS
4.1 Songkhla A Field
The Songkhla A field currently has eight wells that are producing with submersible pumps, each of which
has at least one year of production history. The well tests that total 4,316 bopd and 13,812 bwpd on
December 31, 2011 are shown on Table 4.1. Most of the wells have established oil and water production
trends that were used to forecast future production and determine the reserves. The plots that were
reviewed were oil rate vs. time, oil rate vs. cumulative oil and water cut vs. cumulative oil. The wells
produce with a hyperbolic decline, and 2P reserves were assigned based on the most likely forecast. For
the four wells with less than 550 Mbbl Reserves, the 2P Reserves were assigned to the 1P and 3P cases.
For the four wells with over 950 Mbbl Reserves, the 1P and 3P Reserves were estimated based on the
use of different decline rates to provide a range of recovery.
The field has also been modeled using static and dynamic simulation models. During the first quarter of
2012, the models were reviewed and updated for reservoir data and well performance. The models
appear to provide a good match to field production and well pressures and to forecast production
consistent with expectations. The simulator is expected to be used for future Reserves updates once a
final review is completed in the near future.
4.2 Bua Ban Field – Songkhla C
Oil was first discovered in Miocene age sandstone in the Bau Ban field in July 2010. The C-3 well logged
the sand with 16 ft of net pay at 3,585 ft. Production was established from the well in August 2010 and to
date the well has recovered nearly 15,000 barrels of oil on pump. The well has not produced continuously
and is believed to be completed in a small reservoir.
Sustained higher rate Miocene oil production was established in the Bua Ban field on the Songkhla C field
in October, 2010 with the completion of the C-11 well. The well logged 36 ft of pay in two members of the
M100 reservoir; both of which were perforated. The well reached a peak rate of 451 bopd on October 6,
2010. After 8 months of varying producing rates, the well stabilized in June 2011 and experienced an
annual decline rate of 57% to 200 bopd until early November. At that time, daily volume unexpectedly
began to increase and reached 300 bopd at year end. Well C-11 has produced over 108,000 barrels of oil
while the water production has remained minimal since the initial completion at less than 10 bwpd. The
production history of the well (shown on Figure 4.1) has been erratic. The well is completed in a reservoir
that is believed to be a stratigraphic trap which has uncertain initial oil in place and ultimate recovery.
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UCV02179 15 March 2012
4.3 Bau Ban North Field, Songkhla D and E Areas
Production from the Bau Ban North field D area was initiated in December 2011. Each of the eleven wells
that have been drilled in the field (D-1 through D-11) is scheduled to be completed as a producing well,
except for the D-2 well that was converted to water injection to supplement reservoir pressure on the west
flank of the structure, and the D-9 well that was temporarily abandoned due to mechanical problems that
prevent a completion. Drilling programs in early 2012 and early 2013 are planned to fully develop the area
with infill producing wells and injection wells.
Two of the D field wells were completed in late December prior to the effective date of this report. The first
was well D-10, which is a horizontal well that was completed on December 24, 2011. At year-end, the well
was producing 2,609 bopd with no water. The D-6 well, which was slightly deviated, was completed next
and was producing 1,304 bopd with no water at year-end. The remaining seven wells on the D platform
were completed after December 31, 2011 and are also producing at the current time.
With the completion of the E-6 well, production from the Bau Ban North field E area commenced on July
22, 2011. By August 30, 2011, each of the seven producing wells (E-1, E-2, E-3, E-4, E-5, E-6 and
E-8) was completed. The historical oil production is shown on Figure 4.2, indicating that the seven wells
initially stabilized at a producing rate of approximately 8,000 bopd in the third week of August, 2011. The
field has experienced a gradual decline in rate and is now producing approximately 7,200 bopd. In
December, there were eight days of downtime due to process equipment shut-downs and drilling
operations that has accounted for the reduced rate. A production plot for each well is provided as Figures
4.3, 4.4, 4.5, 4.6, 4.7, 4.8 and 4.9.
The east flank of the structure is open to a large aquifer that should result in a strong water drive with high
recovery for the wells on that flank of the field. The west flank of the structure is bounded by a large north
to south regional fault, which will prevent the wells located on that side of the field from having an
equivalent degree of pressure support from water influx as is expected on the east flank. Well E-7 was
completed as a water injection well on the northwest flank of the M100 sand on September 1, 2011 to
provide pressure support and increase the recovery efficiency from the area. Water injection in the well is
into two thick members having 105 ft and 50 ft of gross sand, respectively, through perforation intervals
5,320 ft to 5,420 ft and 5,440 ft to 5,480 ft MD. The injected water is produced water from the
E area wells that has been filtered and treated, primarily water from wells E-5 and E-8. The injected
volume averaged approximately 6,000 bwpd at 820 psi wellhead pressure in the latter part of the year, and
then was increased to upwards of 14,000 bwpd at 1,400 psi in late December as shown on Figure 4.10.
The pressure support from well E-7 should benefit well completions E-2, E-4, E-6 and E-12 in the western
fault block of the M100 reservoir. Spare pump capacity on the platform is available to inject water into
additional wells in the future.
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The relatively short period of production performance has not identified any reservoir or mechanical
problems that were unanticipated that would threaten recovery of the estimated Reserves. The test
gauges for the wells that were producing on December 31, 2011 are noted in Table 4.1, showing a total of
11,206 bopd and 9,265 bwpd from the nine wells that had been completed in the D and E fields on that
date.
4.4 Songkhla H Discovery
The Songkhla H discovery development is scheduled to have first production in July 2013. Each well is
expected to average approximately 800 bopd during the first six months of production and produce into
year 2016. At that time the MOPU will have future utility and would be re-deployed to another location.
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UCV02179 17 March 2012
5.0 RESERVES DETERMINATION
The Reserves determination process for each of the producing areas reflects the length of time the area
has produced as well as the maturity of the field development.
Songkhla A
There are eight wells producing this field, each has PDP Reserves based on decline curve analysis (oil
rate vs. time, oil rate vs. cumulative oil and water cut vs. cumulative oil plots). The estimated ultimate
recovery and the remaining Reserves for each well were determined by viewing and comparing the plots.
Proved undeveloped Reserves were also assigned based on volumetric calculations to a drilling location
in the M-12ST reservoir to accelerate depletion and increase the sweep efficiency in the reservoir. Two
reservoirs, the M-09 and M-12ST, were also assigned Probable undeveloped reserves based on
volumetric calculations for two waterflood projects to be initiated later in 2012 when the water injection
wells are drilled. Flood response is not expected until 2013, and until response is observed no Proved
Reserves will be assigned.
The producing reservoirs and adjacent prospective reservoirs have been modeled using the PETRELTM
static and NEXUSTM dynamic models. The models were revised during the first quarter of 2012 and
appear to give a good match to reservoir conditions and performance and are expected to be used as the
primary basis of Reserves for the next update. Currently the model results are similar to the Reserves
obtained from decline curve analysis and volumetric calculations.
Songkhla D and E
The reserves for the wells in the Bua Ban North field area were determined using volumetric calculations.
Reservoir rock and fluid properties were taken from well data, structure maps were derived from 3D
seismic interpretations, and net pay isopach maps were then prepared. At year-end, the E area wells had
been producing for nearly six months and two D area wells had been producing for several days. As a
result, well performance was not considered a better method than the volumetric calculations to determine
the Reserves. At the time of the next Reserves update the performance analysis will play a bigger role in
Reserves determination.
Songkhla H
The Songkhla H discovery was made in July 2011 in the Oligocene Sand. The well was sidetracked
down-dip to locate the lower limit of the reservoir but did not find the interval as expected. Therefore, the
down-dip limit is still unknown although the MDT analysis gives a range of depths for the OWC between
the penetrations. These depths were used in volumetric calculations to determine the Reserves in the 1P,
2P and 3P classifications. The reservoir is scheduled to be developed by four wells (three producers and
one injector) to be drilled in up-dip positions to maximize recovery.
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UCV02179 18 March 2012
5.1 Reservoir Characterization
Rock and fluid properties for the reservoirs in the Bau Ban North field, D and E areas which are producing
or are expected to produce are summarized in Tables 5.1 and 5.4, respectively. Rock and fluid properties
for the Lower Oligocene reservoir in the Songkhla H discovery are summarized in Table 5.7. The porosity,
temperature, water saturations and formation pressure values were obtained from MDT test data, open
hole log analysis and petrophysical reports. The water salinity, gas and oil gravities and gas oil ratios
were obtained from production in the Bau Ban and Bau Ban North fields. The permeability was estimated
from porosity data, sand correlations and the Weatherford Lab report.
5.2 Recovery Factor
Recovery factor calculations are shown for the Bua Ban North field, D and E area reservoirs and the H
discovery reservoir in Tables 5.2, 5.5 and 5.8, respectively. The calculations were performed in two steps:
1) An estimate of the recovery using rock and fluid properties assuming 100% sweep in the reservoir, 2)
An application of sweep efficiency based on reservoir geometry (indicating the effectiveness of the water
drive or water injection) and the thickness of the reservoir relative to the reservoir area. Each of the
reservoirs is assumed to have water influx, the strength depending on the reservoir geometry, sand
continuity, and the fault placement bordering the reservoirs. Recovery factors were calculated for each
pay section in each well. The average recovery factor for the Miocene sands, which contain 98% of the
2P reserves potential, was estimated to be 30% by Coastal. The RPS analysis indicates an average
recovery factor from the Miocene reservoirs of 33.0%.
5.3 Reservoir Volumes
Tables 5.3, 5.6 and 5.9 identify the reservoir volumes assigned to each of the 1P, 2P and 3P
accumulations for the Bua Ban North field, D and E areas, and Songkhla H discovery, respectively. The
basis for the downdip limits include lowest known oil (LKO) depths and oil water contact (OWC) depths on
logs and MDT calculated oil water contacts. The assigned volumes and associated volume estimates
incorporate the estimated downdip limits and reservoir boundaries.
Production performance from the wells in the E field has supported the proved oil volumes which were
calculated down to the LKO contacts. There are no wells where the production to date has indicated that
the 2P volumes determined by volumetric calculations are unattainable. The production from each of the
two completions in the D field has been high rate with no water production, thus the calculated reserves
for these completions are supported to date. There is no production yet from the H discovery.
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5.4 STOIIP and Recoverable Oil Volumes
The estimated oil recovery for the Bua Ban North field, D and E areas, and Songkhla H discovery,
respectively, is shown in Tables 5.3, 5.6 and 5.9. The stock tank oil initially in place by reservoir and
Reserves class is noted per acre foot and in millions of barrels. Also shown is the reservoir recovery
factor and estimated recoverable oil in barrels per acre foot and in millions of barrels. Where production
history is available, performance analysis was also considered.
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6.0 RESERVES DISCUSSION
Each reservoir that has a well penetration and a completion or an expected commercial completion is
described in this chapter. For each of these reservoirs, RPS used either a PETRELTM model, or the
structure and net pay isopach maps and well data to determine the STOIIP and estimated recoverable
volumes of oil. Water contacts were taken from well logs and MDT analysis. MDT data is shown on
Figures 6.1, 6.2 and 6.3 for the D and E field wells and H-1 well, respectively, with well and sand intervals
identified with the associated estimated oil water contact.
6.1 Miocene Reservoirs
Reservoir rock and fluid properties are derived from well log evaluation, PVT calculations on a fluid sample
from the E-1 well, analysis of fluid samples from the E-6 well, and core analysis from the E-6 well. Two
gas oil ratios for Miocene reservoir oil have been estimated; 150:1 (from C-11 and D-1) and 257:1 (from
E-1) using surface fluid sample analysis and PVT calculations. Based on the history of the C-11 well and
the D-1 well PVT analysis, the value of 150:1 was chosen and used for all Miocene reservoirs in the
analysis. Production from the E area wells does not support the higher estimated GOR of 257:1.
6.1.1 Songkhla A Field
The Songkhla A field has no production from the Miocene formation to report.
6.1.2 Bau Ban North Field, D Area
Miocene 100 sand, Western (A) fault block (D-1, D-6, D-8, D-9, D-10 and D11 Wells)
The Miocene 100 sand in the southern area of the field was discovered in Well D-1. Oil was found in three
well developed sand members totaling 36 ft separated by thin shale breaks. The sand members were
each full to base with no water contacts. Wells D-6 and D-8 were then drilled, extending the reservoir to
the north while finding thicker pay sands that were also full to base with no oil water contacts. Well D-6
logged a 57 ft section with no shale breaks; well D-8 logged 55 ft with a single thin shale break. Well D-9
was then drilled north of the D-8 well to the area of the reservoir that lies midway between the platforms to
validate the geological model that indicated the sand was continuous between the two fields. The well
was successful and found 35 ft of pay in two well developed members with no oil water contact. MDT’s
taken in Wells D-1 and D-6 in the M100 reservoir indicated the OWC’s at depths of 3,850 ft and 3,825 ft,
respectively, which is consistent with being lower than the LKO depths seen in the four penetrations of the
reservoir to date. Finally, wells D-10 and D-11 were drilled in the crest of the reservoir giving the required
well density to fully evaluate the area and result in effective sweep efficiency. Well D-10 is a horizontal
well that was completed with well D-6 as the first completions on the D Platform in late December 2011.
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The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east and west by faults and is open to the
north. Water influx into the reservoir may be limited; a water injection well to support reservoir pressure is
being considered by Coastal. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 33.3%.
The 2P reserves analysis used the mapped reservoir volume of 36,447 ac-ft assuming an oil water contact
at 3,830 ft. The 1P evaluation retained the volume as determined in the 2P analysis, but due to the
varying stratigraphy in the expansive reservoir the net to gross (NTG) ratio was reduced by 10% to 0.752.
The 3P analysis also retained the 2P volume but increased the NTG ratio by 5% to 0.878. Table 5.3
contains the STOIIP and expected recovery calculations for the reservoir.
Miocene 100 sand, Western (B) fault block (D-4 Well)
A much smaller accumulation of the Miocene 100 sand in the southwest area of the field was discovered
in Well D-4. Oil was found in one well developed sand member having 12 ft of pay which was full to base
with no water contact. The well is located near the crest of the fault block and should effectively drain the
reservoir. No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the north and south by faults; the reservoir is
open to the east and should have water influx. Recovery factor calculations are shown on Table 5.2; after
the sweep efficiency of 75% is applied the estimated recovery factor is 20.5%. This recovery factor is one
of the lowest in the M100 sand reservoirs due to the estimated water saturation of 53.9%.
The 1P reserves analysis used the LKO at 3,657 ft to determine the mapped reservoir volume of
192 ac-ft. The 3P evaluation extended two gross reservoir thicknesses downdip to an estimated OWC at
3,681 ft, which due to the low reservoir dip angle captured 1,746 ac-ft in this case. The 2P analysis
averaged the 1P and 3P volumes. Table 5.3 contains the STOIIP and expected recovery calculations for
the reservoir.
Miocene 100 sand, Eastern fault block (D-5 ST & D-7 Wells)
The Miocene 100 sand in the field was discovered on the eastern flank in Well D-5 ST. Oil was found in
one well developed sand member totaling 33 ft of net pay having an OWC at 3,784 ft. Well D-7 was then
drilled, extending the reservoir to the south while finding a thicker pay section (D-7 penetrated 38 ft of
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UCV02179 22 March 2012
sand with another 10 ft projected above the OWC). MDT’s taken in both wells in the M100 reservoir
indicated an OWC at 3,800 ft. This depth is 16 ft deeper than the OWC noted in well D-5 ST, thus the
MDT depth was not used to estimate the downdip limit of the reservoir.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the west by a large fault and is open to the east
to a large aquifer that should give strong pressure support. There is a significant distance between Wells
D-5 ST and D-7 which would be expected to be oil bearing but will vary in stratigraphy. Recovery factor
calculations are shown on Table 5.2; after the sweep efficiency of 80% is applied the estimated recovery
factor is 37.5%.
The 2P and 3P reserves analysis used the mapped reservoir volume of 13,730 ac-ft having an OWC at
3,784 ft. The 1P evaluation assumed that the reservoir area to the west of the fault adjacent to the D-7
well is not productive. This resulted in a reduction of 30% to the 2P volume for a proved volume of 9,611
ac-ft. Table 5.3 contains the STOIIP and expected recovery calculations for the reservoir.
Miocene 200 sand, Central fault block (D-3 Well)
An accumulation of the Miocene 200 sand in the central graben area of the field was discovered in Well D-
3. Oil was found in one well developed sand member having 25 ft of pay which was full to base with no
water contact. The well is located in the crest of the fault block and should effectively drain the reservoir.
No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the
west and should have water influx. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 22.1%. This recovery factor is one of the
lowest in the M100 sand reservoirs due to the estimated water saturation of 50.9%.
The 1P reserves analysis used the LKO at 3,901 ft to determine the mapped reservoir volume of
443 ac-ft. The 3P evaluation extended two gross reservoir thicknesses downdip to an estimated OWC at
3,963 ft, which due to the low reservoir dip angle includes 3,434 ac-ft. The 2P analysis averaged the 1P
and 3P volumes. Table 5.3 contains the STOIIP and expected recovery calculations for the reservoir.
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UCV02179 23 March 2012
Miocene 400 Upper sand, Central fault block (D-3 Well)
An accumulation of the Miocene 400 Upper sand in the central graben area of the field was discovered in
Well D-3. Oil was found in one well developed sand member having 14 ft of pay which was full to base
with no water contact. The well is located in the crest of the fault block and should effectively drain the
reservoir. No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the
west and should have water influx. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 39.6%. This recovery factor is the highest in
the Miocene sand package due to the estimated water saturation of 29.3%.
The 1P reserves analysis used the LKO at 4,320 ft plus one gross sand thickness to determine the
mapped reservoir volume of 239 ac-ft. The 3P evaluation assumed the contact at 4,394 ft from the M400
Lower sand LKO in the D-3 well which gives a volume of 1,536 ac-ft. The 2P analysis averaged the 1P
and 3P volumes. Table 5.3 contains the STOIIP and expected recovery calculations for the reservoir. It
would be expected that the M400 Upper sand would be commingled with the M400 Lower sand upon
completion.
Miocene 400 Lower sand, Central fault block (D-3 Well)
An accumulation of the Miocene 400 Lower sand in the central graben area of the field was discovered in
Well D-3. Oil was found in one well developed sand member having 47 ft of pay which was full to base
with no water contact. The well is located in the crest of the fault block and should effectively drain the
reservoir. No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the
west and should have water influx. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 30.2%.
The 1P reserves analysis used the LKO at 4,394 ft to determine the mapped reservoir volume of 1,014 ac-
ft. The 2P analysis assumed one additional gross sand thickness to a depth of 4,446 ft for a volume of
3,569 ac-ft. The 3P evaluation assumed an additional 20% to the 2P case NTG ratio, keeping the volume
of 3,569 ac-ft. Table 5.3 contains the STOIIP and expected recovery calculations for the reservoir.
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UCV02179 24 March 2012
Miocene 500 Upper sand, Central fault block (D-3 Well)
An accumulation of the Miocene 500 Upper sand in the central graben area of the field was discovered in
Well D-3. Oil was found in four thin but well developed sand members having 28 ft of pay, each of which
was full to base with no water contact. The well is located in the crest of the fault block and should
effectively drain the reservoir. No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the
west and should have water influx. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 28.2%.
The 2P reserves analysis used the LKO of the lowest member at 4,684 ft to determine the mapped
reservoir volume of 922 ac-ft. The 1P evaluation assumed 75% of the 2P volume recognizing that the
OWC’s of the three higher members may not be as low as the 4th member. The 3P volume of 1,383 ac-ft
was estimated to be 150% of the 2P volume. Table 5.3 contains the STOIIP and expected recovery
calculations for the reservoir. It would be expected that the M500 Upper sand would be commingled with
the M500 Lower sand upon completion.
Miocene 500 Lower sand, Central fault block (D-3 Well)
An accumulation of the Miocene 500 Lower sand in the central graben area of the field was discovered in
Well D-3. Oil was found in two thin but well developed sand members having 11 ft of pay, each of which
was full to base with no water contact. The well is located in the crest of the fault block and should
effectively drain the reservoir. No MDT was taken in the well.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.1. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the
west and should have water influx. Recovery factor calculations are shown on Table 5.2; after the sweep
efficiency of 75% is applied the estimated recovery factor is 27.1%.
The 2P reserves analysis used the LKO of the lower member at 4,773 ft to determine the mapped
reservoir volume of 184 ac-ft. The 1P evaluation assumed 75% of the 2P volume recognizing that the
OWC’s of the higher member may not be as low as the 2nd member. The 3P volume of 276 ac-ft was
estimated to be 150% of the 2P volume. Table 5.3 contains the STOIIP and expected recovery
calculations for the reservoir.
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UCV02179 25 March 2012
6.1.3 Bau Ban North Field, E Area
Miocene 100 sand, Western fault block (E-2, E-4, E-6, E-7 & E-12 Wells)
The Miocene 100 sand on the west flank of the field was discovered in Well E-2. Oil was found in two well
developed sand members totaling 32 ft separated by a shale break. The sand members were each full to
base with no water contacts. Wells E-4 and E-6 were then drilled to the south and north, respectively,
extending the reservoir in both directions while finding thicker pay sands that were also full to base with no
oil water contacts. Well E-4 logged a 42 ft section with two members; well E-6 logged 68 ft in three well
developed members. Well E-7 was drilled north of the E-6 well with the expectation that it would bottom
out deeper than the OWC and be used for water injection. The well logged 3 ft of pay sand with a LKO at
3,789 ft. MDT’s taken in Wells E-2 and E-6 in the M100 reservoir indicated the OWC’s at depths of 3,850
ft and 3,810 ft, respectively, which is consistent with being lower than the LKO depths seen in the four
penetrations of the reservoir. At year end, the E-12 well was drilled and logged 82 ft of net pay sand, the
thickest area to date, between wells E-2 and E-6.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.4. The reservoir is mapped to be bounded on the east and west by faults and is open to the
south. Water influx into the reservoir may be limited; the E-7 well is a water injection well to support
reservoir pressure. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency of
80% is applied the estimated recovery factor is 34.7%.
The 2P reserves determination used the mapped reservoir volume of 21,867 ac-ft assuming an oil water
contact at the average MDT depth of 3,830 ft. The 1P reserves estimate assumed a 10% reduction to the
NTG ratio in the 2P area. The 3P reserves were calculated assuming a 5% increase to the NTG in the 2P
area. The variation in recovery was limited due to the high well density that provides adequate well control
in the reservoir. Table 5.6 contains the STOIIP and expected recovery calculations for the reservoir.
Currently wells E-2, E-4 and E-6 are producing the M100 reservoir. Fluid volume, pump frequency and
choke sizes are shown for each well on Figures 4.4, 4.6 and 4.8, respectively. Well E-2 is also
commingled with the M200 reservoir. The wells produce a total of approximately 3,500 bopd with only well
E-6 producing water at a 34% water cut. Cumulative production from the three wells to year-end 2011 is
436,000 barrels. It is too early to use the performance forecast for reserves analysis, but it is clear that
performance to date does not indicate that the assigned reserves are at risk.
Miocene 100 sand, Central (A) fault block (E-1, E-5 & E-9 Wells)
The Miocene 100 sand was discovered in the central graben of the field by Well E-1. Oil was found in thin
sand with 4 ft of pay. The sand was full to base with the possibility of a water contact. Well E-5 was then
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UCV02179 26 March 2012
drilled to the south and found 10 ft of pay sand in two members that were full to base with no oil water
contacts. An MDT taken in Well E-1 in the M100 reservoir indicated the OWC at a depth of 3,810 ft. The
MDT points from Well E-5 plot above the water gradient line and were deemed to not be indicative of the
OWC. Well E-9 was then drilled to the southern area of the reservoir and logged 49 ft of net pay.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and therefore accepted by RPS. Rock and fluid properties for the reservoir are noted
in Table 5.4. The reservoir is mapped to be bounded on the east and west by faults and is open to the
north and south, with water influx into the reservoir from the north. Recovery factor calculations are shown
on Table 5.5; after the sweep efficiency of 75% is applied the estimated recovery factor is 25.6%.
The 2P reserves analysis used the LKO and MDT from Well E-1 at 3,811 ft to determine the mapped
reservoir volume of 13,267 ac-ft. The 1P evaluation assumed a 15% reduction to the NTG ratio
recognizing that the sand development can vary in undrilled areas of the reservoir. The 3P analysis
assumed an increase of 10% in the NTG ratio for the same reason. Table 5.6 contains the STOIIP and
expected recovery calculations for the reservoir.
Currently, Well E-5 is producing the M100 reservoir. Fluid volume, pump frequency and choke sizes are
shown for the well on Figure 4.7. Well E-5 is also commingled with the M200, M300 and M500 reservoirs.
The well produces a total of approximately 1,430 bopd with significant water production at a 75% water
cut. The water is believed to be flowing from the deeper M300 zone. Cumulative production from the well
to year end 2011 is 246,000 barrels. It is too early to use the performance forecast for reserves analysis,
but performance to date does not indicate that the assigned reserves are at risk.
Miocene 100 sand, Central (B) fault block (E-10 Well)
The Miocene 100 sand Central fault block was split into two segments after well E-10 was drilled, which
proved the reserves accumulation to the east of the Central (A) fault block. Oil was found in three
members of thick sand having a total of 67 ft of pay. The sand was full to base with a LKO at 3,784 ft.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east and west by faults and is open to the north and
south, with water influx into the reservoir from the north. Recovery factor calculations are shown on Table
5.5; after the sweep efficiency of 75% is applied the estimated recovery factor is 33.5%.
The 2P reserves analysis used the downdip LKO in Well E-10 at 3,784 ft to determine the mapped
reservoir volume of 8,954 ac-ft. The 1P evaluation assumed a 15% reduction to the sweep efficiency
recognizing that the geometry of the reservoir could result in lower recovery than estimated. The 3P
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UCV02179 27 March 2012
analysis assumed the same volume as the 2P analysis. Table 5.6 contains the STOIIP and expected
recovery calculations for the reservoir.
Miocene 100 sand, Eastern fault block (E-3 & E-8 Wells)
The Miocene 100 sand was discovered on the eastern flank of the field by Well E-3. Oil was found in two
well developed members with 34 ft of pay separated by a large shale break. The sand was full to base at
3,723 ft with no water contact. Well E-8 was then drilled to the north and found 84 ft of pay sand in three
large members that were full to base at 3,788 ft with no oil water contacts. An MDT taken in Well E-8 in
the M100 reservoir indicated the OWC at a depth of 3,880 ft. MDT data was not taken in Well E-3
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the west by a large fault and is open to the east to a large
aquifer. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency of 80% is applied
the estimated recovery factor is 40.1%.
The 1P reserves analysis used the downdip LKO limit of 3,788 ft from Well E-8 to determine the mapped
reservoir volume of 13,392 ac-ft. The 2P and 3P volumes of 15,546 ac-ft used a downdip limit of 3,810 ft
based on the significant water production from the well that began within 2 months of completion. “Water
tongue” calculations performed by Coastal indicate with the fluid characteristics and flow rate of Well E-8
and the perforations at the base of sand, the water production is likely coming from the formation. Table
5.6 contains the STOIIP and expected recovery calculations for the reservoir.
Currently, Wells E-3 and E-8 are producing the M100 reservoir at a rate of approximately 1,940 bopd.
Fluid volume, pump frequency and choke sizes are shown for the wells on Figures 4.5 and 4.9,
respectively. Well E-3 in a higher structural position is producing approximately 1,525 bopd with limited
water; Well E-8 at a lower position is producing approximately 415 bopd and 3,460 bwpd. Cumulative
production from the wells to year end 2011 is 299,000 barrels. It is too early to use the performance
forecast for reserves analysis, but it is clear that performance to date does not indicate that the assigned
reserves are at risk.
Miocene 200 Upper sand, Western (A) fault block (E-2 Well)
An accumulation of the Miocene 200 Upper sand on the western flank of the field was discovered in Well
E-2. Oil was found in a thin well developed sand having 8 ft of pay that was full to base at 3,766 ft with no
water contact. The well is located in the crest of the fault block and should effectively drain the reservoir.
An MDT was taken in the well which indicated an OWC at 3,880 ft. In a down-dip position, Well E-6
logged the sand wet, giving a HKW of 3,853 ft.
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The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the west and
should have water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency
of 75% is applied the estimated recovery factor is 31.9%.
The 1P reserves analysis used the down-dip limit at 3,766 ft plus one sand thickness to 3,774 ft. The 3P
evaluation placed the OWC at the HKW of the E-6 well at 3,853 ft. The 2P volume was estimated to be
the average of the 1P and 3P volumes. Table 5.6 contains the STOIIP and expected recovery
calculations for the reservoir.
Currently, Well E-2 is producing the M200 Upper and Lower reservoirs (with the M100) at a rate of
approximately 785 bopd with limited water production. Fluid volume, pump frequency and choke sizes are
shown for the well on Figure 4.4. Cumulative production from the well to year end 2011 is 90,000 barrels.
It is too early to use the performance forecast for reserves analysis, but it is clear that performance to date
does not indicate that the assigned reserves are at risk.
Miocene 200 Lower sand, Western (A) fault block (E-2 Well)
An accumulation of the Miocene 200 Lower sand on the western flank of the field was discovered in Well
E-2. Oil was found in a well developed sand having 20 ft of pay that was full to base at 3,825 ft with no
water contact. The well is located in the crest of the fault block and should effectively drain the reservoir.
An MDT was taken in the well which indicated an OWC at 3,880 ft. In a down-dip position, Well E-6
logged wet pay at a HKW of 3,900 ft.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east by one fault; the reservoir is open to the west and
should have water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency
of 75% is applied the estimated recovery factor is 30.2%.
The 1P reserves analysis used the down-dip limit at 3,825 ft plus one sand thickness to 3,846 ft. The 3P
evaluation placed the OWC at the MDT OWC of the E-2 well at 3,880 ft. The 2P volume was estimated to
be the average of the 1P and 3P volumes. Table 5.6 contains the STOIIP and expected recovery
calculations for the reservoir.
Currently, Well E-2 is producing the M200 Upper and Lower reservoirs (with the M100) at a rate of
approximately 785 bopd with limited water production. Fluid volume, pump frequency and choke sizes are
shown for the well on Figure 4.4. Cumulative production from the well to year end 2011 is 90,000 barrels.
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It is too early to use the performance forecast for reserves analysis, but it is clear that performance to date
does not indicate that the assigned reserves are at risk.
Miocene 200 sand, Central fault block (E-5 Well)
A significant discovery in the Miocene 200 sand in the central graben of the field was made in Well E-5.
Oil was found in a large sand package having 103 ft of pay that was full to base at 3,991 ft with no water
contact. The well is located in the crest of the fault block and could effectively drain the reservoir, although
due to its volume infill drilling is expected. An MDT was taken in the top section which indicated an OWC
at 3,980 ft. An MDT taken in the bottom sand section indicated an OWC at 4,045 ft.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east and west by faults; the reservoir is open to the
north and south that should allow water influx. Recovery factor calculations are shown on Table 5.5; after
the sweep efficiency of 70% is applied the estimated recovery factor is 30.1%.
The 2P reserves analysis used the mapped reservoir volume of 39,606 ac-ft assuming an oil water contact
at 3,991 ft. The 1P evaluation reduced the 2P volume based on a 20% reduction to the NTG ratio due to
the varying stratigraphy in the expansive reservoir. The 3P analysis increased the 2P volume by applying
a 10% increase to the NTG ratio for the same reason. Table 5.6 contains the STOIIP and expected
recovery calculations for the reservoir.
Currently, Well E-5 is producing the M200 reservoir (with the M100, M300 and M500) at a rate of
approximately 1,430 bopd with a 75% water cut. It is believed that the water that is being produced from
the E-5 well is coming from the M300 reservoir based on the water contact in that sand. Fluid volume,
pump frequency and choke sizes are shown for the well on Figure 4.7. Cumulative production from the
well to year end 2011 is 246,000 barrels. It is too early to use the performance forecast for reserves
analysis, but it is clear that performance to date does not indicate that the assigned reserves are at risk.
Miocene 300 sand, Central (A) fault block (E-5 Well)
The Miocene 300 sand in the central graben of the field was discovered in Well E-5. Oil was found in two
members having 34 ft of pay with an OWC in the lower member at 4,088 ft. The well is located in a
downdip position in a small fault block. An MDT was taken in the well that confirmed the OWC at 4,088 ft.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east by a fault; the reservoir is open to the west that
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should allow water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency
of 70% is applied the estimated recovery factor is 29.5%.
The 1P, 2P and 3P reserves analysis used the mapped reservoir volume of 680 ac-ft with the OWC at
4,088 ft. Table 5.6 contains the STOIIP and expected recovery calculations for the reservoir.
Currently, Well E-5 is producing the M300 reservoir (with the M100, M200 and M500) at a rate of
approximately 1,430 bopd with a 75% water cut. It is believed that the water is being produced from the
M300 sand due to the proximity of the water contact in the lower member. Fluid volume, pump frequency
and choke sizes are shown for the well on Figure 4.7. Cumulative production from the well to year end
2011 is 246,000 barrels. It is too early to use the performance forecast for reserves analysis, but it is clear
that performance to date does not indicate that the assigned reserves are at risk.
Miocene 300 sand, Central (B) fault block (E-9 Well)
The Miocene 300 sand in the central graben of the field was discovered by Well E-5 with an OWC at 4,088
ft. Afterwards, well E-9 was drilled in what was thought to be the same fault block, but penetrated two well
developed oil bearing members having 29 ft of pay with a shallower OWC at 4,055 ft in the lower member.
Subsequent geological interpretation identified a fault that separates the two reservoirs.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.4. The reservoir is mapped to be bounded on the east by a fault; the reservoir is open to the west that
should allow water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency
of 75% is applied the estimated recovery factor is 34.4%.
The 1P, 2P and 3P reserves analysis used the mapped reservoir volume of 1,037 ac-ft with the OWC at
4,055 ft. Table 5.6 contains the STOIIP and expected recovery calculations for the reservoir.
Miocene 500 sand, Central fault block (E-1, E-4, E-5 & E-9 Wells)
The Miocene 500 sand in the central graben of the field was discovered in Well E-1. Oil was found in two
members having 12 ft of laminated pay with LKO at 4,688 ft. The well is located on the north side of a
large accumulation. Well E-4 was drilled on the south side of the structure and was wet with a HKW of
4,659 ft. Next, Well E-5 was drilled in a central position and found 28 ft of oil pay in two members
separated by a 30 ft shale break. Finally, well E-9 was drilled to the southern extremity of the reservoir
and logged a LKO at 4,655 ft. There were no MDT’s taken in these wells in the M500 sand.
The petrophysical analysis, structure maps and net pay values provided by Coastal were reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
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5.4. The reservoir is mapped to be bounded on the east by a fault; the reservoir is open to the west that
should allow water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency
of 75% is applied the estimated recovery factor is 33.1%.
The 2P reserves analysis used the mapped reservoir volume of 4,959 ac-ft with the OWC at 4,688 ft. The
discrepancy between the oil water contacts on the north and south flanks of the reservoir suggest that
additional faults or stratigraphic variation is present. The 1P evaluation assumed a 10% reduction to the
NTG ratio of the 2P case, and the 3P evaluation assumed a 5% increase to the NTG ratio. Table 5.6
contains the STOIIP and expected recovery calculations for the reservoir.
Currently, Well E-5 is producing the M500 reservoir (with the M100, M200 and M300) at a rate of
approximately 1,430 bopd with a 75% water cut. It is believed that the water is being produced from the
M300 sand due to the proximity of the OWC in that reservoir. Fluid volume, pump frequency and choke
sizes are shown for the well on Figure 4.7. Cumulative production from the well to year end 2011 is
246,000 barrels. It is too early to use the performance forecast for reserves analysis, but it is clear that
performance to date does not indicate that the assigned reserves are at risk.
6.1.4 Songkhla H Discovery
Miocene sandstones penetrated by the H-1 and H-1 ST wellbores were not productive, and because of
this no reserves have been assigned to this sand in the H area.
6.2 Oligocene Reservoirs
6.2.1 Songkhla A Field
Oligocene sand, M-01 fault block (A-1, A-3, A-4 and A-8 Wells)
These four wells were producing 3,675 bopd at year-end 2011 from the M-01 reservoir. This reservoir on
the western flank is the primary pay in the field which the discovery well penetrated. Each well produces
over a 75% water cut, but due to the low dip angle none of the wells are expected to water out soon and
should produce for many years. Each well had produced at a high oil rate upon initial completion followed
by a steep decline, but is now producing at a much lower decline rate with a relatively stabilized decline.
Oligocene sand, M-09 fault block (A-7 ST and A-9 Wells)
These two wells are producing from an interior reservoir that is up-dip of the M-01 fault block. The wells
were producing 620 bopd at year-end 2011 from the M-09 reservoir. Each well is producing with over a
60% water cut. The A-7 ST is also completed in the Eocene formation but this reservoir is not believed to
be contributing much to the daily production of 70 bopd. Well A-9 was completed in December 2010 and
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was producing 550 bopd at year-end. A water injection well is planned to be drilled into the reservoir in
2012 to supplement the water drive.
Oligocene sand, M-11 fault block (A-11 Well)
The A-11 well was drilled and completed in December 2010 and declined rapidly to 70 bopd at year-end
2011. The well is producing nearly water free at a rate that is less than expected based on the well
developed pay sand and long interval that was perforated. The well is located in the southern tip of a
large reservoir to the north that has no other well penetrations.
Oligocene sand, M-12 ST fault block (A-12 ST Well)
The A-12 ST well was drilled and completed in January 2011 and was producing 725 bopd at year-end
2011. The water cut has risen rapidly to over 60%, but given the up-dip position of the well in a large
reservoir the well is expected to have a long life. A second producing well and a water injection well are
planned to be drilled during 2012 into the down-dip area of the reservoir to improve drainage and
supplement the weak natural water influx.
6.2.2 Bua Ban North Field, D Area
Oligocene reservoirs were found to be prospective in the D field area, but none have been perforated.
Currently, Coastal has not indicated that the company plans to produce these reservoirs, which were small
and of low value relative to the shallower Miocene Reserves that were found in the wells to date. Thus, no
reserves were assigned to Oligocene sands in D area wells.
6.2.3 Bua Ban North Field, E Area
Upper Oligocene sand, “A” member, Central fault block (E-1 Well)
The Upper Oligocene sand in the E field area was discovered in Well E-1. Oil was found in two well
developed members (“A” and “B”) that were separated by a 40 ft shale break. The “A” member was full to
base with no water contact. Well E-1 is the only well penetration in the reservoir. The petrophysical
analysis furnished by Coastal that indicated an average porosity of 22.9% and water saturation of 52.6%
in the sand was reviewed and deemed reasonable and accepted by RPS. Rock and fluid properties for
the reservoir are noted in Table 5.4.
The reservoir is mapped to be bounded on all sides by faults, which would not allow water influx into the
reservoir. The water volume to oil volume ratio in the reservoir appears to be about 1:4, thus there will be
limited pressure support from water expansion. The structure maps and net pay values provided by
Coastal were reviewed and deemed reasonable and accepted by RPS. Recovery factor calculations are
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shown on Table 5.5, including the sweep efficiency of 70% which was applied to determine the estimated
recovery factor of 29.4% from this reservoir.
Well E-1 is situated in a down-dip position in the reservoir; another take point in an up-dip position would
be needed to effectively produce the attic area above the well. The 1P reservoir volume was calculated as
the volume to the LKO logged in well E-1 at 5,456 ft. Since most of the acreage in the fault block is oil
saturated above the LKO, only an additional 5% and 10% was added to the 1P reservoir volume for the 2P
and 3P cases. Table 5.6 contains calculations for the reservoir rock volumes and the oil in place and
recoverable volumes, respectively.
Upper Oligocene sand, “B” member, Central fault block (E-1 Well)
The Upper Oligocene sand in the field was discovered in Well E-1. Oil was found in two well developed
members (“A” and “B”) that were separated by a 40 ft shale break. The “B” member indicated an OWC at
5,509 ft. Well E-1 is the only well penetration in the reservoir. The petrophysical analysis furnished by
Coastal that indicated an average porosity of 22.9% and water saturation of 52.6% in the sand was
reviewed and deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are
noted in Table 5.4.
The reservoir is mapped to be bounded on all sides by faults, which would not allow water influx into the
reservoir. The water volume to oil volume ratio in the reservoir appears to be about 1:4, thus there will be
limited pressure support from water expansion. The structure maps and net pay values provided by
Coastal were reviewed and deemed reasonable and accepted by RPS. Recovery factor calculations are
shown on Table 5.5, including the sweep efficiency of 70% which was applied to determine the estimated
recovery factor of 29.4% from this reservoir.
Well E-1 is situated in a down-dip position in the reservoir; another off-take point in an up-dip position
would be needed to effectively produce the attic area above the well. The 1P, 2P and 3P reservoir
volumes are each calculated equally as the volume to the OWC logged in well E-1. Table 5.6 contains
calculations for the reservoir rock volumes and the oil in place and recoverable volumes, respectively.
Lower Oligocene sand, “SS A” member, Central fault block (E-1 Well)
The Lower Oligocene sand in the field was discovered in Well E-1. Oil was found in three thin sand-shale
laminated members separated by shale breaks. The sand members were each full to base with no water
contacts. Well E-1 is the only well penetration in the reservoir. The petrophysical analysis furnished by
Coastal that indicated an average porosity of 19.5% and water saturation of 58.8% in the sand was
reviewed and deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are
noted in Table 5.4.
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The reservoir is mapped to be bounded on two sides by faults and is open to an aquifer to the north which
would allow water influx into the reservoir. The structure maps and net pay values provided by Coastal
were deemed reasonable and accepted by RPS. Recovery factor calculations are shown on Table 5.5,
including the sweep efficiency of 80% which was applied to determine the estimated recovery factor of
38.0% from this reservoir.
Well E-1 is situated in a down-dip position in the reservoir; another off-take point in an up-dip position
would be needed to effectively produce the attic area above the well. The 1P reservoir volume was
calculated as the volume to the LKO logged in well E-1 at 6,683 ft. The 3P area was determined as the
reservoir area down to the MDT OWC of 6,880 ft. The 2P volume was assigned the average of the 1P
and 3P volumes. Table 5.6 contains calculations for the reservoir rock volumes and the oil in place and
recoverable volumes, respectively.
Currently, Well E-1 is producing the Lower Oligocene SS-A and SS-B members at a rate of approximately
415 bopd with no water production. Fluid volume, pump frequency and choke sizes are shown for the well
on Figure 4.3. Cumulative production from the well to year end 2011 is 65,000 barrels. It is too early to
use the performance forecast for reserves analysis, but it is clear that performance to date does not
indicate that the assigned reserves are at risk.
Lower Oligocene sand, “SS B” member, Central fault block (E-1 Well)
The Lower Oligocene sand in the field was discovered in Well E-1. Oil was found in one well developed
sand member that did not have a water contact. Well E-1 is the only well penetration in the reservoir. The
petrophysical analysis furnished by Coastal that indicated an average porosity of 19.5% and water
saturation of 58.8% in the sand was reviewed and deemed reasonable and accepted by RPS. Rock and
fluid properties for the reservoir are noted in Table 5.4.
The reservoir is mapped to be bounded on two sides by faults and is open to an aquifer to the north which
would allow water influx into the reservoir. The structure maps and net pay values provided by Coastal
were reviewed and deemed reasonable and accepted by RPS. Recovery factor calculations are shown on
Table 5.5, including the sweep efficiency of 80% which was applied to determine the estimated recovery
factor of 38.0% from this reservoir.
Well E-1 is situated in a down-dip position in the reservoir; another off-take point in an up-dip position
would be needed to effectively produce the attic area above the well. The 1P reservoir volume was
calculated as the volume to the LKO logged in well E-1 at 6,812 ft. The 3P area was determined as the
reservoir area down to the MDT OWC at 6,880 ft, and the 2P volume was assigned as the average of the
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1P and 3P volumes. Table 5.6 contains calculations for the reservoir rock volumes and the oil in place
and recoverable volumes, respectively.
Currently, Well E-1 is producing the Lower Oligocene SS-A and SS-B members at a rate of approximately
415 bopd with limited water production. Fluid volume, pump frequency and choke sizes are shown for the
well on Figure 4.3. Cumulative production from the well to year end 2011 is 65,000 barrels. It is too early
to use the performance forecast for reserves analysis, but it is clear that performance to date does not
indicate that the assigned reserves are at risk.
6.2.4 Songkhla H Discovery
The Lower Oligocene sand in the field was discovered in Well H-1 in a pay zone having no water contact.
Oil was also found in the shallower Upper Oligocene sand but was poorly developed and thin. The
reservoir was also penetrated by Well H-1 ST, but the well failed to extend the productive area down-dip
as the objective section had poor sand development. The petrophysical analysis furnished by Coastal that
indicated an average porosity of 21.0% and water saturation of 44.4% in the sand was reviewed and
deemed reasonable and accepted by RPS. Rock and fluid properties for the reservoir are noted in Table
5.7.
The reservoir is mapped to be bounded up-dip by a fault and is open to an aquifer to the east which would
allow water influx into the reservoir. The structure maps and net pay values provided by Coastal were
reviewed and deemed reasonable and accepted by RPS. Recovery factor calculations are shown on
Table 5.8, including the sweep efficiency of 80% which was applied to determine the estimated recovery
factor of 22.6% from this reservoir.
Well H-1 ST was situated in a down-dip position in the reservoir and was abandoned. Off-take points will
be drilled in up-dip positions to effectively produce the attic area above the discovery well. The 1P
reservoir volume was calculated as the volume to one gross sand thickness below the lowest known oil
(LKO) logged in well H-1 at 8,300 ft, which is 10 ft deeper than RPS’s interpretation of the MDT OWC
depth. The 2P and 3P area was determined as the reservoir area down to one additional sand thickness
at 8,340 ft, which is Coastal’s OWC based on MDT analysis. Table 5.9 contains calculations for the
reservoir rock volumes and the oil in place and recoverable volumes, respectively.
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7.0 ECONOMIC EVALUATION
7.1 Analysis Parameters
The input data for the economic analysis was guided by Coastal’s likely case development plans for the
properties with Reserves in the G5/43 concession. RPS used the plans as the basis for the drilling
programs in each field area and modified them as needed to forecast the 1P, 2P and 3P Reserves cases.
Both the Coastal and the RPS plans are shown in Figure 7.1. Considering the projected CAPEX,
operating costs and production that was in Coastal’s plans, the changes made by RPS were:
1. A small decrease in reserves (loss of technical volumes to economic limit tests),
2. The application of escalation to scheduled costs,
3. The identification of two additional water injection wells, and
4. The inclusion of abandonment costs.
The analysis of the A, C, D & E and H field areas was similar and was conducted as follows:
1. The technical Reserves were determined in each classification (1P, 2P and 3P) and category
(producing, non-producing, shut-in and undeveloped) using volumetric calculations, decline curve
analysis and dynamic reservoir models.
2. The technical Reserves were forecasted using the PHDWIN economic model by completion in
each Reserves classification and category.
3. The RPS price forecast (Dubai benchmark crude) adjusted for Thailand location tariff was input.
4. The operating costs and investments specific to each field were input with a 2% escalation rate.
5. The investments to purchase selected production facilities in 2012 are scheduled along with the
removal of the monthly lease payments on those facilities.
6. As the production levels drop from the peak years, the operating cost was reduced to reflect de-
manning of facilities, reduced producing well count, and other measures that operators take to
reduce operating costs when fields are in their sunset years.
7. The PHDWIN economic model was run by field to establish the economic limit for each producing
field with the associated year of depletion and loss of technical Reserves.
8. The commercial reserves and associated operating costs and investments were input from the
PHDWIN model output into Coastal’s economic model by field and Reserves classification and
category. (The input data by field area and Reserves classification are provided as Tables 7.1 to
7.4 for the Songkhla A, C, D & E and H field areas.)
9. Abandonment costs were scheduled in the year following the year in which the economic limit was
reached. Wells were assigned $500,000; facilities were assigned $1,500,000 for demobilization
and to be towed to other fields for re-use. Abandonment costs were escalated at 2% per year.
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10. Coastal’s model was run for each Reserves classification to determine the annual royalty and
income tax burden percentages.
11. The model was then re-run, holding the annual royalty and income tax burdens constant, to
determine the PV10% for each Reserves classification by Reserves category.
12. The model was then run for final analysis on a before and after tax basis, with discount rates of
0%, 5%, 10%, 15% and 20%. The results of these cash flow evaluations are shown in
Appendices 3 and 4 and comprise the input to the NI-51-101 reports.
The wells in the D and E areas are capable of producing at higher rates beginning in 2012 than the
forecast indicates. The producing rate is limited by facilities processing capacity and is estimated to hold
the daily oil production to a maximum of 15,000 bopd as indicated by Coastal’s analysis. The 1P, 2P and
3P production forecasts by RPS indicate that this curtailed rate will be maintained until 2017, 2018 and
2019, respectively, for each case. No other field developments in the G5/43 concession are expected to
experience curtailments to production.
The CAPEX costs include the drilling programs in 2012 and 2013 at an average cost of $4 million per well
for drilling and completion. The cost for flow lines from the C, D and E fields are included with $10 million
to be spent in each December 2012 and January 2013. The cost of $400,000 for a re-completion of well
E-1 to the Upper Oligocene sand was also scheduled in 2015 in the 1P case and in 2016 in the 2P and 3P
cases.
The operating cost for the producing facilities was provided by Coastal. The monthly operating costs for
the Songkhla A, C and D & E operations during 2012 were projected to be $2,485,000, $1,154,000 and
$2,699,000 per month, respectively, after facility acquisition. These monthly costs which exclude facility
lease charges are markedly less than the costs prior to purchase of the MOPU’s and FSO’s. The
producing facilities have the following acquisition schedule:
Songkhla A – MOPU was bought in February 2012, FSO scheduled to be bought in August 2012
Songkhla C – MOPU and FSO purchased in 2011
Songkhla D & E – MOPU’s scheduled to be bought in July and December 2012, FSO’s scheduled
to be bought in September and October 2012
Sonhkhla H – production facilities will be leased for life of project due to limited duration.
These investments were scheduled in the economic analysis.
7.2 Coastal Economic Model
The evaluation model that was used for this analysis was provided by Coastal. The model was audited by
RPS and found to properly reflect the terms associated with the G5/43 concession. Modifications were
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made to accommodate the various reserves classifications and field areas. Tax and royalty calculations
incorporate the contract terms, royalty obligations and country tax regulations.
Since Coastal owns 100% of the concession, the gross Reserves are equal to the working interest
Reserves. Although the royalty is paid in cash, the equivalent royalty volume in barrels is deducted from
the working interest Reserves to calculate the net Reserves of the company. For the payment of royalty,
the following royalty rates apply to the total value of the production from the concession:
Monthly Crude Oil Sales: Percent of Value:
1st level Not exceeding 60,000 barrels 5.00%
2nd level The portion exceeding 60,000 barrels but
not exceeding 150,000 barrels
6.25%
3rd level The portion exceeding 150,000 barrels but
not exceeding 300,000 barrels
10.00%
4th level The portion exceeding 300,000 barrels but
not exceeding 600,000 barrels
12.50%
5th level The portion exceeding 600,000 barrels 15.00%
The analysis is based on the RPS oil price forecast. The forecast benchmark is Dubai crude, with a
trading differential to production from Thailand (per Coastal) of -$1.70/bbl. The oil price forecast that was
used in the analysis is shown in the cash flow illustrations. The oil price declines in current terms through
2015, and then is followed by an increase in price afterwards.
7.3 Assessed Value
The analysis was performed using Coastal’s field development plans with the associated production,
operating cost and investment forecasts. Because the royalty and country income tax rates are based
upon the production from the entire concession, not by individual field, the projected performance of the
Songkhla A, C, D & E and H field areas are combined in this evaluation. The basis for the Songkhla C
field production forecast and cost schedules is the technical report1 dated March 29, 2012 that was
prepared by RPS – Singapore office. The before tax and after tax annual cash flow evaluations for
concession G5/43 are provided in Appendix 3 and 4, respectively. The table below contains a summary of
the results:
1 “Technical Update of Remaining Recoverable Hydrocarbons for the Songkhla C Field as of 1st January, 2012”
RPS Reserves Certification Report
UCV02179 39 March 2012
Reserves Classification Remaining Reserves Net Present Value @ 10%
Gross Net Before Tax After Tax
Mbbl Mbbl $MM $MM
PROVED
Developed Producing 25,115 22,910 1,140 886
Developed Shut In 17,171 15,627 864 297
Developed Non-Producing 467 427 23 6
Undeveloped 19,736 17,999 882 303
TOTAL PROVED 62,489 56,963 2,909 1,492
PROBABLE 17,453 15,805 506 176
TOTAL PROVED PLUS
PROBABLE
79,942 72,768 3,415 1,668
POSSIBLE 7,125 6,363 258 74
TOTAL PROVED PLUS
PROBABLE PLUS POSSIBLE
87,068 79,131 3,673 1,742
RPS Reserves Certification Report
UCV02179 40 March 2012
8.0 QUALIFICATIONS AND LIMITATIONS
8.1 Independence and Conflict of Interest
This report has been prepared by RPS Energy. RPS is an independent worldwide oil and gas advisory
firm with offices in Houston, Dallas, Calgary, Perth, Singapore and the United Kingdom. All evaluations
performed by RPS are strictly fee-based and RPS has not and will not receive any benefit which may be
regarded as affecting its ability to render an unbiased opinion on the petroleum interests held by Coastal.
8.2 Purpose, Scope and Use of This Report
This report was commissioned by Mr. Jerry Moon of Coastal Energy Company to assess the reserves and
value of the Bua Ban North field in the Songkhla Field, Thailand. The scope of the project was restricted
to this brief. This report was prepared exclusively for the internal use of Coastal and the report nor its
contents should not be duplicated or distributed to any third parties without the express written consent of
Coastal and RPS, except as required by law.
8.3 Available Data
This study was based on data supplied by Coastal. The data was reviewed for reasonableness from a
technical perspective. As is common in oil field situations, basic physical measurements taken over time
cannot be verified independently in retrospect. As such, beyond the application of normal professional
judgment, such data must be accepted as representative. While we are not aware of any falsification of
records or data pertinent to the results of this study, RPS does not warrant the accuracy of the data and
accepts no liability for any losses from actions based upon reliance on data, which is subsequently shown
to be falsified or erroneous.
8.4 Professional Qualifications
RPS personnel who prepared this report are degreed professionals with the appropriate qualifications and
experience to complete the project brief. RPS and its staff do not claim expertise in accounting, legal and
environmental matters, and opinions on such matters do not form part of this report.
8.5 Reserves Estimates
Reserves estimates were made using extrapolation of performance trends and other accepted engineering
methods as described within. The estimates were made in accordance with the 2007 oil and gas reserves
guidelines as published by the SPE. The reserves definitions allow for changes in category as information
RPS Reserves Certification Report
UCV02179 41 March 2012
is gathered and as producing history is accumulated. As such, the volume and class of reserves is
expected to change and be revised with time.
Net oil and gas reserves are those estimated quantities of crude oil, natural gas and natural gas liquids
attributed to the evaluated interests (after deduction of applicable royalties and overriding royalties) that
are considered to be economically recoverable under the conditions modeled. It is implicit that good oil
field practices are maintained in order to recover the estimated reserves.
8.6 Conclusions
RPS cannot attest to the validity or correctness of the ownership information provided by Coastal and such
an opinion does not form a part of this report. Cost parameters and operating cost data were supplied by
Coastal. This report is restricted to an independent engineering estimate of reserves and a production
forecast of those reserves. It is not the intention or purpose of this report to comment on title, ownership
or legal encumbrances, commercial or business relationships or sunk costs involved in acquiring the
properties.
8.7 Field Visit and Inspection
No field visit to the fields or properties which are the subject of this report has been made. As is
customary in this type of evaluation, a field visit was not considered necessary. As such, RPS is not in a
position to comment on the state of operations or that such operations are in compliance with any country
regulations that may apply to them.
8.8 Liability Waiver
This report has been prepared on a best efforts basis to address the requirement of the brief specified by
Coastal. The results and conclusions represent informed professional judgments based on the data
available and time frame allowed to perform this work. No warranty is implied or expressed that actual
results will conform to these estimates. RPS accepts no liability for actions or losses derived from reliance
on this report or the data on which it was based.
FIGURES
Figure 2.1Property Location Map
SONGKHLA FIELD
Source: International Petroleum Encyclopedia 2007
rpsgroup.com
Figure 2.2Concession and Basin Areas
rpsgroup.com
Figure 3.1/ / SType Log – Well E-6 M100/M200/M300 Sands
M100 Top at 3,641’
M100 Bottom at 3,778’
M200 Top at 3,825’
M200 Bottom at 4,058’
M300 Top at 4,082’
M300 Bottom at 4,240’
rpsgroup.com
Figure 3.2T L W ll E 6 M400/M500 S dType Log – Well E-6 M400/M500 Sands
M400 Top at 4,260’
M400 Bottom at 4,492’’
M500 Top at 4 808’M500 Top at 4,808
M500 Bottom at 5 120’
rpsgroup.com
M500 Bottom at 5,120
Figure 3.3T L W ll E 1 U Oli S dType Log – Well E-1 Upper Oligocene Sand
Upper Oligocene Top at 5,182’
rpsgroup.com
Upper Oligocene Bottom at 6,195’
Figure 3.4Type Log Well E 1 Lower OligoceneType Log – Well E-1 Lower Oligocene,
Oligocene Sandstone and Eocene SandsLower Oligocene Top at 6,210’
Lower Oligocene Bottom at 6,341’
Oligocene Sandstone Top at 6,533’
Oligocene Sandstone Bottom at 6,817’
Eocene Top at 7,163’
rpsgroup.com
Eocene Bottom at 7,853’(below log section)
Figure 3.53D A bit SW NE Li E A3D Arbitrary SW-NE Line – E Area
rpsgroup.com
Figure 3.6T L W ll H 1 L Oli S dType Log – Well H-1 Lower Oligocene Sand
Lower Oligocene Pay Top at 10,175 ft MD
Lower Oligocene Pay Bottom at 10,234 ft MD
rpsgroup.com
Figure 3.7 Miocene and Oligocene Reservoirsg
Porosity vs. Permeability Plots
Miocene Reservoirs Oligocene Reservoirs
10,000
Correlation line is based on the analysis of SWC from well E‐06 by Weatherford Laboratories, report dated 7/12/2011
10,000
Correlation line is based on the analysis of SWC from well E‐06 by Weatherford Laboratories, report dated 7/12/2011
1,000
lity ‐mD
100
1,000
bility ‐mD
100
Perm
eabi
10
100
Perm
eab
10 114 16 18 20 22 24 26 28
rpsgroup.com
16 18 20 22 24 26 28 30
Porosity ‐ %
14 16 18 20 22 24 26 28
Porosity ‐ %
Figure 3.8Petrophysical Evaluation – M100 Sand
D Area - Eastern and Southern Fault Blocks
D-7 Partial penetration of i t l LKO @ 3 741’ (l t
D-5 ST Complete penetration f th i t l OWC @
E-2 Sands in the i t l il
E-5 Sands in the i t l il b i
D-3 Interval is wet in the Central fault block
interval. LKO @ 3,741’ (last reading of the deep resistivity curve). All sands are oil bearing.
of the interval. OWC @ 3,784’, supported by resistivity curves and MDT.
interval are oil bearing down to the base at 3,685’ (LKO)
interval are oil bearing down to the base of the sands at 3,753’ (LKO)
rpsgroup.com
Figure 4.1
Bua Ban Field
Well C-11 Performance – Miocene Sand
rpsgroup.com
0
10
20
30
40
50
60
70
80
90
100
0
50
100
150
200
250
300
350
400
450
500
10/4/10 11/4/10 12/4/10 1/4/11 2/4/11 3/4/11 4/4/11 5/4/11 6/4/11 7/4/11 8/4/11 9/4/11 10/4/11 11/4/11 12/4/11
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd, W
ater
Pro
duct
ion -
bw
pd
Oil Production
Water Production
Pump Frequency
Choke Size
108.1 MBO thru
Dec 2011 @ 2% WC
rpsgroup.com
Figure 4.2
Bua Ban North Field
E Area Production
100
1,000
10,000
7/1/11 8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Oil
Pro
duct
ion -
bopd
Figure 4.3
Bua Ban North Field
Well E-1 Production – Lower Oligocene Sand
rpsgroup.com
0
20
40
60
80
100
120
140
160
180
0
100
200
300
400
500
600
700
800
900
8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pu
mp
Fre
qu
ency
-h
z, C
ho
ke S
ize
Oil
Pro
du
ctio
n -
bo
pd
Figure 4.3Songkhla E-1 Well Performance - Lower Oligocene Sand
Oil Production
Pump Frequency
Choke Size
Well E-1 is producing water free. Cumulative oil
production to YE 2011 is 65 MBBL.
Figure 4.4
Bua Ban North Field
Well E-2 Production – M100 and M200 Sands
rpsgroup.com
0
20
40
60
80
100
120
140
160
180
0
100
200
300
400
500
600
700
800
900
1000
8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd, W
ater
Pro
duct
ion -
bw
pd
Oil Production
Pump Frequency
Choke Size
Water Production
Well E-2 is producing with a 3% water cut. Cumulative
oil production to YE 2011 is 90 MBBL.
Figure 4.5
Bua Ban North Field
Well E-3 Production – M100 Sand
rpsgroup.com
0
20
40
60
80
100
120
140
160
180
200
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd
Oil Production
Water Production
Pump Frequency
Choke Size
Well E-3 is producing 17% water. Cumulative oil
production to YE 2011 is 196 MBBL.
Figure 4.6
Bua Ban North Field
Well E-4 Production - M100 Sand
rpsgroup.com
0
20
40
60
80
100
120
140
160
180
200
0
100
200
300
400
500
600
8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd
Oil Production
Pump Frequency
Choke Size
Well E-4 is producing water free. Cumulative oil
production to YE 2011 is 48 MBBL.
Figure 4.7
Bua Ban North Field
Well E-5 Production – M100, M200, M300 and M500 Sands
rpsgroup.com
0
20
40
60
80
100
120
140
160
180
200
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd, W
ater
Pro
duct
ion -
bw
pd
Oil Production
Water Production
Pump Frequency
Choke Size
Cumulative oil production to YE 2011 is 246 MBBL.
Well E-5 is producing at a 75% water cut.
Figure 4.8
Bua Ban North Field
Well E-6 Production – M100 Sand
rpsgroup.com
0
20
40
60
80
100
120
140
0
500
1,000
1,500
2,000
2,500
3,000
3,500
7/1/11 8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
-H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd, W
ater
Pro
duct
ion -
bw
pd
Oil Production
Water Production
Pump Frequency
Choke Size
Cumulative oil production at YE 2011 is 298 MBBL.
Well E-6 is producing with a 34% water cut.
rpsgroup.com
0
10
20
30
40
50
60
70
80
90
100
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
7/1/11 8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Pum
p F
requency
- H
z, C
hoke S
ize
Oil
Pro
duct
ion -
bopd, W
ater
Pro
duct
ion -
bw
pd
Oil Production
Water Production
Pump Frequency
Choke Size
Cumulative oil production at YE 2011 is 103 MBBL.
Well E-8 is producing with a 89% water cut.
Figure 4.9
Bua Ban North Field
Well E-8 Production – M100 Sand
rpsgroup.com
Figure 4.10
Bua Ban North Field
Well E-7 Water Injection – M100 Sand
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
9/1/11 10/1/11 11/1/11 12/1/11 1/1/12
Wat
er
Inje
ctio
n -
bw
pd, W
ellh
ead
Pre
ssure
- p
si
Water Injection - bwpd
Wellhead Pressure - psi
Pump pressure increased from 650 psi to
1400 psi December 23; injection rate
increased from 5,500 bwpd to 14,000 bwpd.
Figure 6.1 B B N th Fi ld D A W llBua Ban North Field – D Area Wells (MDT Plot edited by RPS)
D‐1 M100 OWC 3850’
D‐7 M100 OWC 3800’
D‐6 M100 OWC 3825’
MDT contact picks are based on MDT alone and are not
necessarily where RPS has placed the OWC in the reservoir.
D‐5 STM100 Water
D‐2 M100 WaterD‐6 M200 Water
D‐5 ST M100 OWC 3800’
D‐6 M200 Water
D 5 ST M100 WaterD‐5 ST M100 Water
rpsgroup.com
Figure 6.2 B B N th Fi ld E A W llBua Ban North Field – E Area Wells (MDT Plot edited by RPS)
E‐2 M100 OWC 3850’
E‐8 M100 OWC 3880’
E‐5 M100 OWC 3930’
E‐2 M200 OWC 3880’
E‐6 M100 OWC 3810’ MDT contact picks are based on MDT alone and are not
necessarilywhere RPShasplaced
E‐5 M200 OWC 3980’
E‐5 M200 OWC 4045’
E‐1 M100 Water
E‐1 M100 OWC 3810’
necessarily where RPS has placed the OWC in the reservoir.
E 5 M200 OWC 4045
E‐5 M300 OWC 4088’
E‐6 M200 Water
E‐2 M200 Water
E‐5 M300 Water
rpsgroup.com
Figure 6.3 H DiH Discovery (MDT Plot edited by RPS)
rpsgroup.com
Figure 7.1G5/43
Development Plan ScheduleCoastal Development Plans
2012
Jan‐12 Feb‐12 Mar‐12 Apr‐12 Dec‐12Jun‐12 Jul‐12 Aug‐12 Sep‐12 Oct‐12 Nov‐12 Jan‐13 Feb‐13May‐12 May‐13 Jun‐13
2013
Mar‐13 Apr‐13
SKL E11‐E14 4
SKL D12‐D16 5
SKL A * 3
SKL C 2
SKL D & E 10
SKL H 4
* Coastal's plan includes one additional well to be drilled to a reservoir that contains prospective resources
RPS Adjusted Development PlansRPS Adjusted Development Plans
1P Cases
D Area ‐ 5 wells 2 WI
E Area ‐ 9 wells 3 WI
A A 3 ll 1 P d 2 WI
Dec‐12 Jan‐13 Feb‐13Jul‐12 Aug‐12 Sep‐12 Oct‐12 Nov‐12Feb‐12 Mar‐12 Apr‐12 May‐12 Jun‐12
4 ProducersE‐11 & E‐14
D12, D13, D14
2012
Jan‐12
2013
May‐13 Jun‐13Mar‐13 Apr‐13
A Area ‐ 3 wells 1 Prod
C Area ‐ 2 wells
H Discovery ‐ 3 wells 1 WI
2P Cases
D Area ‐ 7 wells 2 WI
E Area ‐ 12 wells 3 WI
A Area 3 wells 1 Prod
2 WI
2 WI
D12, D13, D14
E‐11 & E‐14 4 Producers
2 Producers
3 Producers
2 Producers
D‐15 & D‐16
A Area ‐ 3 wells 1 Prod
C Area ‐ 2 wells
H Discovery ‐ 4 wells 1 WI
3P Cases
D Area ‐ 7 wells 2 WI
E Area ‐ 12 wells 3 WI
A Area 3 wells 1 Prod
2 WI
2 WI
E‐11 & E‐14 4 Producers 3 Producers
D12, D13, D14 D‐15 & D‐16
2 Producers
3 Producers
rpsgroup.com
A Area ‐ 3 wells 1 Prod
C Area ‐ 2 wells
H Discovery ‐ 4 wells 1 WI
2 Producers
2 WI
3 Producers
TABLES
Table 3.1
Bua Ban North Field - D Area
Well Tops and Net Pay Data
WELL NAMES: D01, D02, D03, D04, D5ST, D6, D7, D8, D9, D10 & D11 OPERATOR: Coastal Energy Company
FIELD: Songkhla, Offshore Thailand K. B.: 96.2 Feet
WELL SAND FAULT CONTACTS HOLE HOLE FM DIP GROSS SECTION NET PAY
NAME NAME BLOCK MD TVD SS MD TVD SS TYPE MD TVD SS DEV AZ DIP AZ MT TVD TVT TST MT TVD TVT TST
D01 M100 Western (A) 4,679 3,671 -3,575 4,752 3,713 -3,617 LKO 4,752 3,713 -3,617 54.0 155.0 5.7 300.0 73.0 42.9 47.7 47.5 54.4 32.0 35.6 35.4
UPR OLIG Central 7,089 5,563 -5,467 7,162 5,631 -5,535 LKO 7,162 5,631 -5,535 21.7 90.9 8.8 255.0 73.0 67.8 71.8 71.0 29.1 27.0 28.6 28.3
D02 UPR OLIG Western 5,194 4,199 -4,103 5,203 4,206 -4,110 OWC 5,203 4,206 -4,110 42.5 295.5 9.0 6.6 6.6 6.6 4.1 3.0 3.0 3.0
LWR OLIG Western 5,261 4,248 -4,152 5,272 4,256 -4,160 LKO 5,272 4,256 -4,160 42.1 295.9 11.0 8.2 8.2 8.2 4.0 3.0 3.0 3.0
D03 M200 Central 7,530 3,968 -3,872 7,568 3,997 -3,901 LKO 7,568 3,997 -3,901 40.0 149.0 5.7 301.0 38.0 29.1 31.3 31.1 30.0 23.0 24.7 24.6
M400 U Central 8,087 4,402 -4,306 8,103 4,415 -4,319 LKO 8,103 4,415 -4,319 37.0 149.0 5.7 301.0 16.0 12.8 13.6 13.6 16.3 13.0 13.9 13.8
M400 L Central 8,142 4,446 -4,350 8,196 4,490 -4,394 LKO 8,196 4,490 -4,394 35.0 149.0 5.7 301.0 54.0 44.2 47.0 46.7 53.7 44.0 46.7 46.5
M500 U Central 8,465 4,714 -4,618 8,551 4,785 -4,689 LKO 8,551 4,785 -4,689 33.5 148.0 86.0 71.7 71.7 71.7 33.6 28.0 28.0 28.0
M500 L Central 8,627 4,848 -4,752 8,653 4,869 -4,773 LKO 8,653 4,869 -4,773 34.0 148.0 26.0 21.6 21.6 21.6 13.4 11.1 11.1 11.1
D04 M100 Western (B) 5,219 3,738 -3,642 5,240 3,753 -3,657 LKO 5,240 3,753 -3,657 47.5 151.8 1.1 260.0 21.0 14.2 14.3 14.3 17.8 12.0 12.1 12.1
D05ST M100 Eastern 9,299 3,841 -3,745 9,511 3,903 -3,807 OWC 9,413 3,880 -3,784 65.7 0.9 2.3 77.0 212.0 87.2 85.4 85.3 81.2 33.4 32.7 32.7
D06 M100 Western (A) 4,175 3,712 -3,616 4,248 3,770 -3,674 LKO 4,248 3,770 -3,674 38.3 47.4 1.7 359.0 73.0 57.3 56.4 56.4 73.6 57.8 56.9 56.8
M500 Western 5,633 5,061 -4,965 5,638 5,066 -4,970 LKO 5,638 5,066 -4,970 0.1 4.6 15.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0
D07 M100 Eastern 8,531 3,776 -3,680 8,759 3,837 -3,741 LKO 8,759 3,837 -3,741 74.0 121.4 3.7 95.0 228.0 62.8 50.2 50.0 172.8 47.6 38.0 37.9
Partial Pene. Est 12 +TVD 74.0 121.4 3.7 95.0 43.5 12.0 9.6 9.5
D08 M100 Western (A) 6,935 3,823 -3,727 7,248 3,899 -3,803 LKO 7,248 3,899 -3,803 73.9 10.4 2.0 341.0 313.0 86.8 77.7 77.6 221.7 61.5 55.0 55.0
D09 M100 Western (A) 11,693 3,802 -3,706 11,796 3,880 -3,784 LKO 11,796 3,880 -3,784 41.0 70.0 103.5 78.1 78.1 78.1 46.8 35.3 35.3 35.3
M200 Western 11,966 4,008 -3,912 12,097 4,052 -3,956 OWC 11,990 4,016 -3,920 41.0 70.0 131.5 99.2 99.2 99.2 8.0 6.0 6.0 6.0
D10 M100 Western (A) 4,710 3,646 -3,550 LKO 66.5 61.4 7.2 -4,710.0 -1,878.1 -1,616.9 -1,604.2
D11 M100 Western (A) 4,050 3,661 -3,565 4,120 3,705 -3,609 LKO 4,120 3,705 -3,609 51.1 145.6 1.60 70.0 44.0 45.2 45.2 68.0 42.7 43.9 43.9
TOP OF HORIZON BASE OF HORIZON
RPS
Table 3.2
Bua Ban North Field - E Area
Well Tops and Net Pay Data
WELL NAMES: E01, E02, E03, E04, E05, E06, E07, E08, E09, E10 & E12 OPERATOR: Coastal Energy Company
FIELD: Songkhla, Offshore Thailand K. B.: 96.2 Feet
WELL SAND FAULT CONTACTS HOLE HOLE FM DIP GROSS SECTION NET PAY
NAME NAME BLOCK MD TVD SS MD TVD SS TYPE MD TVD SS DEV AZ DIP AZ MT TVD TVT TST MT TVD TVT TST
E01 M100 Central 4,337 3,903 -3,807 4,342 3,907 -3,811 LKO 4,342 3,907 -3,811 40.0 168.0 5.1 36.0 5.0 3.8 4.0 4.0 5.2 4.0 4.2 4.2
M500 Central 5,423 4,731 -4,635 5,445 4,748 -4,652 LKO 5,445 4,748 -4,652 40.0 168.0 6.4 104.0 22.0 16.9 16.2 16.1 9.1 7.0 6.7 6.7
M500 L Central 5,485 4,778 -4,682 5,492 4,784 -4,688 LKO 5,492 4,784 -4,688 40.0 168.0 6.4 104.0 7.0 5.4 5.1 5.1 6.5 5.0 4.8 4.8
U OLIG U Central 6,476 5,538 -5,442 6,494 5,552 -5,456 LKO 6,494 5,552 -5,456 40.0 165.0 7.2 347.0 18.0 13.8 15.2 15.1 17.0 13.0 14.4 14.3
U OLIG M Central 6,544 5,591 -5,495 6,563 5,605 -5,509 OWC 6,563 5,605 -5,509 40.0 165.0 7.2 347.0 19.0 14.6 16.1 16.0 14.4 11.0 12.2 12.1
U OLIG L Central 6,618 5,647 -5,551 6,694 5,707 -5,611 LKO 6,694 5,707 -5,611 40.0 162.0 7.2 347.0 76.0 58.2 64.4 63.9 3.9 3.0 3.3 3.3
OLIGOCENE SAND-UCentral 8,032 6,755 -6,659 8,062 6,779 -6,683 LKO 8,062 6,779 -6,683 37.0 148.0 7.2 347.0 30.0 24.0 26.1 25.9 11.3 9.0 9.8 9.7
OLIGOCENE SAND-L Central 8,216 6,901 -6,805 8,224 6,908 -6,812 LKO 8,224 6,908 -6,812 37.0 147.0 7.2 347.0 8.0 6.4 7.0 6.9 8.8 7.0 7.6 7.6
EOCENE U Central 8,698 7,293 -7,197 8,794 7,374 -7,278 LKO 8,794 7,374 -7,278 33.0 150.0 96.0 80.5 80.5 80.5 33.4 28.0 28.0 28.0
E02 M100 Western 4,872 3,737 -3,641 4,922 3,780 -3,684 LKO 4,922 3,780 -3,684 30.0 207.0 2.9 265.0 50.0 43.3 42.6 42.6 37.0 32.0 31.5 31.5
M200 Western 5,005 3,854 -3,758 5,014 3,862 -3,766 LKO 5,014 3,862 -3,766 27.0 207.0 2.9 265.0 9.0 8.0 7.9 7.9 9.0 8.0 7.9 7.9
M200 L Western 5,058 3,900 -3,804 5,081 3,921 -3,825 LKO 5,081 3,921 -3,825 27.0 207.0 2.9 265.0 23.0 20.5 20.2 20.2 22.5 20.0 19.7 19.7
E03 M100 M Eastern 7,367 3,744 -3,648 7,563 3,819 -3,723 LKO 7,563 3,819 -3,723 68.0 137.0 3.0 101.0 196.0 73.4 65.7 65.6 100.0 37.5 33.5 33.5
M200 Eastern 7,711 3,881 -3,785 7,729 3,889 -3,793 OWC 7,729 3,889 -3,793 64.0 137.0 3.0 101.0 18.0 7.9 7.2 7.2 18.3 8.0 7.3 7.3
E04 M50 Western 5,833 3,251 -3,155 5,888 3,276 -3,180 OWC 5,888 3,276 -3,180 63.0 170.0 4.3 282.0 55.0 25.0 26.3 26.3 22.0 10.0 10.6 10.5
M100 Western 6,805 3,756 -3,660 6,898 3,818 -3,722 LKO 6,898 3,818 -3,722 48.0 149.0 4.3 282.0 93.0 62.2 65.8 65.6 59.0 39.5 41.7 41.6
M200 Western 7,030 3,913 -3,817 7,064 3,938 -3,842 OWC 7,064 3,938 -3,842 43.0 149.0 4.3 282.0 34.0 24.9 26.1 26.0 22.0 16.1 16.9 16.8
M200 L Western 7,066 3,940 -3,844 7,224 4,060 -3,964 LKO 7,224 4,060 -3,964 41.0 149.0 4.3 282.0 158.0 119.2 124.6 124.2 19.9 15.0 15.7 15.6
M300 Western 7,285 4,108 -4,012 7,315 4,131 -4,035 OWC 7,315 4,131 -4,035 38.0 148.0 4.3 282.0 30.0 23.6 24.6 24.5 21.6 17.0 17.7 17.6
M300 L Western 7,338 4,150 -4,054 7,375 4,178 -4,082 OWC 7,375 4,178 -4,082 37.0 148.0 4.3 282.0 37.0 29.5 30.7 30.6 3.8 3.0 3.1 3.1
E05 M100 L Central 5,077 3,823 -3,727 5,114 3,849 -3,753 LKO 5,114 3,849 -3,753 47.0 164.0 4.3 282.0 37.0 25.2 26.2 26.1 14.7 10.0 10.4 10.3
M200 Central 5,212 3,916 -3,820 5,461 4,087 -3,991 LKO 5,461 4,087 -3,991 47.0 164.0 4.3 282.0 249.0 169.8 176.2 175.7 145.2 99.0 102.7 102.5
M300 Central 5,540 4,142 -4,046 5,602 4,184 -4,088 OWC 5,602 4,184 -4,088 46.0 164.0 4.3 282.0 62.0 43.1 44.6 44.5 47.5 33.0 34.2 34.1
M400 Central 5,747 4,286 -4,190 5,761 4,295 -4,199 LKO 5,761 4,295 -4,199 46.0 163.0 4.3 282.0 14.0 9.7 10.1 10.1 5.8 4.0 4.2 4.1
M500 Central 6,307 4,679 -4,583 6,319 4,687 -4,591 LKO 6,319 4,687 -4,591 46.0 162.0 6.3 93.0 12.0 8.3 8.0 7.9 11.5 8.0 7.7 7.6
M500 L Central 6,373 4,724 -4,628 6,410 4,750 -4,654 LKO 6,410 4,750 -4,654 46.0 162.0 6.3 93.0 37.0 25.7 24.6 24.5 30.2 21.0 20.1 20.0
E06 M100 Western 4,013 3,769 -3,673 4,126 3,872 -3,776 LKO 4,126 3,872 -3,776 24.0 326.0 2.7 333.0 113.0 103.2 101.1 101.0 75.5 69.0 67.5 67.5
Eocene Western 6,596 6,290 -6,194 6,643 6,337 -6,241 LKO 6,643 6,337 -6,241 5.5 2.0 47.0 46.8 46.8 46.8 17.0 16.9 16.9 16.9
Eocene L Western 6,923 6,616 -6,520 6,977 6,670 -6,574 OWC 6,977 6,670 -6,574 6.0 13.5 54.0 53.7 53.7 53.7 1.5 1.5 1.5 1.5
E07 M100 Western 5,280 3,883 -3,786 5,285 3,885 -3,789 LKO 5,285 3,885 -3,789 58.0 355.0 3.6 355.0 4.5 2.4 2.1 2.1 5.0 2.6 2.4 2.4
E08 M100 Eastern 5,739 3,769 -3,673 5,979 3,884 -3,788 LKO 5,979 3,884 -3,788 62.0 109.0 4.2 57.0 240.0 112.7 103.1 102.8 195.0 91.5 83.8 83.5
E09 M75 Central 6,295 3,450 -3,299 6,355 3,466 -3,315 OWC 6,345 3,463 -3,313 75.0 178.0 60.0 15.5 15.5 15.5 51.8 13.4 13.4 13.4
M100 Central (A) 7,264 3,805 -3,655 7,405 3,871 -3,720 LKO 7,405 3,871 -3,720 62.0 167.0 141.5 66.4 66.4 66.4 103.7 48.7 48.7 48.7
M200 Central 7,656 3,988 -3,837 7,935 4,117 -3,967 LKO 7,935 4,117 -3,967 62.0 167.0 2.5 270.0 279.0 131.0 133.4 133.3 142.7 67.0 68.2 68.2
M300 Central 8,039 4,166 -4,016 8,134 4,210 -4,060 OWC 8,124 4,206 -4,055 62.0 168.0 2.4 270.0 94.5 44.4 45.1 45.1 60.5 28.4 28.9 28.8
M500 Central 9,393 4,797 -4,646 9,411 4,805 -4,655 LKO 9,411 4,805 -4,655 62.0 168.0 3.0 220.0 18.5 8.7 8.2 8.1 18.7 8.8 8.3 8.3
E10 M100 Central (B) 5,733 3,826 -3,675 5,935 3,944 -3,794 LKO 5,935 3,944 -3,794 56.0 119.0 7.0 90.0 201.7 112.7 94.7 94.0 141.0 79.2 66.6 66.1
M500 Central (B) 6,888 4,581 -4,431 6,903 4,592 -4,441 LKO 6,903 4,592 -4,441 46.0 107.0 4.6 110.0 15.0 10.4 9.6 9.5 15.4 10.7 9.8 9.8
E12 1500 Sand Western 1,543 1,535 -1,384 1,563 1,555 -1,404 OWC 1,548 1,539 -1,389 7.0 249.0 20.0 19.9 19.9 19.9 5.0 5.0 5.0 5.0
M100 Western 4,439 3,724 -3,574 4,616 3,829 -3,679 LKO 4,616 3,829 -3,679 54.0 218.0 5.0 70.0 176.5 103.7 114.3 113.9 125.9 74.0 81.6 81.2
TOP OF HORIZON BASE OF HORIZON
RPS
Table 3.3
H Discovery
Well Tops and Net Pay Data
WELL NAMES: H01, H01 ST OPERATOR: Coastal Energy Company
FIELD: Songkhla, Offshore Thailand K. B.: 96.2 Feet
WELL SAND FAULT CONTACTS HOLE HOLE FM DIP GROSS SECTION NET PAY
NAME NAME BLOCK MD TVD SS MD TVD SS TYPE MD TVD SS DEV AZ DIP AZ MT TVD TVT TST MT TVD TVT TST
H01 ST Upr Oligocene UT 7,442 6,636 -6,540 9,079 7,618 -7,522 LKO 9,079 7,618 -7,522 53.0 296.0 8.2 359.0 1,637.0 985.2 899.6 890.4 10.0 6.0 5.5 5.4
Lwr Oligocene UT 9,528 7,893 -7,797 10,742 8,715 -8,619 LKO 10,742 8,715 -8,619 48.0 298.0 8.2 359.0 1,214.0 812.3 749.3 741.6 39.0 26.1 24.1 23.8
H01 ST Oligocene SS UT 11,908 8,673 -8,577 11,909 8,674 -8,578 LKO 11,909 8,674 -8,578 42.0 283.0 7.5 357.4 1.0 0.7 0.7 0.7 1.3 1.0 0.9 0.9
TOP OF HORIZON BASE OF HORIZON
RPS
Table 4.1
Production Well Tests - Songkhla A, D and E Areas
31-Dec-11
Well No.Choke
Size
Wellhead
Pressure
Wellhead
TempWater Cut
Pump
Freq
Pump
Intake
Pressure
Pump
Discharge
Pressure
Allocated
Oil
Volume
Allocated
Gas
Volume
Allocated
Water
Volume
/64 psig F % hz psia psis stb mmscf bbl
SKL A-1 128 200 237 80 65 1358 3104 546 0.11 2922
SKL A-3 128 410 236 78 64 1270 3290 1060 0.12 5027SKL A-4 * 128 185 230 75 64 870 3083 1214 0.24 3828
SKL A-7st1 128 115 146 73 60 719 2981 127 0.02 38
SKL A-8 128 120 201 64 63 1234 2760 374 0.06 889
SKL A-9 128 135 123 40 56 435 2601 403 0.04 359
SKL A-11 128 110 86 6 60 1060 2723 10 0.01 0
SKL A-12 40 155 184 49 55 585 2750 582 0.06 749
A Area Totals 4316 0.66 13812
SKL D-10 37 322 158 2 40 923 1790 2609 0 0
SKL D-6 30 864 145 3 40 1089 2244 1304 0 0
D Area Totals 3913 0 0
SKL E-1 36 99 122 0 55 546 546 416 0 0
SKL E-2 36 98 139 4 44 718 1462 785 0 28
SKL E-3 64 89 165 16 46 819 1726 1527 0 323
SKL E-4 36 83 105 0 40 NA NA 345 0 0
SKL E-5 64 103 179 72 53 952 2071 1433 0 4255
SKL E-6 64 90 170 32 44 975 1869 2369 0 1195
SKL E-8 56 91 169 83 49 1080 1087 416 0 3463
E Area Totals 7293 0 9265
Songkhla A, D & E Totals 15522 1 23077
* Test gauge dated December 4, 2011. Well shut in with VSD issue on December 31, 2011.
RPS
Table 5.1
Bua Ban North Field - D Area Wells
Rock and Fluid Properties
MDT Test Depth
Sand Member Fault Block Well(s) Yes / No SS TVD Porosity Permeability Temp Water Gas Oil Water Gas-Oil
Salinity Specific Gravity Saturation Ratio Pressure
feet % md deg F ppm Gravity API % cf/bbl psi
(1) (1 & 2) (2 & 3) (4) (2 & 5) (4 & 5) (5) (1 & 2) (5) (4)
Miocene 100 Western (A) D-1, 6, 8, 9, 10, 11 Yes 3575-3727 26.6 800 171 3000 1.00 36.0 36.5 150:1 1556
Miocene 100 Western (B) D-4 No 3642 30.9 1200 172 3000 1.00 36.0 53.9 150:1 1595
Miocene 100 Eastern D-5 ST & D-7 Yes 3745-3680 26.2 720 173 3000 1.00 36.0 32.9 150:1 1588
Miocene 200 Central D-3 No 3872 27.0 900 178 3000 1.00 36.0 50.9 150:1 1696
Miocene 400 U Central D-3 No 4306 28.1 1100 190 3000 1.00 36.0 29.3 150:1 1886
Miocene 400 L Central D-3 No 4350 27.1 925 191 3000 1.00 36.0 42.8 150:1 1905
Miocene 500 U Central D-3 No 4618 28.7 1100 200 3000 1.00 36.0 46.6 150:1 2023
Miocene 500 L Central D-3 No 4752 27.0 900 204 3000 1.00 36.0 46.6 150:1 2081
(1) Well log analysis
(2) Petrophysical reports and extrapolations
(3) Miocene sand correlations
(4) MDT data and extrapolations
(5) Data from offset Songkhla and Bua Ban platforms and new well data; actual values for the platform are expected to vary
Fluid PropertiesReservoir Identification Rock Properties
RPS
Table 5.2
Bua Ban North Field - D Area Wells
Recovery Factor Calculations
Thickness STOOIP
Sand Member Fault Block Well(s) Well Reservoir Drive Mechanism Sweep Efficiency
Feet bbl / ac-ft bbl / ac-ft % % bbl / ac-ft %
Miocene 100 Western (A) D-1, 6, 8, 9, 10, 11 36, 57, 55, 35, H, 43 1236 549 44.4 Water 0.75 412 33.3
Miocene 100 Western (B) D-4 12 1043 285 27.3 Water 0.75 214 20.5
Miocene 100 Eastern D-5 ST & D-7 33 & 48 (Est) 1287 604 46.9 Water 0.80 483 37.5
Miocene 200 Central D-3 25 970 286 29.5 Partial Water 0.75 215 22.1
Miocene 400 U Central D-3 14 1454 768 52.8 Partial Water 0.75 576 39.6
Miocene 400 L Central D-3 47 1135 456 40.2 Partial Water 0.75 342 30.2
Miocene 500 U Central D-3 28 1122 422 37.6 Partial Water 0.75 317 28.2
Miocene 500 L Central D-3 11 1055 381 36.1 Partial Water 0.75 286 27.1
Reservoir Identification Recovery Factor Calculation
Recovery before Sweep Efficiency Recovery
RPS
Table 5.3
Bua Ban North Field - D Area Wells
Reservoir Volume and Estimated Ultimate Recovery Calculations
STOOIP
Sand Member Fault Block ac-ft Reserves Category Description MMBBL bbl/ac-ft MMBBL
Miocene 100 W (A) 32,802 1P 2P area with 0.752 N/G (-10%) 40.54 412 13.506
Miocene 100 W (A) 36,447 2P E Area, Eastern flank MDT avg 3,830 ft. 45.05 412 15.007
Miocene 100 W (A) 36,447 3P 2P area with 0.878 N/G (+5%) 47.30 412 15.757
Miocene 100 W (B) 192 1P LKO @ 3,657 ft. 0.20 214 0.041
Miocene 100 W (B) 969 2P Average of 1P and 3P volume 1.01 214 0.207
Miocene 100 W (B) 1,746 3P LKO @ 3,657 ft. + 2 sand thicknesses 1.80 214 0.370
Miocene 100 E 9,611 1P Reduce 2P area by 30% for area west of fault at D-7 12.37 483 4.644
Miocene 100 E 13,730 2P OWC in D-5 ST1 @ 3,784 ft. 17.67 483 6.634
Miocene 100 E 13,730 3P 2P 17.67 483 6.634
Miocene 200 C 443 1P LKO @ 3,901 ft. 0.43 215 0.095
Miocene 200 C 1,939 2P Average of 1P and 3P volume 1.88 215 0.416
Miocene 200 C 3,434 3P LKO @ 3,901 ft. + 2 sd thicknesses = 3,963 ft. 3.30 215 0.740
Miocene 400 U C 239 1P LKO @ 4,320 ft. + 1 sd thickness = 4,334 ft. 0.35 576 0.138
Miocene 400 U C 888 2P Average of 1P and 3P volume 1.29 576 0.511
Miocene 400 U C 1,536 3P LKO of 400 L member at 4,394 ft. 2.20 576 0.880
Miocene 400 L C 1,014 1P LKO @ 4,394 ft. 1.15 342 0.347
Miocene 400 L C 3,569 2P LKO @ 4,394 ft. + 1 sd thickness = 4,446 ft. 4.05 342 1.221
Miocene 400 L C 3,569 3P 2P + 20% add to N/G 4.86 342 1.465
Miocene 500 U C 692 1P 75% of 2P volume 0.78 317 0.219
Miocene 500 U C 922 2P LKO of bottom of 4 members @ 4,684 ft. 1.03 317 0.292
Miocene 500 U C 1,383 3P 150% of 2P volume 1.60 317 0.438
Miocene 500 L C 138 1P 75% of 2P volume 0.15 286 0.039
Miocene 500 L C 184 2P LKO of bottom of 2 members @ 4,773 ft. 0.19 286 0.053
Miocene 500 L C 276 3P 150% of 2P volume 0.30 286 0.079
Bua Ban North Field - Area D Totals 45,131 1P 55.96 34.0% 19.029
58,648 2P 72.18 33.7% 24.341
62,121 3P 79.03 33.4% 26.363
Reservoir Identification Reservoir Volume Determination Oil Recovery
RPS
Table 5.4
Bua Ban North Field - E Area Wells
Rock and Fluid Properties
MDT Test Depth
Sand Member Fault Block (s) Well(s) Yes / No SS TVD Porosity Permeability Temp Water Gas Oil Water Gas-Oil
Salinity Specific Gravity Saturation Ratio Pressure
feet % md deg F ppm Gravity API % cf/bbl psi
(1) (1 & 2) (2 & 3) (4) (2 & 5) (5) (4 & 5) (1 & 2) (5) (4)
Miocene 100 Western E-2, E-4, E-6, E-7, E-12 Yes 3641 to 3,786 29.0 1125 183 3000 1.00 36.0 41.0 150:1 1630
Miocene 100 Central (A) E-1, E-5 & E-9 Yes 3805 to 3727 25.8 675 177 3000 1.00 36.0 45.7 150:1 1630
Miocene 100 Central (B) E-10 No 3826 26.5 800 182 3000 1.00 36.0 38.5 150:1 1676
Miocene 100 Eastern E-3 & E8 Yes 3648 & 3680 28.4 1100 177 3000 1.00 36.0 32.6 150:1 1635
Miocene 200 U Western (A) E-2 Yes 3758 25.8 675 180 3000 1.00 36.0 37.7 150:1 1646
Miocene 200 L Western (A) E-2 Yes 3804 27.9 1050 182 3000 1.00 36.0 43.4 150:1 1666
Miocene 200 Central E-5, E-9 Yes 3820 to 3988 27.6 1000 181 3000 1.00 36.0 40.2 150:1 1710
Miocene 300 Central (A) E-5 Yes 4046 26.8 820 183 3000 1.00 36.0 39.6 150:1 1780
Miocene 300 Central (B) E-9 No 4167 27.2 900 187 3000 1.00 36.0 36.5 150:1 1833
Miocene 500 Central E-1, E-4, E-5 & E-9 Yes 4464-4682 27.9 1000 195 3000 1.00 36.0 39.4 150:1 1987
Upr Oligocene A Central E-1 No 5442 22.9 200 200 3000 1.00 30.0 52.6 300:1 2346
Upr Oligocene B Central E-1 No 5495 22.9 200 202 3000 1.00 30.0 52.6 300:1 2369
Lwr Oligocene SS-A Central E-1 Yes 6659 19.5 200 231 3000 1.00 30.0 58.8 300:1 2875
Lwr Oligocene SS-B Central E-1 Yes 6805 19.5 200 240 3000 1.00 30.0 58.8 300:1 2925
(1) Well log analysis
(2) Petrophysical reports and extrapolations
(3) Miocene sand correlations
(4) MDT data and extrapolations
(5) Data from offset Songkhla and Bua Ban platforms and new well data; actual values for the platform are expected to vary
Fluid PropertiesReservoir Identification Rock Properties
RPS
Table 5.5
Bua Ban North Field - E Area Wells
Recovery Factor Calculations
Thickness STOOIP
Sand Member Fault Block (s) Well(s) Well (s) Reservoir Drive Mechanism Sweep Efficiency
ft bbl / ac-ft bbl / ac-ft % % bbl / ac-ft %
Miocene 100 Western * E-2, E-4, E-6, E-7, E-12 32, 42, 68, 3, 82 1252 543 43.4 Waterflood 80 434 34.7
Miocene 100 Central (A) * E-1, E-5 & E-9 4, 10 & 49 1025 350 34.1 Partial Water 75 263 25.6
Miocene 100 Central (B) E-10 67 1090 487 44.7 Partial Water 75 365 33.5
Miocene 100 Eastern * E-3, E8 34 & 84 1401 702 50.1 Water 80 562 40.1
Miocene 200 U Western (A) * E-2 8 1176 500 42.5 Partial Water 75 375 31.9
Miocene 200 L Western (A) * E-2 20 1156 466 40.3 Partial Water 75 350 30.2
Miocene 200 Central * E-5 & E-9 103 & 68 1208 519 43.0 Partial Water 70 363 30.1
Miocene 300 Central (A)* E-5 34 1185 499 42.1 Partial Water 70 349 29.5
Miocene 300 Central (B) E-9 29 1264 579 45.8 Partial Water 75 434 34.4
Miocene 500 Central * E-1, E-4, E-5 & E-9 12, 0 , 28, 8 1237 546 44.1 Partial Water 75 410 33.1
Upr Oligocene A Central E-1 14 715 300 42.0 Limited Water 70 210 29.4
Upr Oligocene B Central E-1 12 715 300 42.0 Limited Water 70 210 29.4
Lwr Oligocene SS-A Central * E-1 10 527 250 47.4 Partial Water 80 200 38.0
Lwr Oligocene SS-B Central * E-1 8 526 250 47.5 Partial Water 80 200 38.0
* Indicates reservoir is producing Upr Oligocene and Lwr Oligocene oil recovery per ac-ft estimated based on performance
Reservoir Identification
Recovery Before Sweep Efficiency Reservoir Recovery
Recovery Factor Calculation
RPS
Table 5.6
Bua Ban North Field - E Area Wells
Reservoir Volume and Estimated Ultimate Recovery Calculations
STOOIP
Sand Member Fault Block ac-ft Reserves Category Description MMBBL bbl/ac-ft MMBBL
Miocene 100 W 19,680 1P 2P area with 10% reduction to N/G 24.64 434 8.549
Miocene 100 W 21,867 2P DD limit to MDT average of 3,830 ft. 27.38 434 9.499
Miocene 100 W 22,960 3P 2P area with + 5% increase to N/G 28.75 434 9.974
Miocene 100 C (A) 11,277 1P 2P area with 15% reduction to N/G 11.56 263 2.960
Miocene 100 C (A) 13,267 2P DD limit to MDT & LKO in E-1 @ 3,811 ft. 13.60 263 3.483
Miocene 100 C (A) 14,594 3P 2P area with + 10% increase to N/G 14.96 263 3.831
Miocene 100 C (B) 7,611 1P 2P area with 15% reduction to sweep efficiency 8.30 365 2.780
Miocene 100 C (B) 8,954 2P DD limit LKO @ 3,784 ft. in D-10 9.76 365 3.270
Miocene 100 C (B) 8,954 3P 2P 9.76 365 3.270
Miocene 100 E 13,392 1P DD limit LKO @ 3,788 ft. in E-8 18.76 562 7.521
Miocene 100 E 15,546 2P OWC from MDT & prod @ 3,810 ft. 21.78 562 8.731
Miocene 100 E 15,546 2P 2P 21.78 562 8.731
Miocene 200 U W (A) 964 1P DD limit LKO @ 3,766 ft. plus 1 sd to 3,774 ft. 1.13 375 0.362
Miocene 200 U W (A) 1,851 2P Average of 1P and 3P volume 2.18 375 0.694
Miocene 200 U W (A) 2,738 3P HKW @ 3,853 ft in E06 3.20 375 1.026
Miocene 200 L W (A) 1,747 1P DD limit LKO @ 3,825 ft. plus 1 sd to 3,846 ft. 2.02 350 0.611
Miocene 200 L W (A) 2,198 2P Average of 1P and 3P volume 2.54 350 0.768
Miocene 200 L W (A) 2,649 3P MDT OWC @ 3,880 ft. in E-2 3.10 350 0.930
Miocene 200 C 31,685 1P 2P area with 20% reduction to N/G 38.28 363 11.511
Miocene 200 C 39,606 2P Downdip limit LKO @ 3,991 ft. at spillpoint 47.84 363 14.389
Miocene 200 C 43,567 3P 2P area with + 10% increase to N/G 52.63 363 15.828
Miocene 300 C (A) 680 1P Downdip limit OWC @ 4,088 ft. in E-5 0.81 349 0.238
Miocene 300 C (A) 680 2P 1P 0.81 349 0.238
Miocene 300 C (A) 680 3P 1P 0.81 349 0.238
Miocene 300 C (B) 1,037 1P Downdip limit OWC @ 4,055 ft. in E-9 1.31 434 0.450
Miocene 300 C (B) 1,037 2P 1P 1.31 434 0.450
Miocene 300 C (B) 1,037 3P 1P 1.31 434 0.450
Miocene 500 C 4,463 1P 2P area with 10% reduction to N/G 5.52 410 1.828
Miocene 500 C 4,959 2P W & S - E-4 HKW 4,659 ft., NE - E-1 LKO @ 4,688 ft. 6.13 410 2.031
Miocene 500 C 5,207 3P 2P area with + 5% increase to N/G 6.44 410 2.132
Upr Olig A C 1,208 1P Downdip limit LKO @ 5,456 ft. 0.86 210 0.254
Upr Olig A C 1,268 2P 1P volume plus 5% 0.91 210 0.266
Upr Olig A C 1,329 3P 1P volume plus 10% 0.95 210 0.279
Upr Olig B C 1,032 1P Downdip limit OWC @ 5,509 ft. 0.74 210 0.217
Upr Olig B C 1,032 2P 1P 0.74 210 0.217
Upr Olig B C 1,032 3P 1P 0.74 210 0.217
Lwr Olig SS-A C 593 1P Downdip limit LKO @ 6,683 ft. 0.31 200 0.119
Lwr Olig SS-A C 788 2P Average of 1P and 3P volume 0.42 200 0.158
Lwr Olig SS-A C 982 3P Downdip limit MDT @ 6,880 ft. 0.50 200 0.197
Lwr Olig SS-B C 421 1P Downdip limit LKO @ 6,812 ft. 0.22 200 0.084
Lwr Olig SS-B C 516 2P Average of 1P and 3P volume 0.27 200 0.103
Lwr Olig SS-B C 611 3P Downdip limit MDT @ 6,880 ft. 0.30 200 0.120
Bua Ban North Field - E Area Totals 87,142 1P 114.46 32.7% 37.482
103,578 2P 135.66 32.7% 44.296
111,894 3P 145.22 32.5% 47.223
Reservoir Identification Reservoir Volume Determination Oil Recovery
RPS
Table 5.7
H Discovery
Rock and Fluid Properties
MDT Test Depth
Sand Member Fault Block Well Yes / No SS TVD Porosity Permeability Temp Water Gas Oil Water Gas-Oil
Salinity Specific Gravity Saturation Ratio Pressure
feet % md deg F ppm Gravity API % cf/bbl psi
(1) (1 & 2) (2 & 3) (4) (2 & 5) (4 & 5) (5) (1 & 2) (5) (4)
Oligocene Lower UT H-1 Yes 8240 20.4 90 272 3000 1.00 30.0 45.4 139:1 3535
(1) Well log analysis
(2) Petrophysical reports and extrapolations
(3) Oligocene sand correlations
(4) MDT data and extrapolations
(5) Data from offset Songkhla and Bua Ban platforms and new well data; actual values for the platform are expected to vary
Fluid PropertiesReservoir Identification Rock Properties
RPS
Table 5.8
H Discovery
Recovery Factor Calculations
Thickness STOOIP
Sand Member Fault Block Well Well Reservoir Drive Mechanism Sweep Efficiency
Ft bbl / ac-ft bbl / ac-ft % % bbl / ac-ft %
Oligocene Lower UT H-1 26 864 213 24.7 Water - 1P 75 160 18.5
907 256 28.3 Water - 2P 80 205 22.6
935 285 30.5 Water - 3P 80 228 24.4
Reservoir Identification Recovery Factor Calculation
Recovery before Sweep Efficiency Recovery
RPS
Table 5.9
H Discovery
Reservoir Volume and Estimated Ultimate Recovery Calculations
STOOIP
Sand Member Fault Block ac-ft Reserves Category Description MMBBL bbl/ac-ft MMBBL
Oligocene Lower UT 1,443 1P Base of sand plus 1 sand thickness, OWC 8,300 ft. 1.25 160 0.231
Oligocene Lower UT 4,193 2P Add second gross sand to 1P for OWC 8,340 ft. 3.80 205 0.859
Oligocene Lower UT 4,193 3P Improved reservoir quality above 2P 3.92 228 0.956
Reservoir Identification Reservoir Volume Determination Oil Recovery
RPS
Table 7.1
GULF OF THAILAND, SONGKHLA A AREA
PRODUCTION, OPERATING EXPENSE AND INVESTMENT FORECASTS
Year Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment
MBBL $M $M MBBL $M $M MBBL $M $M
2012 1,382.0 28,665.9 36,376.3 1,556.0 28,455.0 36,376.1 1,696.0 28,455.0 36,376.3
2013 1,028.7 13,589.4 0.0 1,197.0 25,550.7 0.0 1,232.5 25,550.7 0.0
2014 803.8 12,948.8 0.0 1,041.0 26,061.8 0.0 1,125.5 26,061.8 0.0
2015 666.7 13,447.6 0.0 1,048.0 26,583.0 0.0 1,132.1 26,583.0 0.0
2016 519.2 13,957.2 0.0 971.5 27,115.1 0.0 1,117.7 27,115.1 0.0
2017 423.3 14,476.0 0.0 888.3 27,656.9 0.0 1,064.1 27,656.9 0.0
2018 361.1 15,005.3 0.0 821.5 28,210.1 0.0 1,025.7 28,210.1 0.0
2019 297.6 15,545.3 0.0 626.1 28,774.3 0.0 882.6 28,774.3 0.0
2020 232.5 16,096.9 0.0 470.5 29,350.3 0.0 660.3 29,350.3 0.0
2021 130.0 11,042.3 0.0 380.8 29,936.8 0.0 509.6 29,936.8 0.0
2022 0.0 0.0 8,484.0 328.7 16,074.6 0.0 390.8 16,074.6 0.0
2023 0.0 0.0 0.0 230.7 15,068.3 0.0 290.6 15,068.3 0.0
2024 0.0 0.0 0.0 163.7 15,370.0 0.0 190.3 15,370.0 0.0
2025 0.0 0.0 0.0 147.3 15,677.1 0.0 57.0 6,494.4 0.0
2026 0.0 0.0 0.0 90.5 10,625.1 0.0 0.0 0.0 8,763.0
2027 0.0 0.0 0.0 0.0 0.0 9,546.0 0.0 0.0 0.0
2028 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2029 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2030 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2031 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2032 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2033 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2034 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2035 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2036 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2037 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2038 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Totals 5,844.8 154,774.5 44,860.3 9,961.8 350,509.0 45,922.1 11,374.7 330,701.2 45,139.3
1P Reserves Category 2P Reserves Category 3P Reserves Category
RPS
Table 7.2
GULF OF THAILAND, SONGKHLA C AREA
PRODUCTION, OPERATING EXPENSE AND INVESTMENT FORECASTS
Year Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment
MBBL $M $M MBBL $M $M MBBL $M $M
2012 316.2 13,850.0 8,000.0 320.2 13,850.0 8,000.0 324.2 13,850.0 8,000.0
2013 337.7 13,850.0 0.0 501.3 13,850.0 0.0 824.9 13,850.0 0.0
2014 186.1 11,080.0 0.0 274.6 11,080.0 0.0 433.9 11,080.0 0.0
2015 0.0 0.0 7,425.0 162.1 8,310.0 0.0 250.4 8,310.0 0.0
2016 0.0 0.0 0.0 0.0 0.0 7,520.0 161.3 6,232.5 0.0
2017 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 7,773.0
2018 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2019 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2020 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2021 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2022 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2023 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2024 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2025 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2026 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2027 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2028 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2029 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2030 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2031 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2032 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2033 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2034 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2035 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2036 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2037 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2038 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Totals 840.1 38,780.0 15,425.0 1,258.2 47,090.0 15,520.0 1,994.8 53,322.5 15,773.0
1P Reserves Category 2P Reserves Category 3P Reserves Category
RPS
Table 7.3
GULF OF THAILAND, SONGKHLA D AND E AREAS
PRODUCTION, OPERATING EXPENSE AND INVESTMENT FORECASTS
Year Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment
MBBL $M $M MBBL $M $M MBBL $M $M
2012 5,475.0 59,723.9 127,459.8 5,475.0 59,723.9 127,459.8 5,475.0 59,723.9 127,357.9
2013 5,475.0 31,148.5 13,268.4 5,475.0 31,148.5 13,268.4 5,475.0 31,148.5 13,268.4
2014 5,475.0 31,771.0 0.0 5,475.0 31,771.0 0.0 5,475.0 31,771.0 0.0
2015 5,475.0 32,406.0 427.3 5,475.0 32,406.0 0.0 5,475.0 32,406.0 0.0
2016 5,475.0 33,055.2 0.0 5,475.0 33,055.2 435.8 5,475.0 33,055.2 435.8
2017 5,475.0 33,716.1 0.0 5,475.0 33,716.1 0.0 5,475.0 33,716.1 0.0
2018 4,467.6 34,390.0 0.0 5,475.0 34,390.0 0.0 5,475.0 34,390.0 0.0
2019 3,645.6 35,077.3 0.0 4,653.8 35,077.3 0.0 5,475.0 35,077.3 0.0
2020 2,974.8 35,780.0 0.0 3,955.7 35,780.0 0.0 4,599.0 35,780.0 0.0
2021 2,427.4 36,495.4 0.0 3,362.3 36,495.4 0.0 3,863.2 36,495.4 0.0
2022 2,014.8 37,224.8 0.0 2,858.0 37,224.8 0.0 3,245.1 37,224.8 0.0
2023 1,672.2 37,968.8 0.0 2,429.3 37,968.8 0.0 2,758.3 37,968.8 0.0
2024 1,388.0 38,729.4 0.0 2,089.2 38,729.4 0.0 2,344.6 38,729.4 0.0
2025 1,110.4 39,503.8 0.0 1,796.7 39,503.8 0.0 1,992.9 39,503.8 0.0
2026 888.3 40,293.4 0.0 1,545.2 40,293.4 0.0 1,693.9 40,293.4 0.0
2027 710.6 19,340.8 0.0 1,328.8 30,220.0 0.0 1,456.8 36,264.0 0.0
2028 568.5 14,505.6 0.0 1,156.1 15,110.0 0.0 1,252.8 32,637.6 0.0
2029 454.8 10,879.2 0.0 1,005.8 11,332.5 0.0 1,077.4 29,373.9 0.0
2030 363.8 4,589.7 0.0 814.7 5,194.1 0.0 948.1 26,436.5 0.0
2031 267.0 3,442.2 0.0 659.9 3,895.5 0.0 834.4 23,792.8 0.0
2032 0.0 0.0 33,028.3 541.1 2,921.7 0.0 734.2 21,413.5 0.0
2033 0.0 0.0 0.0 443.7 2,191.2 0.0 653.5 19,272.2 0.0
2034 0.0 0.0 0.0 363.9 1,643.4 0.0 581.6 17,345.0 0.0
2035 0.0 0.0 0.0 298.4 1,232.6 0.0 494.4 15,610.5 0.0
2036 0.0 0.0 0.0 247.0 924.4 0.0 425.0 14,049.4 0.0
2037 0.0 0.0 0.0 0.0 0.0 35,573.0 0.0 0.0 37,196.0
2038 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Totals 55,803.8 610,041.4 174,183.8 67,874.5 631,949.3 176,737.0 72,755.1 793,479.2 178,258.1
1P Reserves Category 2P Reserves Category 3P Reserves Category
RPS
Table 7.4
GULF OF THAILAND, SONGKHLA H AREA
PRODUCTION, OPERATING EXPENSE AND INVESTMENT FORECASTS
Year Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment Gross Oil
Operating
Expense Investment
MBBL $M $M MBBL $M $M MBBL $M $M
2012 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2013 0.0 0.0 0.0 304.1 19,290.0 18,287.2 333.3 19,290.0 18,287.2
2014 0.0 0.0 0.0 340.1 14,567.0 0.0 365.1 14,567.0 0.0
2015 0.0 0.0 0.0 204.1 14,858.0 0.0 216.6 14,858.0 0.0
2016 0.0 0.0 0.0 0.0 0.0 2,302.0 28.0 2,446.0 0.0
2017 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4,569.0
2018 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2019 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2020 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2021 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2022 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2023 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2024 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2025 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2026 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2027 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2028 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2029 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2030 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2031 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2032 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2033 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2034 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2035 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2036 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2037 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2038 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Totals 0.0 0.0 0.0 848.2 48,715.0 20,589.2 943.0 51,161.0 22,856.2
1P Reserves Category 2P Reserves Category 3P Reserves Category
RPS
APPENDICES
APPENDIX 1
Appendix 1 SPE/WPC/AAPG/SPE RESERVE/RESOURCE DEFINITIONS
RPS 1
The following is extracted from the SPE/WPC/AAPG/SPEE PRMS 2007 using the section numbering and spelling from PRMS.
1.0 Basic Principles and Definitions
The estimation of petroleum resource quantities involves the interpretation of volumes and values that have an inherent degree of uncertainty. These quantities are associated with development projects at various stages of design and implementation. Use of a consistent classification system enhances comparisons between projects, groups of projects, and total company portfolios according to forecast production profiles and recoveries. Such a system must consider both technical and commercial factors that impact the project’s economic feasibility, its productive life, and its related cash flows.
1.1 Petroleum Resources Classification Framework
Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulphide and sulphur. In rare cases, non-hydrocarbon content could be greater than 50%.
The term “resources” as used herein is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”
Figure A1-1 is a graphical representation of the SPE/WPC/AAPG/SPEE resources classification system. The system defines the major recoverable resources classes: Production, Reserves, Contingent Resources, and Prospective Resources, as well as Unrecoverable petroleum.
Figure B.1: Resources Classification Framework
Appendix 1 SPE/WPC/AAPG/SPE RESERVE/RESOURCE DEFINITIONS
RPS 2
The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality, that is, the chance that the project that will be developed and reach commercial producing status. The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage.
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be
Appendix 1 SPE/WPC/AAPG/SPE RESERVE/RESOURCE DEFINITIONS
RPS 3
recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
1.2 Project-Based Resources Evaluations
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to an evaluation of net recoverable resources (see Figure A1-2) that may be described as follows:
Figure B.2: Resources Evaluation Data Sources
The Reservoir (accumulation): Key attributes include the types and quantities of Petroleum Initially-in-Place and the fluid and rock properties that affect petroleum recovery.
The Project: Each project applied to a specific reservoir development generates a unique production and cash flow schedule. The time integration of these schedules taken to the project’s technical, economic, or contractual limit defines the estimated recoverable resources and associated future net cash flow projections for each project. The ratio of EUR to Total Initially-in-Place quantities defines the ultimate recovery efficiency for the development project(s). A project may be defined at various levels and stages of maturity; it may include one or many wells and associated production and processing facilities. One project may develop many reservoirs, or many projects may be applied to one reservoir.
The Property (lease or license area): Each property may have unique associated contractual rights and obligations including the fiscal terms. Such information allows definition of each participant’s share of produced quantities (entitlement) and share of investments, expenses, and revenues for each recovery project and the reservoir to which it is applied. One property may encompass many reservoirs, or one reservoir may span several different properties. A property may contain both discovered and undiscovered accumulations.
In context of this data relationship, “project” is the primary element considered in this resources
classification, and net recoverable resources are the incremental quantities derived from each project.
Appendix 1 SPE/WPC/AAPG/SPE RESERVE/RESOURCE DEFINITIONS
RPS 4
Project represents the link between the petroleum accumulation and the decision-making process. A project may, for example, constitute the development of a single reservoir or field, or an incremental development for a producing field, or the integrated development of several fields and associated facilities with a common ownership. In general, an individual project will represent the level at which a decision is made whether or not to proceed (i.e., spend more money) and there should be an associated range of estimated recoverable quantities for that project.
An accumulation or potential accumulation of petroleum may be subject to several separate and distinct projects that are at different stages of exploration or development. Thus, an accumulation may have recoverable quantities in several resource classes simultaneously.
In order to assign recoverable resources of any class, a development plan needs to be defined consisting of one or more projects. Even for Prospective Resources, the estimates of recoverable quantities must be stated in terms of the sales products derived from a development program assuming successful discovery and commercial development. Given the major uncertainties involved at this early stage, the development program will not be of the detail expected in later stages of maturity. In most cases, recovery efficiency may be largely based on analogous projects. In-place quantities for which a feasible project cannot be defined using current, or reasonably forecast improvements in, technology are classified as Unrecoverable.
Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on a forecast of the conditions that will exist during the time period encompassed by the project’s activities. “Conditions” include technological, economic, legal, environmental, social, and governmental factors. While economic factors can be summarized as forecast costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and taxes.
The resource quantities being estimated are those volumes producible from a project as measured according to delivery specifications at the point of sale or custody transfer. The cumulative production from the evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project.
APPENDIX 2
1
Appendix 2 GLOSSARY OF TERMS AND ABBREVIATIONS
AAPG American Association of Petroleum Geologists ac-ft acre-feet API American Petroleum Institute AT after tax AZ azimuth B billion bbl(s) barrel(s) bbls/d barrels per day bopd barrels of oil per day BT before tax BTU British Thermal Unit Bscf billions of standard cubic feet bwpd barrels of water per day CAPEX capital expenditures CO2 Carbon dioxide condensate liquid hydrocarbons which are sometimes produced with natural gas and liquids
derived from natural gas cP centipoise F Fahrenheit temperature FBHP flowing bottom hole pressure FM DIP formation dip FTP flowing tubing pressure ft feet ftSS depth in feet below sea level GDT Gas Down To GIP Gas in Place GIIP Gas Initially in Place GOR gas/oil ratio GRV gross rock volume GWC gas water contact H2S Hydrogen sulfide HKW Highest known water hz frequency in hertz KB Kelly Bushing km kilometers km
2 square kilometers
LKO Lowest Known Oil M thousand m cementation factor M$ thousand US dollars MD measured depth mD permeability in millidarcies MDT modular formation dynamics tester MM million MM$ million US dollars MMscf/d millions of standard cubic feet per day mo month MOPU mobile oil production unit msec milliseconds MT measured thickness n saturation exponent NTG net to gross sand ratio NGL Natural Gas Liquids
2
NPV Net Present Value ohms unit of electrical resistance Ohm-m log resistivity OWC oil water contact PDNP Proved Developed Non-Producing PDP Proved Developed Producing PI productivity index Poss Possible ppm parts per million PRMS Petroleum Resources Management System Prob Probable PSI Proved Shut-In psi pounds per square inch psia pounds per square inch absolute psig pounds per square inch gauge psis pounds per square inch static PUD Proved Undeveloped PVD Proved PVT pressure volume temperature rb barrel(s) of oil at reservoir conditions rcf reservoir cubic feet RFT repeat formation tester Rw water resistivity SCAL Special Core Analysis scf standard cubic feet measured at 14.7 pounds per square inch and 60
o F
scfe Standard cubic feet equivalent scf/d standard cubic feet per day scf/stb standard cubic feet per stock tank barrel So oil saturation SPE Society of Petroleum Engineers SPEE Society of Petroleum Evaluation Engineers SS Subsea ST Sidetrack stb stock tank barrels measured at 14.7 pounds per square inch and 60
o F
stb/d stock tank barrels per day STOIIP stock tank oil initially in place Sw water saturation SWC side wall core THP tubing head pressure Tscf trillion standard cubic feet TST true subsea thickness TVDSS true vertical depth (sub-sea) TVT true vertical thickness TWT two-way time US$ United States Dollar VCL clay volume Vsh shale volume WC water cut WPC World Petroleum Congresses WUT Water Up To YE Year-End φ porosity µ viscosity 1P Proved Reserves 2P Proved Reserves + Probable Reserves 3D 3-dimensional seismic 3P Proved Reserves + Probable Reserves + Possible Reserves
APPENDIX 3
Appendix 3.1
Proved Total As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 7,173.2 10.179% 6,443.1 104.10 670,723.6 226,836.0 102,239.7 341,648.0 325,748.6
2013 6,841.5 10.066% 6,152.8 99.60 612,817.2 13,268.4 58,587.9 540,960.9 794,644.9
2014 6,464.9 9.925% 5,823.2 95.10 553,790.6 0.0 55,799.8 497,990.8 1,187,054.5
2015 6,141.7 9.789% 5,540.5 94.91 525,870.8 7,852.3 45,853.6 472,164.9 1,525,290.1
2016 5,994.2 9.722% 5,411.4 96.93 524,535.1 0.0 47,012.3 477,522.8 1,836,266.2
2017 5,898.3 9.677% 5,327.5 98.99 527,359.0 0.0 48,192.1 479,166.8 2,119,945.0
2018 4,828.7 9.052% 4,391.6 101.09 443,927.6 0.0 49,395.3 394,532.2 2,332,284.2
2019 3,943.2 8.278% 3,616.8 103.23 373,342.5 0.0 50,622.6 322,719.9 2,490,183.6
2020 3,207.2 7.615% 2,963.0 105.41 312,324.6 0.0 51,876.9 260,447.7 2,606,030.1
2021 2,557.4 7.009% 2,378.2 107.63 255,972.6 0.0 47,537.8 208,434.9 2,690,313.1
2022 2,014.8 6.203% 1,889.8 109.90 207,695.5 8,484.0 37,224.8 161,986.7 2,749,859.5
2023 1,672.2 5.712% 1,576.7 112.22 176,941.9 0.0 37,968.8 138,973.1 2,796,301.9
2024 1,388.0 5.602% 1,310.2 114.58 150,128.8 0.0 38,729.4 111,399.3 2,830,145.3
2025 1,110.4 5.439% 1,050.0 116.99 122,839.3 0.0 39,503.8 83,335.5 2,853,161.3
2026 888.3 5.237% 841.8 119.45 100,551.0 0.0 40,293.4 60,257.7 2,868,290.6
2027 710.6 5.000% 675.1 121.96 82,334.4 0.0 19,340.8 62,993.5 2,882,668.9
2028 568.5 5.000% 540.1 124.51 67,248.6 0.0 14,505.6 52,743.0 2,893,613.2
2029 454.8 5.000% 432.1 127.12 54,925.8 0.0 10,879.2 44,046.6 2,901,922.0
2030 363.8 5.000% 345.7 129.78 44,860.2 0.0 4,589.7 40,270.6 2,908,827.9
2031 267.0 5.000% 253.7 132.41 33,586.6 0.0 3,442.3 30,144.3 2,913,527.4
2032 0.0 5.000% 0.0 135.10 0.0 33,028.3 0.0 -33,028.3 2,908,846.4
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 2,908,846.4
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 2,908,846.4
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 2,908,846.4
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 2,908,846.4
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 2,908,846.4
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 2,908,846.4
Totals 62,488.7 56,963.1 5,841,775.6 289,468.9 803,595.9 4,748,710.8
PW 0.00% 4,748,710.8
PW 5.00% 3,636,561.4
PW 10.00% 2,908,846.4
PW 15.00% 2,406,060.7
PW 20.00% 2,042,911.2
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
1
Appendix 3.2
Proved Developed Producing As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 3,413.9 10.179% 3,066.4 104.10 319,216.4 102,181.3 59,530.3 157,504.8 150,175.0
2013 2,780.8 10.066% 2,500.9 99.60 249,086.6 2,667.2 29,088.9 217,330.5 338,553.6
2014 2,504.2 9.925% 2,255.7 95.10 214,515.9 0.0 28,016.9 186,498.9 485,512.1
2015 2,263.4 9.789% 2,041.8 94.91 193,796.5 5,622.0 20,140.9 168,033.5 605,883.0
2016 2,161.9 9.722% 1,951.7 96.93 189,182.3 0.0 20,445.7 168,736.7 715,769.0
2017 2,114.8 9.677% 1,910.1 98.99 189,079.7 0.0 21,364.3 167,715.3 815,060.7
2018 1,806.7 9.052% 1,643.2 101.09 166,101.3 0.0 21,991.3 144,110.0 892,621.4
2019 1,528.8 8.278% 1,402.2 103.23 144,746.0 0.0 22,369.5 122,376.5 952,497.4
2020 1,278.5 7.615% 1,181.2 105.41 124,502.4 0.0 22,409.1 102,093.3 997,908.2
2021 1,038.5 7.009% 965.7 107.63 103,945.6 0.0 18,349.4 85,596.2 1,032,520.0
2022 809.8 6.203% 759.5 109.90 83,476.0 7,541.0 9,306.2 66,628.8 1,057,012.8
2023 688.3 5.712% 649.0 112.22 72,829.3 0.0 9,492.2 63,337.1 1,078,179.0
2024 585.1 5.602% 552.3 114.58 63,282.0 0.0 9,682.4 53,599.6 1,094,462.7
2025 497.3 5.439% 470.2 116.99 55,015.2 0.0 9,116.3 45,898.9 1,107,139.2
2026 422.7 5.237% 400.6 119.45 47,847.7 0.0 9,670.4 38,177.3 1,116,724.7
2027 359.3 5.000% 341.3 121.96 41,627.9 0.0 4,500.0 37,127.9 1,125,199.1
2028 291.7 5.000% 277.2 124.51 34,510.6 0.0 7,505.6 27,005.0 1,130,802.7
2029 233.4 5.000% 221.7 127.12 28,186.8 0.0 5,879.2 22,307.6 1,135,010.8
2030 186.7 5.000% 177.4 129.78 23,021.4 0.0 2,304.0 20,717.4 1,138,563.5
2031 149.4 5.000% 141.9 132.41 18,790.2 0.0 1,843.2 16,947.0 1,141,205.6
2032 0.0 5.000% 0.0 135.10 0.0 9,588.9 0.0 -9,588.9 1,139,846.6
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 1,139,846.6
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 1,139,846.6
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 1,139,846.6
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 1,139,846.6
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 1,139,846.6
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 1,139,846.6
Totals 25,115.2 22,910.1 2,362,759.7 127,600.3 333,006.0 1,902,153.4
PW 0.00% 1,902,153.4
PW 5.00% 1,435,435.8
PW 10.00% 1,139,846.6
PW 15.00% 940,547.7
PW 20.00% 799,114.2
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
2
Appendix 3.3
Proved Developed Shut-In As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 1,825.0 10.179% 1,639.2 104.10 170,644.4 33,385.0 20,594.4 116,665.0 111,235.7
2013 1,825.0 10.066% 1,641.3 99.60 163,472.5 2,963.5 10,382.8 150,126.1 241,362.7
2014 1,825.0 9.925% 1,643.9 95.10 156,332.7 0.0 10,590.3 145,742.4 356,205.6
2015 1,825.0 9.789% 1,646.4 94.91 156,263.0 0.0 10,802.0 145,461.0 460,406.6
2016 1,825.0 9.722% 1,647.6 96.93 159,700.5 0.0 11,018.4 148,682.1 557,232.5
2017 1,825.0 9.677% 1,648.4 98.99 163,170.5 0.0 10,463.6 152,706.9 647,638.8
2018 1,460.0 9.052% 1,327.8 101.09 134,225.6 0.0 10,672.8 123,552.8 714,135.5
2019 1,172.4 8.278% 1,075.3 103.23 111,001.7 0.0 10,886.1 100,115.6 763,119.8
2020 914.5 7.615% 844.8 105.41 89,050.8 0.0 11,104.1 77,946.6 797,790.3
2021 713.3 7.009% 663.3 107.63 71,391.8 0.0 11,326.2 60,065.7 822,078.5
2022 556.4 6.203% 521.8 109.90 57,353.0 0.0 11,965.1 45,387.9 838,763.1
2023 434.0 5.712% 409.2 112.22 45,917.3 0.0 12,204.3 33,713.1 850,029.5
2024 338.5 5.602% 319.5 114.58 36,612.2 0.0 12,448.7 24,163.5 857,370.4
2025 264.0 5.439% 249.7 116.99 29,208.2 0.0 13,674.4 15,533.8 861,660.6
2026 205.9 5.237% 195.2 119.45 23,310.9 0.0 14,505.6 8,805.2 863,871.4
2027 162.1 5.000% 154.0 121.96 18,784.3 0.0 11,604.5 7,179.8 865,510.2
2028 0.0 5.000% 0.0 124.51 0.0 0.0 0.0 0.0 865,510.2
2029 0.0 5.000% 0.0 127.12 0.0 0.0 0.0 0.0 865,510.2
2030 0.0 5.000% 0.0 129.78 0.0 0.0 0.0 0.0 865,510.2
2031 0.0 5.000% 0.0 132.41 0.0 0.0 0.0 0.0 865,510.2
2032 0.0 5.000% 0.0 135.10 0.0 10,654.3 0.0 -10,654.3 864,000.2
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 864,000.2
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 864,000.2
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 864,000.2
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 864,000.2
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 864,000.2
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 864,000.2
Totals 17,171.0 15,627.4 1,586,439.4 47,002.8 194,243.4 1,345,193.2
PW 0.00% 1,345,193.2
PW 5.00% 1,061,230.8
PW 10.00% 864,000.2
PW 15.00% 722,296.3
PW 20.00% 617,302.9
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
3
Appendix 3.4
Proved Developed Non-Producing As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 0.0 10.179% 0.0 104.10 0.0 2,809.7 0.0 -2,809.7 -2,678.9
2013 0.0 10.066% 0.0 99.60 0.0 296.4 0.0 -296.4 -2,935.8
2014 0.0 9.925% 0.0 95.10 0.0 0.0 0.0 0.0 -2,935.8
2015 71.6 9.789% 64.6 94.91 6,130.6 427.3 1,080.2 4,623.1 376.0
2016 88.6 9.722% 79.9 96.93 7,749.5 0.0 1,101.8 6,647.6 4,705.1
2017 70.4 9.677% 63.5 98.99 6,290.7 0.0 1,162.6 5,128.0 7,741.1
2018 56.1 9.052% 51.0 101.09 5,154.8 0.0 1,185.9 3,969.0 9,877.2
2019 44.7 8.278% 41.0 103.23 4,230.7 0.0 1,209.6 3,021.1 11,355.3
2020 35.7 7.615% 33.0 105.41 3,476.2 0.0 1,233.8 2,242.4 12,352.7
2021 28.3 7.009% 26.4 107.63 2,836.6 0.0 1,258.5 1,578.1 12,990.9
2022 22.6 6.203% 21.2 109.90 2,329.9 0.0 1,329.5 1,000.4 13,358.6
2023 18.0 5.712% 17.0 112.22 1,905.8 0.0 1,356.0 549.8 13,542.3
2024 14.4 5.602% 13.6 114.58 1,556.3 0.0 1,383.2 173.2 13,595.0
2025 11.4 5.439% 10.8 116.99 1,264.7 0.0 1,519.4 -254.7 13,524.6
2026 5.2 5.237% 5.0 119.45 593.1 0.0 1,611.7 -1,018.6 13,268.9
2027 0.0 5.000% 0.0 121.96 0.0 0.0 0.0 0.0 13,268.9
2028 0.0 5.000% 0.0 124.51 0.0 0.0 0.0 0.0 13,268.9
2029 0.0 5.000% 0.0 127.12 0.0 0.0 0.0 0.0 13,268.9
2030 0.0 5.000% 0.0 129.78 0.0 0.0 0.0 0.0 13,268.9
2031 0.0 5.000% 0.0 132.41 0.0 0.0 0.0 0.0 13,268.9
2032 0.0 5.000% 0.0 135.10 0.0 1,065.4 0.0 -1,065.4 13,117.9
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 13,117.9
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 13,117.9
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 13,117.9
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 13,117.9
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 13,117.9
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 13,117.9
Totals 467.0 426.9 43,518.8 4,598.7 15,432.1 23,488.0
PW 0.00% 23,488.0
PW 5.00% 17,579.3
PW 10.00% 13,117.9
PW 15.00% 9,794.5
PW 20.00% 7,311.4
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
4
Appendix 3.5
Proved Undeveloped As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 1,934.3 10.179% 1,737.4 104.10 180,862.8 88,460.0 22,115.0 70,287.8 67,016.8
2013 2,235.7 10.066% 2,010.6 99.60 200,258.2 7,341.4 19,116.2 173,800.6 217,664.4
2014 2,135.6 9.925% 1,923.7 95.10 182,942.0 0.0 17,192.5 165,749.5 348,272.6
2015 1,981.7 9.789% 1,787.7 94.91 169,680.7 1,803.0 13,830.4 154,047.3 458,624.5
2016 1,918.7 9.722% 1,732.2 96.93 167,902.9 0.0 14,446.4 153,456.4 558,559.6
2017 1,888.2 9.677% 1,705.4 98.99 168,818.2 0.0 15,201.5 153,616.6 649,504.5
2018 1,505.9 9.052% 1,369.6 101.09 138,445.8 0.0 15,545.4 122,900.5 715,650.1
2019 1,197.3 8.278% 1,098.2 103.23 113,364.1 0.0 16,157.4 97,206.6 763,211.1
2020 978.6 7.615% 904.1 105.41 95,295.3 0.0 17,129.8 78,165.4 797,978.9
2021 777.3 7.009% 722.8 107.63 77,798.6 0.0 16,603.7 61,194.9 822,723.7
2022 626.0 6.203% 587.2 109.90 64,536.6 943.0 14,624.0 48,969.5 840,725.0
2023 532.0 5.712% 501.6 112.22 56,289.5 0.0 14,916.3 41,373.2 854,551.2
2024 450.0 5.602% 424.8 114.58 48,678.2 0.0 15,215.1 33,463.0 864,717.3
2025 337.6 5.439% 319.3 116.99 37,351.3 0.0 15,193.8 22,157.5 870,836.9
2026 254.4 5.237% 241.1 119.45 28,799.4 0.0 14,505.6 14,293.8 874,425.7
2027 189.2 5.000% 179.8 121.96 21,922.2 0.0 3,236.3 18,685.8 878,690.8
2028 276.8 5.000% 262.9 124.51 32,738.0 0.0 7,000.0 25,738.0 884,031.4
2029 221.4 5.000% 210.3 127.12 26,739.0 0.0 5,000.0 21,739.0 888,132.2
2030 177.1 5.000% 168.3 129.78 21,838.9 0.0 2,285.7 19,553.2 891,485.4
2031 117.6 5.000% 111.7 132.41 14,796.3 0.0 1,599.1 13,197.3 893,542.8
2032 0.0 5.000% 0.0 135.10 0.0 11,719.7 0.0 -11,719.7 891,881.8
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 891,881.8
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 891,881.8
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 891,881.8
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 891,881.8
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 891,881.8
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 891,881.8
Totals 19,735.5 17,998.8 1,849,057.8 110,267.1 260,914.3 1,477,876.3
PW 0.00% 1,477,876.3
PW 5.00% 1,122,315.6
PW 10.00% 891,881.8
PW 15.00% 733,422.2
PW 20.00% 619,182.7
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
5
Appendix 3.6
Proved plus Probable As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 7,350.8 10.286% 6,594.7 104.10 686,505.9 226,836.0 102,028.8 357,641.1 340,997.4
2013 7,477.5 10.366% 6,702.4 99.60 667,555.6 31,555.6 89,839.6 546,160.3 814,400.5
2014 7,130.9 10.165% 6,406.0 95.10 609,211.2 0.0 83,479.8 525,731.4 1,228,669.3
2015 6,888.8 10.083% 6,194.2 94.91 587,920.3 0.0 82,157.2 505,763.1 1,590,973.0
2016 6,446.5 9.917% 5,807.2 96.93 562,895.4 10,257.8 60,170.3 492,467.3 1,911,681.3
2017 6,363.3 9.883% 5,734.4 98.99 567,633.1 0.0 61,373.1 506,260.0 2,211,400.1
2018 6,296.5 9.856% 5,676.0 101.09 573,758.8 0.0 62,600.1 511,158.7 2,486,508.1
2019 5,279.9 9.347% 4,786.4 103.23 494,074.3 0.0 63,851.6 430,222.7 2,697,006.2
2020 4,426.2 8.738% 4,039.4 105.41 425,787.2 0.0 65,130.3 360,656.9 2,857,425.4
2021 3,743.1 8.052% 3,441.7 107.63 370,447.0 0.0 66,432.2 304,014.8 2,980,357.2
2022 3,186.7 7.599% 2,944.6 109.90 323,620.2 0.0 53,299.4 270,320.7 3,079,727.4
2023 2,660.0 7.124% 2,470.5 112.22 277,243.3 0.0 53,037.1 224,206.2 3,154,653.3
2024 2,252.9 6.604% 2,104.1 114.58 241,096.4 0.0 54,099.4 186,997.0 3,211,463.5
2025 1,944.0 6.065% 1,826.1 116.99 213,636.7 0.0 55,180.9 158,455.8 3,255,226.4
2026 1,636.0 5.700% 1,542.7 119.45 184,278.7 0.0 50,918.4 133,360.2 3,288,710.1
2027 1,328.8 5.573% 1,254.8 121.96 153,030.7 9,545.6 30,220.0 113,265.1 3,314,563.0
2028 1,156.1 5.472% 1,092.8 124.51 136,073.9 0.0 15,110.0 120,963.9 3,339,663.1
2029 1,005.8 5.355% 951.9 127.12 121,012.9 0.0 11,332.5 109,680.4 3,360,353.0
2030 814.7 5.145% 772.8 129.78 100,293.8 0.0 5,194.1 95,099.7 3,376,661.5
2031 659.9 5.000% 626.9 132.41 83,011.0 0.0 3,895.6 79,115.4 3,388,995.5
2032 541.1 5.000% 514.1 135.10 69,447.9 0.0 2,921.7 66,526.2 3,398,424.0
2033 443.7 5.000% 421.5 137.83 58,100.5 0.0 2,191.2 55,909.3 3,405,627.5
2034 363.9 5.000% 345.7 140.62 48,607.0 0.0 1,643.4 46,963.6 3,411,128.3
2035 298.4 5.000% 283.4 143.47 40,664.6 0.0 1,232.6 39,432.0 3,415,327.0
2036 247.0 5.000% 234.7 146.37 34,346.1 0.0 924.4 33,421.7 3,418,562.3
2037 0.0 5.000% 0.0 149.33 0.0 35,573.1 0.0 -35,573.1 3,415,431.8
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 3,415,431.8
Totals 79,942.4 72,768.9 7,630,252.5 313,768.1 1,078,263.9 6,238,220.5
PW 0.00% 6,238,220.5
PW 5.00% 4,465,381.7
PW 10.00% 3,415,431.8
PW 15.00% 2,740,328.3
PW 20.00% 2,277,508.8
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
Before Income Tax Analysis
Present Worth Profile ($M)
6
Appendix 3.7
Probable As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 177.6 14.623% 151.6 104.10 15,782.3 0.0 -210.9 15,993.1 15,248.9
2013 636.0 13.591% 549.6 99.60 54,738.3 18,287.2 31,251.7 5,199.4 19,755.6
2014 666.0 12.500% 582.8 95.10 55,420.6 0.0 27,680.0 27,740.6 41,614.8
2015 747.1 12.500% 653.7 94.91 62,049.5 -7,852.3 36,303.6 33,598.2 65,682.9
2016 452.3 12.500% 395.7 96.93 38,360.3 10,257.8 13,158.0 14,944.5 75,415.2
2017 465.0 12.500% 406.9 98.99 40,274.2 0.0 13,181.0 27,093.2 91,455.0
2018 1,467.9 12.500% 1,284.4 101.09 129,831.2 0.0 13,204.8 116,626.4 154,223.9
2019 1,336.7 12.500% 1,169.6 103.23 120,731.8 0.0 13,229.0 107,502.8 206,822.6
2020 1,219.0 11.694% 1,076.4 105.41 113,462.6 0.0 13,253.4 100,209.1 251,395.3
2021 1,185.7 10.302% 1,063.6 107.63 114,474.4 0.0 18,894.4 95,580.0 290,044.2
2022 1,172.0 10.000% 1,054.8 109.90 115,924.7 -8,484.0 16,074.6 108,334.1 329,867.9
2023 987.8 9.515% 893.8 112.22 100,301.4 0.0 15,068.3 85,233.1 358,351.3
2024 864.9 8.214% 793.9 114.58 90,967.7 0.0 15,370.0 75,597.7 381,318.1
2025 833.6 6.898% 776.1 116.99 90,797.4 0.0 15,677.1 75,120.3 402,065.1
2026 747.7 6.250% 700.9 119.45 83,727.7 0.0 10,625.1 73,102.6 420,419.5
2027 618.2 6.231% 579.7 121.96 70,696.3 9,545.6 10,879.2 50,271.5 431,894.0
2028 587.6 5.928% 552.7 124.51 68,825.4 0.0 604.4 68,221.0 446,050.0
2029 551.0 5.648% 519.9 127.12 66,087.1 0.0 453.3 65,633.8 458,431.0
2030 450.8 5.263% 427.1 129.78 55,433.5 0.0 604.4 54,829.1 467,833.5
2031 392.9 5.000% 373.3 132.41 49,424.4 0.0 453.3 48,971.1 475,468.1
2032 541.1 5.000% 514.1 135.10 69,447.9 -33,028.3 2,921.7 99,554.5 489,577.6
2033 443.7 5.000% 421.5 137.83 58,100.5 0.0 2,191.2 55,909.3 496,781.0
2034 363.9 5.000% 345.7 140.62 48,607.0 0.0 1,643.4 46,963.6 502,281.8
2035 298.4 5.000% 283.4 143.47 40,664.6 0.0 1,232.6 39,432.0 506,480.6
2036 247.0 5.000% 234.7 146.37 34,346.1 0.0 924.4 33,421.7 509,715.8
2037 0.0 5.000% 0.0 149.33 0.0 35,573.1 0.0 -35,573.1 506,585.4
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 506,585.4
Totals 17,453.7 15,805.8 1,788,476.9 24,299.1 274,668.1 1,489,509.7
PW 0.00% 1,489,509.7
PW 5.00% 828,820.2
PW 10.00% 506,585.4
PW 15.00% 334,267.6
PW 20.00% 234,597.5
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Before Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
7
Appendix 3.8
Proved plus Probable plus Possible As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 7,495.2 10.377% 6,717.5 104.10 699,286.6 226734.2 102,028.8 370,523.6 353,280.4
2013 7,865.7 10.595% 7,032.3 99.60 700,421.9 31,555.6 89,839.2 579,027.0 855,171.8
2014 7,399.5 10.317% 6,636.0 95.10 631,086.7 0.0 83,479.8 547,606.9 1,286,678.2
2015 7,074.1 10.146% 6,356.4 94.91 603,313.1 0.0 82,157.0 521,156.1 1,660,008.7
2016 6,782.0 10.045% 6,100.8 96.93 591,354.3 435.8 68,848.8 522,069.6 1,999,994.9
2017 6,539.1 9.954% 5,888.2 98.99 582,857.4 12,342.0 61,373.1 509,142.3 2,301,420.0
2018 6,500.7 9.939% 5,854.6 101.09 591,813.0 0.0 62,600.1 529,212.9 2,586,244.9
2019 6,357.6 9.881% 5,729.4 103.23 591,416.3 0.0 63,851.6 527,564.6 2,844,370.2
2020 5,259.3 9.334% 4,768.4 105.41 502,621.9 0.0 65,130.3 437,491.6 3,038,965.3
2021 4,372.8 8.692% 3,992.7 107.63 429,745.7 0.0 66,432.2 363,313.5 3,185,875.2
2022 3,635.9 7.921% 3,347.9 109.90 367,948.7 0.0 53,299.4 314,649.3 3,301,540.6
2023 3,048.9 7.491% 2,820.5 112.22 316,520.7 0.0 53,037.1 263,483.5 3,389,592.3
2024 2,534.9 6.982% 2,357.9 114.58 270,171.6 0.0 54,099.4 216,072.2 3,455,235.6
2025 2,049.9 6.268% 1,921.4 116.99 224,787.5 0.0 45,998.2 178,789.4 3,504,614.4
2026 1,693.9 5.719% 1,597.1 119.45 190,770.5 8,763.0 40,293.4 141,714.1 3,540,195.5
2027 1,456.8 5.632% 1,374.7 121.96 167,659.6 0.0 36,264.0 131,395.6 3,570,186.7
2028 1,252.8 5.532% 1,183.5 124.51 147,367.4 0.0 32,637.6 114,729.8 3,593,993.3
2029 1,077.4 5.415% 1,019.1 127.12 129,551.0 0.0 29,373.9 100,177.1 3,612,890.4
2030 948.1 5.301% 897.9 129.78 116,530.9 0.0 26,436.5 90,094.5 3,628,340.6
2031 834.4 5.171% 791.2 132.41 104,768.0 0.0 23,792.8 80,975.2 3,640,964.5
2032 734.2 5.024% 697.4 135.10 94,209.4 0.0 21,413.5 72,795.8 3,651,281.6
2033 653.5 5.000% 620.8 137.83 85,566.2 0.0 19,272.2 66,294.0 3,659,823.1
2034 581.6 5.000% 552.5 140.62 77,695.8 0.0 17,345.0 60,350.8 3,666,891.9
2035 494.4 5.000% 469.6 143.47 67,378.2 0.0 15,610.5 51,767.7 3,672,404.2
2036 425.0 5.000% 403.8 146.37 59,097.6 0.0 14,049.4 45,048.1 3,676,764.9
2037 0.0 5.000% 0.0 149.33 0.0 37,195.4 0.0 -37,195.4 3,673,491.6
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 3,673,491.6
Totals 87,067.6 79,131.4 8,343,940.0 317,026.1 1,228,664.0 6,798,250.0
PW 0.00% 6,798,250.0
PW 5.00% 4,832,682.4
RPS PW 10.00% 3,673,491.6
JWH PW 15.00% 2,931,479.3
27-Mar-12 PW 20.00% 2,425,271.2
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Before Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
8
Appendix 3.9
Possible As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M
2012 144.4 15.000% 122.8 104.10 12,780.7 -101.8 0.0 12,882.5 12,283.0
2013 388.2 15.000% 330.0 99.60 32,866.3 0.0 -0.4 32,866.7 40,771.3
2014 268.6 14.356% 230.0 95.10 21,875.5 0.0 0.0 21,875.5 58,008.9
2015 185.3 12.500% 162.2 94.91 15,392.8 0.0 -0.2 15,393.0 69,035.7
2016 335.5 12.500% 293.6 96.93 28,458.8 -9,822.0 8,678.5 29,602.3 88,313.5
2017 175.8 12.500% 153.8 98.99 15,224.3 12,342.0 0.0 2,882.3 90,019.9
2018 204.1 12.500% 178.6 101.09 18,054.3 0.0 0.0 18,054.3 99,736.8
2019 1,077.7 12.500% 943.0 103.23 97,342.0 0.0 0.0 97,342.0 147,364.0
2020 833.1 12.500% 728.9 105.41 76,834.8 0.0 0.0 76,834.8 181,539.9
2021 629.6 12.500% 550.9 107.63 59,298.7 0.0 0.0 59,298.7 205,518.0
2022 449.1 10.200% 403.3 109.90 44,328.6 0.0 0.0 44,328.6 221,813.2
2023 388.9 10.000% 350.0 112.22 39,277.3 0.0 0.0 39,277.3 234,939.0
2024 281.9 10.000% 253.7 114.58 29,075.1 0.0 0.0 29,075.1 243,772.1
2025 105.9 10.000% 95.3 116.99 11,150.9 0.0 -9,182.7 20,333.6 249,388.0
2026 58.0 6.250% 54.3 119.45 6,491.8 8,763.0 -10,625.1 8,353.9 251,485.4
2027 127.9 6.250% 120.0 121.96 14,628.9 -9,545.6 6,044.0 18,130.5 255,623.7
2028 96.7 6.250% 90.7 124.51 11,293.5 0.0 17,527.6 -6,234.1 254,330.1
2029 71.6 6.250% 67.2 127.12 8,538.0 0.0 18,041.4 -9,503.3 252,537.4
2030 133.5 6.250% 125.1 129.78 16,237.1 0.0 21,242.4 -5,005.3 251,679.1
2031 174.5 5.819% 164.3 132.41 21,757.1 0.0 19,897.3 1,859.8 251,969.0
2032 193.1 5.092% 183.3 135.10 24,761.5 0.0 18,491.9 6,269.6 252,857.6
2033 209.8 5.000% 199.3 137.83 27,465.7 0.0 17,081.0 10,384.7 254,195.6
2034 217.7 5.000% 206.9 140.62 29,088.8 0.0 15,701.5 13,387.2 255,763.6
2035 196.0 5.000% 186.2 143.47 26,713.7 0.0 14,377.9 12,335.8 257,077.2
2036 178.0 5.000% 169.1 146.37 24,751.4 0.0 13,125.0 11,626.4 258,202.6
2037 0.0 5.000% 0.0 149.33 0.0 1,622.3 0.0 -1,622.3 258,059.8
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 258,059.8
Totals 7,125.2 6,362.5 713,687.5 3,258.0 150,400.0 560,029.5
PW 0.00% 560,029.5
PW 5.00% 367,300.7
RPS PW 10.00% 258,059.8
JWH PW 15.00% 191,151.0
27-Mar-12 PW 20.00% 147,762.4
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Before Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
9
APPENDIX 4
Appendix 4.1
Proved Total As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 7,173.2 10.179% 6,443.1 104.10 670,723.6 226,836.0 102,239.7 341,648.0 47,817.4 293,830.5 280,156.4
2013 6,841.5 10.066% 6,152.8 99.60 612,817.2 13,268.4 58,587.9 540,960.9 106,650.8 434,310.1 656,609.5
2014 6,464.9 9.925% 5,823.2 95.10 553,790.6 0.0 55,799.8 497,990.8 337,022.8 160,968.0 783,450.0
2015 6,141.7 9.789% 5,540.5 94.91 525,870.8 7,852.3 45,853.6 472,164.9 306,282.3 165,882.6 902,280.0
2016 5,994.2 9.722% 5,411.4 96.93 524,535.1 0.0 47,012.3 477,522.8 285,588.4 191,934.4 1,027,273.0
2017 5,898.3 9.677% 5,327.5 98.99 527,359.0 0.0 48,192.1 479,166.8 290,564.1 188,602.8 1,138,930.7
2018 4,828.7 9.052% 4,391.6 101.09 443,927.6 0.0 49,395.3 394,532.2 286,168.5 108,363.8 1,197,252.5
2019 3,943.2 8.278% 3,616.8 103.23 373,342.5 0.0 50,622.6 322,719.9 220,467.0 102,252.9 1,247,282.5
2020 3,207.2 7.615% 2,963.0 105.41 312,324.6 0.0 51,876.9 260,447.7 158,503.3 101,944.5 1,292,627.2
2021 2,557.4 7.009% 2,378.2 107.63 255,972.6 0.0 47,537.8 208,434.9 109,066.9 99,368.0 1,332,807.7
2022 2,014.8 6.203% 1,889.8 109.90 207,695.5 8,484.0 37,224.8 161,986.7 73,316.9 88,669.7 1,365,402.8
2023 1,672.2 5.712% 1,576.7 112.22 176,941.9 0.0 37,968.8 138,973.1 47,775.8 91,197.3 1,395,879.4
2024 1,388.0 5.602% 1,310.2 114.58 150,128.8 0.0 38,729.4 111,399.3 32,423.4 78,975.9 1,419,872.5
2025 1,110.4 5.439% 1,050.0 116.99 122,839.3 0.0 39,503.8 83,335.5 18,514.0 64,821.5 1,437,775.2
2026 888.3 5.237% 841.8 119.45 100,551.0 0.0 40,293.4 60,257.7 5,749.0 54,508.6 1,451,461.0
2027 710.6 5.000% 675.1 121.96 82,334.4 0.0 19,340.8 62,993.5 728.0 62,265.6 1,465,673.2
2028 568.5 5.000% 540.1 124.51 67,248.6 0.0 14,505.6 52,743.0 728.0 52,015.0 1,476,466.4
2029 454.8 5.000% 432.1 127.12 54,925.8 0.0 10,879.2 44,046.6 0.0 44,046.6 1,484,775.2
2030 363.8 5.000% 345.7 129.78 44,860.2 0.0 4,589.7 40,270.6 0.0 40,270.6 1,491,681.2
2031 267.0 5.000% 253.7 132.41 33,586.6 0.0 3,442.3 30,144.3 0.0 30,144.3 1,496,380.6
2032 0.0 5.000% 0.0 135.10 0.0 33,028.3 0.0 -33,028.3 0.0 -33,028.3 1,491,699.6
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 1,491,699.6
Totals 62,488.7 56,963.1 5,841,775.6 289,468.9 803,595.9 4,748,710.8 2,327,366.6 2,421,344.3
PW 0.00% 2,421,344.3
PW 5.00% 1,846,280.5
PW 10.00% 1,491,699.6
PW 15.00% 1,256,852.9
PW 20.00% 1,091,682.2
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
1
Appendix 4.2
Proved Developed Producing As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 3,413.9 10.179% 3,066.4 104.10 319,216.4 102,181.3 59,530.3 157,504.8 3,116.1 154,388.7 147,203.8
2013 2,780.8 10.066% 2,500.9 99.60 249,086.6 2,667.2 29,088.9 217,330.5 35,107.2 182,223.3 305,152.1
2014 2,504.2 9.925% 2,255.7 95.10 214,515.9 0.0 28,016.9 186,498.9 62,263.0 124,235.9 403,048.2
2015 2,263.4 9.789% 2,041.8 94.91 193,796.5 5,622.0 20,140.9 168,033.5 59,498.1 108,535.5 480,797.7
2016 2,161.9 9.722% 1,951.7 96.93 189,182.3 0.0 20,445.7 168,736.7 51,968.5 116,768.1 556,840.3
2017 2,114.8 9.677% 1,910.1 98.99 189,079.7 0.0 21,364.3 167,715.3 51,685.7 116,029.6 625,532.8
2018 1,806.7 9.052% 1,643.2 101.09 166,101.3 0.0 21,991.3 144,110.0 46,342.0 97,768.0 678,152.0
2019 1,528.8 8.278% 1,402.2 103.23 144,746.0 0.0 22,369.5 122,376.5 34,831.2 87,545.2 720,985.8
2020 1,278.5 7.615% 1,181.2 105.41 124,502.4 0.0 22,409.1 102,093.3 25,702.4 76,390.9 754,964.3
2021 1,038.5 7.009% 965.7 107.63 103,945.6 0.0 18,349.4 85,596.2 16,681.9 68,914.3 782,830.6
2022 809.8 6.203% 759.5 109.90 83,476.0 7,541.0 9,306.2 66,628.8 8,352.1 58,276.7 804,253.2
2023 688.3 5.712% 649.0 112.22 72,829.3 0.0 9,492.2 63,337.1 2,853.9 60,483.2 824,465.6
2024 585.1 5.602% 552.3 114.58 63,282.0 0.0 9,682.4 53,599.6 827.3 52,772.3 840,498.0
2025 497.3 5.439% 470.2 116.99 55,015.2 0.0 9,116.3 45,898.9 0.0 45,898.9 853,174.5
2026 422.7 5.237% 400.6 119.45 47,847.7 0.0 9,670.4 38,177.3 0.0 38,177.3 862,759.9
2027 359.3 5.000% 341.3 121.96 41,627.9 0.0 4,500.0 37,127.9 0.0 37,127.9 871,234.4
2028 291.7 5.000% 277.2 124.51 34,510.6 0.0 7,505.6 27,005.0 0.0 27,005.0 876,838.0
2029 233.4 5.000% 221.7 127.12 28,186.8 0.0 5,879.2 22,307.6 0.0 22,307.6 881,046.0
2030 186.7 5.000% 177.4 129.78 23,021.4 0.0 2,304.0 20,717.4 0.0 20,717.4 884,598.8
2031 149.4 5.000% 141.9 132.41 18,790.2 0.0 1,843.2 16,947.0 0.0 16,947.0 887,240.9
2032 0.0 5.000% 0.0 135.10 0.0 9,588.9 0.0 -9,588.9 0.0 -9,588.9 885,881.9
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 885,881.9
Totals 25,115.2 22,910.1 2,362,759.7 127,600.3 333,006.0 1,902,153.4 399,229.5 1,502,923.9
PW 0.00% 1,502,923.9
PW 5.00% 1,120,790.1
PW 10.00% 885,881.9
PW 15.00% 731,330.0
PW 20.00% 623,703.9
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
2
Appendix 4.3
Proved Developed Shut-In As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 1,825.0 10.179% 1,639.2 104.10 170,644.4 33,385.0 20,594.4 116,665.0 21,539.0 95,126.0 90,699.1
2013 1,825.0 10.066% 1,641.3 99.60 163,472.5 2,963.5 10,382.8 150,126.1 39,042.0 111,084.1 186,985.0
2014 1,825.0 9.925% 1,643.9 95.10 156,332.7 0.0 10,590.3 145,742.4 130,107.3 15,635.1 199,305.3
2015 1,825.0 9.789% 1,646.4 94.91 156,263.0 0.0 10,802.0 145,461.0 124,466.5 20,994.5 214,344.7
2016 1,825.0 9.722% 1,647.6 96.93 159,700.5 0.0 11,018.4 148,682.1 117,295.9 31,386.2 234,784.2
2017 1,825.0 9.677% 1,648.4 98.99 163,170.5 0.0 10,463.6 152,706.9 122,149.4 30,557.4 252,875.0
2018 1,460.0 9.052% 1,327.8 101.09 134,225.6 0.0 10,672.8 123,552.8 118,214.2 5,338.6 255,748.3
2019 1,172.4 8.278% 1,075.3 103.23 111,001.7 0.0 10,886.1 100,115.6 90,218.9 9,896.8 260,590.5
2020 914.5 7.615% 844.8 105.41 89,050.8 0.0 11,104.1 77,946.6 62,573.8 15,372.8 267,428.3
2021 713.3 7.009% 663.3 107.63 71,391.8 0.0 11,326.2 60,065.7 41,459.7 18,605.9 274,951.8
2022 556.4 6.203% 521.8 109.90 57,353.0 0.0 11,965.1 45,387.9 27,098.3 18,289.6 281,675.1
2023 434.0 5.712% 409.2 112.22 45,917.3 0.0 12,204.3 33,713.1 15,288.1 18,425.0 287,832.4
2024 338.5 5.602% 319.5 114.58 36,612.2 0.0 12,448.7 24,163.5 9,277.1 14,886.4 292,354.9
2025 264.0 5.439% 249.7 116.99 29,208.2 0.0 13,674.4 15,533.8 4,552.2 10,981.5 295,387.8
2026 205.9 5.237% 195.2 119.45 23,310.9 0.0 14,505.6 8,805.2 1,108.2 7,697.1 297,320.4
2027 162.1 5.000% 154.0 121.96 18,784.3 0.0 11,604.5 7,179.8 109.4 7,070.4 298,934.2
2028 0.0 5.000% 0.0 124.51 0.0 0.0 0.0 0.0 0.0 0.0 298,934.2
2029 0.0 5.000% 0.0 127.12 0.0 0.0 0.0 0.0 0.0 0.0 298,934.2
2030 0.0 5.000% 0.0 129.78 0.0 0.0 0.0 0.0 0.0 0.0 298,934.2
2031 0.0 5.000% 0.0 132.41 0.0 0.0 0.0 0.0 0.0 0.0 298,934.2
2032 0.0 5.000% 0.0 135.10 0.0 10,654.3 0.0 -10,654.3 0.0 -10,654.3 297,424.2
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 297,424.2
Totals 17,171.0 15,627.4 1,586,439.4 47,002.8 194,243.4 1,345,193.2 924,500.1 420,693.0
PW 0.00% 420,693.0
PW 5.00% 347,229.5
PW 10.00% 297,424.2
PW 15.00% 262,203.7
PW 20.00% 236,215.4
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
3
Appendix 4.4
Proved Developed Non-Producing As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 0.0 10.179% 0.0 104.10 0.0 2,809.7 0.0 -2,809.7 0.0 -2,809.7 -2,678.9
2013 0.0 10.066% 0.0 99.60 0.0 296.4 0.0 -296.4 0.0 -296.4 -2,935.8
2014 0.0 9.925% 0.0 95.10 0.0 0.0 0.0 0.0 0.0 0.0 -2,935.8
2015 71.6 9.789% 64.6 94.91 6,130.6 427.3 1,080.2 4,623.1 2,099.2 2,523.9 -1,127.8
2016 88.6 9.722% 79.9 96.93 7,749.5 0.0 1,101.8 6,647.6 2,783.0 3,864.6 1,389.0
2017 70.4 9.677% 63.5 98.99 6,290.7 0.0 1,162.6 5,128.0 2,176.7 2,951.3 3,136.2
2018 56.1 9.052% 51.0 101.09 5,154.8 0.0 1,185.9 3,969.0 2,015.2 1,953.8 4,187.8
2019 44.7 8.278% 41.0 103.23 4,230.7 0.0 1,209.6 3,021.1 1,444.7 1,576.4 4,959.1
2020 35.7 7.615% 33.0 105.41 3,476.2 0.0 1,233.8 2,242.4 955.3 1,287.1 5,531.6
2021 28.3 7.009% 26.4 107.63 2,836.6 0.0 1,258.5 1,578.1 578.0 1,000.1 5,935.9
2022 22.6 6.203% 21.2 109.90 2,329.9 0.0 1,329.5 1,000.4 317.0 683.5 6,187.2
2023 18.0 5.712% 17.0 112.22 1,905.8 0.0 1,356.0 549.8 132.3 417.5 6,326.7
2024 14.4 5.602% 13.6 114.58 1,556.3 0.0 1,383.2 173.2 35.3 137.9 6,368.6
2025 11.4 5.439% 10.8 116.99 1,264.7 0.0 1,519.4 -254.7 -39.6 -215.1 6,309.2
2026 5.2 5.237% 5.0 119.45 593.1 0.0 1,611.7 -1,018.6 -68.0 -950.6 6,070.5
2027 0.0 5.000% 0.0 121.96 0.0 0.0 0.0 0.0 0.0 0.0 6,070.5
2028 0.0 5.000% 0.0 124.51 0.0 0.0 0.0 0.0 0.0 0.0 6,070.5
2029 0.0 5.000% 0.0 127.12 0.0 0.0 0.0 0.0 0.0 0.0 6,070.5
2030 0.0 5.000% 0.0 129.78 0.0 0.0 0.0 0.0 0.0 0.0 6,070.5
2031 0.0 5.000% 0.0 132.41 0.0 0.0 0.0 0.0 0.0 0.0 6,070.5
2032 0.0 5.000% 0.0 135.10 0.0 1,065.4 0.0 -1,065.4 0.0 -1,065.4 5,919.5
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 5,919.5
Totals 467.0 426.9 43,518.8 4,598.7 15,432.1 23,488.0 12,429.1 11,058.9
PW 0.00% 11,058.9
PW 5.00% 8,216.1
PW 10.00% 5,919.5
PW 15.00% 4,160.3
PW 20.00% 2,831.1
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
4
Appendix 4.5
Proved Undeveloped As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 1,934.3 10.179% 1,737.4 104.10 180,862.8 88,460.0 22,115.0 70,287.8 12,985.6 57,302.2 54,635.5
2013 2,235.7 10.066% 2,010.6 99.60 200,258.2 7,341.4 19,116.2 173,800.6 45,229.7 128,570.9 166,078.8
2014 2,135.6 9.925% 1,923.7 95.10 182,942.0 0.0 17,192.5 165,749.5 148,069.0 17,680.5 180,010.8
2015 1,981.7 9.789% 1,787.7 94.91 169,680.7 1,803.0 13,830.4 154,047.3 131,903.5 22,143.8 195,873.5
2016 1,918.7 9.722% 1,732.2 96.93 167,902.9 0.0 14,446.4 153,456.4 121,145.0 32,311.4 216,915.6
2017 1,888.2 9.677% 1,705.4 98.99 168,818.2 0.0 15,201.5 153,616.6 122,961.0 30,655.7 235,064.5
2018 1,505.9 9.052% 1,369.6 101.09 138,445.8 0.0 15,545.4 122,900.5 117,670.3 5,230.2 237,879.4
2019 1,197.3 8.278% 1,098.2 103.23 113,364.1 0.0 16,157.4 97,206.6 87,657.2 9,549.4 242,551.7
2020 978.6 7.615% 904.1 105.41 95,295.3 0.0 17,129.8 78,165.4 62,792.3 15,373.2 249,389.7
2021 777.3 7.009% 722.8 107.63 77,798.6 0.0 16,603.7 61,194.9 42,268.0 18,926.9 257,043.0
2022 626.0 6.203% 587.2 109.90 64,536.6 943.0 14,624.0 48,969.5 29,256.6 19,712.9 264,289.5
2023 532.0 5.712% 501.6 112.22 56,289.5 0.0 14,916.3 41,373.2 18,774.6 22,598.6 271,841.5
2024 450.0 5.602% 424.8 114.58 48,678.2 0.0 15,215.1 33,463.0 12,856.3 20,606.8 278,101.9
2025 337.6 5.439% 319.3 116.99 37,351.3 0.0 15,193.8 22,157.5 6,497.8 15,659.7 282,426.9
2026 254.4 5.237% 241.1 119.45 28,799.4 0.0 14,505.6 14,293.8 1,800.1 12,493.7 285,563.7
2027 189.2 5.000% 179.8 121.96 21,922.2 0.0 3,236.3 18,685.8 285.0 18,400.8 289,763.7
2028 276.8 5.000% 262.9 124.51 32,738.0 0.0 7,000.0 25,738.0 468.9 25,269.1 295,007.1
2029 221.4 5.000% 210.3 127.12 26,739.0 0.0 5,000.0 21,739.0 0.0 21,739.0 299,107.9
2030 177.1 5.000% 168.3 129.78 21,838.9 0.0 2,285.7 19,553.2 0.0 19,553.2 302,461.1
2031 117.6 5.000% 111.7 132.41 14,796.3 0.0 1,599.1 13,197.3 0.0 13,197.3 304,518.5
2032 0.0 5.000% 0.0 135.10 0.0 11,719.7 0.0 -11,719.7 0.0 -11,719.7 302,857.5
2033 0.0 5.000% 0.0 137.83 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
2034 0.0 5.000% 0.0 140.62 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
2035 0.0 5.000% 0.0 143.47 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
2036 0.0 5.000% 0.0 146.37 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
2037 0.0 5.000% 0.0 149.33 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 302,857.5
Totals 19,735.5 17,998.8 1,849,057.8 110,267.1 260,914.3 1,477,876.3 962,620.8 515,255.5
PW 0.00% 515,255.5
PW 5.00% 379,683.6
PW 10.00% 302,857.5
PW 15.00% 255,198.5
PW 20.00% 223,156.4
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
5
Appendix 4.6
Proved plus Probable As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 7,350.8 10.286% 6,594.7 104.10 686,505.9 226,836.0 102,028.8 357,641.1 49,690.1 307,951.1 293,619.8
2013 7,477.5 10.366% 6,702.4 99.60 667,555.6 31,555.6 89,839.6 546,160.3 133,496.6 412,663.7 651,310.1
2014 7,130.9 10.165% 6,406.0 95.10 609,211.2 0.0 83,479.8 525,731.4 349,037.8 176,693.6 790,542.2
2015 6,888.8 10.083% 6,194.2 94.91 587,920.3 0.0 82,157.2 505,763.1 330,148.8 175,614.3 916,343.6
2016 6,446.5 9.917% 5,807.2 96.93 562,895.4 10,257.8 60,170.3 492,467.3 315,746.1 176,721.1 1,031,429.3
2017 6,363.3 9.883% 5,734.4 98.99 567,633.1 0.0 61,373.1 506,260.0 305,138.5 201,121.6 1,150,498.3
2018 6,296.5 9.856% 5,676.0 101.09 573,758.8 0.0 62,600.1 511,158.7 315,588.1 195,570.6 1,255,755.4
2019 5,279.9 9.347% 4,786.4 103.23 494,074.3 0.0 63,851.6 430,222.7 311,728.8 118,493.9 1,313,731.7
2020 4,426.2 8.738% 4,039.4 105.41 425,787.2 0.0 65,130.3 360,656.9 254,734.1 105,922.7 1,360,845.9
2021 3,743.1 8.052% 3,441.7 107.63 370,447.0 0.0 66,432.2 304,014.8 193,684.7 110,330.2 1,405,459.1
2022 3,186.7 7.599% 2,944.6 109.90 323,620.2 0.0 53,299.4 270,320.7 148,567.9 121,752.8 1,450,215.6
2023 2,660.0 7.124% 2,470.5 112.22 277,243.3 0.0 53,037.1 224,206.2 115,932.0 108,274.2 1,486,398.9
2024 2,252.9 6.604% 2,104.1 114.58 241,096.4 0.0 54,099.4 186,997.0 84,442.9 102,554.2 1,517,555.2
2025 1,944.0 6.065% 1,826.1 116.99 213,636.7 0.0 55,180.9 158,455.8 61,585.8 96,870.0 1,544,309.1
2026 1,636.0 5.700% 1,542.7 119.45 184,278.7 0.0 50,918.4 133,360.2 44,430.8 88,929.4 1,566,637.2
2027 1,328.8 5.573% 1,254.8 121.96 153,030.7 9,545.6 30,220.0 113,265.1 32,038.2 81,226.9 1,585,177.4
2028 1,156.1 5.472% 1,092.8 124.51 136,073.9 0.0 15,110.0 120,963.9 28,938.6 92,025.3 1,604,272.7
2029 1,005.8 5.355% 951.9 127.12 121,012.9 0.0 11,332.5 109,680.4 27,659.6 82,020.8 1,619,744.9
2030 814.7 5.145% 772.8 129.78 100,293.8 0.0 5,194.1 95,099.7 21,192.5 73,907.2 1,632,419.2
2031 659.9 5.000% 626.9 132.41 83,011.0 0.0 3,895.6 79,115.4 13,550.0 65,565.4 1,642,640.7
2032 541.1 5.000% 514.1 135.10 69,447.9 0.0 2,921.7 66,526.2 6,405.2 60,121.0 1,651,161.5
2033 443.7 5.000% 421.5 137.83 58,100.5 0.0 2,191.2 55,909.3 1,628.6 54,280.7 1,658,155.1
2034 363.9 5.000% 345.7 140.62 48,607.0 0.0 1,643.4 46,963.6 0.0 46,963.6 1,663,655.9
2035 298.4 5.000% 283.4 143.47 40,664.6 0.0 1,232.6 39,432.0 0.0 39,432.0 1,667,854.7
2036 247.0 5.000% 234.7 146.37 34,346.1 0.0 924.4 33,421.7 0.0 33,421.7 1,671,089.9
2037 0.0 5.000% 0.0 149.33 0.0 35,573.1 0.0 -35,573.1 0.0 -35,573.1 1,667,959.5
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 1,667,959.5
Totals 79,942.4 72,768.9 7,630,252.5 313,768.1 1,078,263.9 6,238,220.5 3,145,365.5 3,092,855.0
PW 0.00% 3,092,855.0
PW 5.00% 2,171,257.3
PW 10.00% 1,667,959.5
PW 15.00% 1,362,621.0
PW 20.00% 1,160,750.1
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
Reserves Class:
After Income Tax Analysis
Present Worth Profile ($M)
6
Appendix 4.7
Probable As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 177.6 14.623% 151.6 104.10 15,782.3 0.0 -210.9 15,993.1 1,872.6 14,120.5 13,463.4
2013 636.0 13.591% 549.6 99.60 54,738.3 18,287.2 31,251.7 5,199.4 26,845.8 -21,646.4 -5,299.4
2014 666.0 12.500% 582.8 95.10 55,420.6 0.0 27,680.0 27,740.6 12,014.9 15,725.7 7,092.2
2015 747.1 12.500% 653.7 94.91 62,049.5 -7,852.3 36,303.6 33,598.2 23,866.5 9,731.7 14,063.5
2016 452.3 12.500% 395.7 96.93 38,360.3 10,257.8 13,158.0 14,944.5 30,157.8 -15,213.3 4,156.2
2017 465.0 12.500% 406.9 98.99 40,274.2 0.0 13,181.0 27,093.2 14,574.4 12,518.8 11,567.7
2018 1,467.9 12.500% 1,284.4 101.09 129,831.2 0.0 13,204.8 116,626.4 29,419.6 87,206.9 58,502.8
2019 1,336.7 12.500% 1,169.6 103.23 120,731.8 0.0 13,229.0 107,502.8 91,261.8 16,241.0 66,449.2
2020 1,219.0 11.694% 1,076.4 105.41 113,462.6 0.0 13,253.4 100,209.1 96,230.9 3,978.2 68,218.7
2021 1,185.7 10.302% 1,063.6 107.63 114,474.4 0.0 18,894.4 95,580.0 84,617.8 10,962.2 72,651.4
2022 1,172.0 10.000% 1,054.8 109.90 115,924.7 -8,484.0 16,074.6 108,334.1 75,251.0 33,083.1 84,812.7
2023 987.8 9.515% 893.8 112.22 100,301.4 0.0 15,068.3 85,233.1 68,156.2 17,076.9 90,519.5
2024 864.9 8.214% 793.9 114.58 90,967.7 0.0 15,370.0 75,597.7 52,019.4 23,578.3 97,682.7
2025 833.6 6.898% 776.1 116.99 90,797.4 0.0 15,677.1 75,120.3 43,071.8 32,048.5 106,534.0
2026 747.7 6.250% 700.9 119.45 83,727.7 0.0 10,625.1 73,102.6 38,681.8 34,420.8 115,176.2
2027 618.2 6.231% 579.7 121.96 70,696.3 9,545.6 10,879.2 50,271.5 31,310.2 18,961.4 119,504.2
2028 587.6 5.928% 552.7 124.51 68,825.4 0.0 604.4 68,221.0 28,210.6 40,010.4 127,806.4
2029 551.0 5.648% 519.9 127.12 66,087.1 0.0 453.3 65,633.8 27,659.6 37,974.2 134,969.7
2030 450.8 5.263% 427.1 129.78 55,433.5 0.0 604.4 54,829.1 21,192.5 33,636.6 140,738.0
2031 392.9 5.000% 373.3 132.41 49,424.4 0.0 453.3 48,971.1 13,550.0 35,421.1 146,260.1
2032 541.1 5.000% 514.1 135.10 69,447.9 -33,028.3 2,921.7 99,554.5 6,405.2 93,149.4 159,461.8
2033 443.7 5.000% 421.5 137.83 58,100.5 0.0 2,191.2 55,909.3 1,628.6 54,280.7 166,455.5
2034 363.9 5.000% 345.7 140.62 48,607.0 0.0 1,643.4 46,963.6 0.0 46,963.6 171,956.3
2035 298.4 5.000% 283.4 143.47 40,664.6 0.0 1,232.6 39,432.0 0.0 39,432.0 176,155.0
2036 247.0 5.000% 234.7 146.37 34,346.1 0.0 924.4 33,421.7 0.0 33,421.7 179,390.3
2037 0.0 5.000% 0.0 149.33 0.0 35,573.1 0.0 -35,573.1 0.0 -35,573.1 176,259.8
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 176,259.8
Totals 17,453.7 15,805.8 1,788,476.9 24,299.1 274,668.1 1,489,509.7 817,999.0 671,510.7
PW 0.00% 671,510.7
PW 5.00% 324,976.9
PW 10.00% 176,259.8
PW 15.00% 105,768.0
PW 20.00% 69,067.9
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
After Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
7
Appendix 4.8
Proved plus Probable plus Possible As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 7,495.2 10.377% 6,717.5 104.10 699,286.6 226,734.2 102,028.8 370,523.6 51,263.2 319,260.4 304,402.8
2013 7,865.7 10.595% 7,032.3 99.60 700,421.9 31,555.6 89,839.2 579,027.0 143,333.1 435,693.9 682,055.4
2014 7,399.5 10.317% 6,636.0 95.10 631,086.7 0.0 83,479.8 547,606.9 378,574.9 169,032.0 815,250.2
2015 7,074.1 10.146% 6,356.4 94.91 603,313.1 0.0 82,157.0 521,156.1 348,940.4 172,215.7 938,617.0
2016 6,782.0 10.045% 6,100.8 96.93 591,354.3 435.8 68,848.8 522,069.6 327,388.0 194,681.6 1,065,399.0
2017 6,539.1 9.954% 5,888.2 98.99 582,857.4 12,342.0 61,373.1 509,142.3 325,257.5 183,884.8 1,174,263.5
2018 6,500.7 9.939% 5,854.6 101.09 591,813.0 0.0 62,600.1 529,212.9 322,091.6 207,121.3 1,285,737.2
2019 6,357.6 9.881% 5,729.4 103.23 591,416.3 0.0 63,851.6 527,564.6 336,431.7 191,133.0 1,379,254.2
2020 5,259.3 9.334% 4,768.4 105.41 502,621.9 0.0 65,130.3 437,491.6 324,057.7 113,434.0 1,429,709.3
2021 4,372.8 8.692% 3,992.7 107.63 429,745.7 0.0 66,432.2 363,313.5 259,695.1 103,618.4 1,471,608.5
2022 3,635.9 7.921% 3,347.9 109.90 367,948.7 0.0 53,299.4 314,649.3 195,882.0 118,767.3 1,515,267.5
2023 3,048.9 7.491% 2,820.5 112.22 316,520.7 0.0 53,037.1 263,483.5 148,919.7 114,563.8 1,553,552.8
2024 2,534.9 6.982% 2,357.9 114.58 270,171.6 0.0 54,099.4 216,072.2 109,269.2 106,803.0 1,585,999.8
2025 2,049.9 6.268% 1,921.4 116.99 224,787.5 0.0 45,998.2 178,789.4 78,062.4 100,727.0 1,613,819.0
2026 1,693.9 5.719% 1,597.1 119.45 190,770.5 8,763.0 40,293.4 141,714.1 54,040.1 87,674.0 1,635,831.9
2027 1,456.8 5.632% 1,374.7 121.96 167,659.6 0.0 36,264.0 131,395.6 38,627.9 92,767.6 1,657,006.3
2028 1,252.8 5.532% 1,183.5 124.51 147,367.4 0.0 32,637.6 114,729.8 31,530.8 83,198.9 1,674,270.1
2029 1,077.4 5.415% 1,019.1 127.12 129,551.0 0.0 29,373.9 100,177.1 23,725.2 76,451.9 1,688,691.8
2030 948.1 5.301% 897.9 129.78 116,530.9 0.0 26,436.5 90,094.5 17,565.4 72,529.1 1,701,129.7
2031 834.4 5.171% 791.2 132.41 104,768.0 0.0 23,792.8 80,975.2 12,763.7 68,211.5 1,711,763.8
2032 734.2 5.024% 697.4 135.10 94,209.4 0.0 21,413.5 72,795.8 8,437.5 64,358.3 1,720,885.1
2033 653.5 5.000% 620.8 137.83 85,566.2 0.0 19,272.2 66,294.0 4,765.7 61,528.3 1,728,812.5
2034 581.6 5.000% 552.5 140.62 77,695.8 0.0 17,345.0 60,350.8 1,653.0 58,697.9 1,735,687.7
2035 494.4 5.000% 469.6 143.47 67,378.2 0.0 15,610.5 51,767.7 83.2 51,684.5 1,741,191.2
2036 425.0 5.000% 403.8 146.37 59,097.6 0.0 14,049.4 45,048.1 0.0 45,048.1 1,745,551.9
2037 0.0 5.000% 0.0 149.33 0.0 37,195.4 0.0 -37,195.4 0.0 -37,195.4 1,742,278.6
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 1,742,278.6
Totals 87,067.6 79,131.4 8,343,940.0 317,026.1 1,228,664.0 6,798,250.0 3,542,359.0 3,255,891.0
PW 0.00% 3,255,891.0
PW 5.00% 2,274,827.3
PW 10.00% 1,742,278.6
PW 15.00% 1,420,231.8
PW 20.00% 1,207,749.2
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
After Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
8
Appendix 4.9
Possible As of date: 01/01/2012
Discount rate: 10.0%
Year Gross Oil Royalty Net Oil Oil Price Oil RevenueNet
InvestmentOperating
CostAnnual BT Cash Flow Taxes
Annual AT Cash Flow
Cum Disc. Cash Flow
MBBL % Mbbl $/bbl $M $M $M $M $M $M $M
2012 144.4 15.000% 122.8 104.10 12,780.7 -101.8 0.0 12,882.5 1,573.1 11,309.3 10,783.0
2013 388.2 15.000% 330.0 99.60 32,866.3 0.0 -0.4 32,866.7 9,836.5 23,030.2 30,745.2
2014 268.6 14.356% 230.0 95.10 21,875.5 0.0 0.0 21,875.5 29,537.2 -7,661.6 24,708.0
2015 185.3 12.500% 162.2 94.91 15,392.8 0.0 -0.2 15,393.0 18,791.6 -3,398.6 22,273.4
2016 335.5 12.500% 293.6 96.93 28,458.8 -9,822.0 8,678.5 29,602.3 11,641.9 17,960.5 33,969.8
2017 175.8 12.500% 153.8 98.99 15,224.3 12,342.0 0.0 2,882.3 20,119.1 -17,236.8 23,765.2
2018 204.1 12.500% 178.6 101.09 18,054.3 0.0 0.0 18,054.3 6,503.5 11,550.7 29,981.8
2019 1,077.7 12.500% 943.0 103.23 97,342.0 0.0 0.0 97,342.0 24,702.9 72,639.1 65,522.4
2020 833.1 12.500% 728.9 105.41 76,834.8 0.0 0.0 76,834.8 69,323.5 7,511.2 68,863.4
2021 629.6 12.500% 550.9 107.63 59,298.7 0.0 0.0 59,298.7 66,010.5 -6,711.8 66,149.4
2022 449.1 10.200% 403.3 109.90 44,328.6 0.0 0.0 44,328.6 47,314.0 -2,985.5 65,052.0
2023 388.9 10.000% 350.0 112.22 39,277.3 0.0 0.0 39,277.3 32,987.7 6,289.6 67,153.9
2024 281.9 10.000% 253.7 114.58 29,075.1 0.0 0.0 29,075.1 24,826.3 4,248.8 68,444.6
2025 105.9 10.000% 95.3 116.99 11,150.9 0.0 -9,182.7 20,333.6 16,476.6 3,857.0 69,509.9
2026 58.0 6.250% 54.3 119.45 6,491.8 8,763.0 -10,625.1 8,353.9 9,609.2 -1,255.4 69,194.7
2027 127.9 6.250% 120.0 121.96 14,628.9 -9,545.6 6,044.0 18,130.5 6,589.8 11,540.7 71,828.9
2028 96.7 6.250% 90.7 124.51 11,293.5 0.0 17,527.6 -6,234.1 2,592.3 -8,826.4 69,997.4
2029 71.6 6.250% 67.2 127.12 8,538.0 0.0 18,041.4 -9,503.3 -3,934.4 -5,569.0 68,946.9
2030 133.5 6.250% 125.1 129.78 16,237.1 0.0 21,242.4 -5,005.3 -3,627.1 -1,378.1 68,710.6
2031 174.5 5.819% 164.3 132.41 21,757.1 0.0 19,897.3 1,859.8 -786.4 2,646.2 69,123.1
2032 193.1 5.092% 183.3 135.10 24,761.5 0.0 18,491.9 6,269.6 2,032.4 4,237.3 69,723.6
2033 209.8 5.000% 199.3 137.83 27,465.7 0.0 17,081.0 10,384.7 3,137.2 7,247.6 70,657.4
2034 217.7 5.000% 206.9 140.62 29,088.8 0.0 15,701.5 13,387.2 1,653.0 11,734.3 72,031.8
2035 196.0 5.000% 186.2 143.47 26,713.7 0.0 14,377.9 12,335.8 83.2 12,252.6 73,336.5
2036 178.0 5.000% 169.1 146.37 24,751.4 0.0 13,125.0 11,626.4 0.0 11,626.4 74,461.9
2037 0.0 5.000% 0.0 149.33 0.0 1,622.3 0.0 -1,622.3 0.0 -1,622.3 74,319.2
2038 0.0 5.000% 0.0 152.35 0.0 0.0 0.0 0.0 0.0 0.0 74,319.2
Totals 7,125.2 6,362.5 713,687.5 3,258.0 150,400.0 560,029.5 396,993.5 163,036.0
PW 0.00% 163,036.0
PW 5.00% 103,570.0
PW 10.00% 74,319.2
PW 15.00% 57,610.8
PW 20.00% 46,999.1
EVALUATION OF COASTAL INTERESTS IN G5/43 CONCESSION
GULF OF THAILAND, SONGKHLA A, C, D AND E FIELDS AND SONGKHLA H DISCOVERY
After Income Tax AnalysisReserves Class:
Present Worth Profile ($M)
9