RESERVES CERTIFICATION REPORT Songkhla A Field Bau Ban … · 2012-05-31 · RPS Reserves...

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


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


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


UCV02179 4 March 2012

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


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


UCV02179 6 March 2012

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


UCV02179 7 March 2012

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.


UCV02179 8 March 2012

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.


UCV02179 9 March 2012

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.


UCV02179 10 March 2012

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.


UCV02179 11 March 2012

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.


UCV02179 12 March 2012

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%.


UCV02179 13 March 2012

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.


UCV02179 14 March 2012

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.


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.


UCV02179 16 March 2012

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.


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.


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.


UCV02179 19 March 2012

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.


UCV02179 20 March 2012

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.


UCV02179 21 March 2012

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.



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


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.



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.



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.


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






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







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.


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 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 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.


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.




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


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.




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.


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


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



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


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.


UCV02179 28 March 2012



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


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


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.



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


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


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.


UCV02179 29 March 2012

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.



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.



5.4. The reservoir is mapped to be bounded on the east by a fault; the reservoir is open to the west that


UCV02179 30 March 2012

should allow water influx. Recovery factor calculations are shown on Table 5.5; after the sweep efficiency


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.


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 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.




UCV02179 31 March 2012




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.


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


UCV02179 32 March 2012

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


UCV02179 33 March 2012

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.


UCV02179 34 March 2012

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.


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.


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


UCV02179 35 March 2012

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


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.


UCV02179 36 March 2012

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.


UCV02179 37 March 2012

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


UCV02179 38 March 2012

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


10.00%

4th level The portion exceeding 300,000 barrels but


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”


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


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


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’


M300 Top at 4,082’


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

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40

50

60

70

80

90

100

0

50

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300

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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

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600

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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

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0

100

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500

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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


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


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

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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


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

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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


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



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


C Area ‐ 2 wells


3P Cases



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


C Area ‐ 2 wells


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 NAMES: E01, E02, E03, E04, E05, E06, E07, E08, E09, E10 & E12 OPERATOR: Coastal Energy Company




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


RPS

Table 3.3

H Discovery


WELL NAMES: H01, H01 ST OPERATOR: Coastal Energy Company




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


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


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


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


MDT Test Depth

Sand Member Fault Block (s) Well(s) Yes / No SS TVD Porosity Permeability Temp Water Gas Oil Water Gas-Oil



(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



(3) Miocene sand correlations




RPS

Table 5.5



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



STOOIP


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


RPS

Table 5.7

H Discovery


MDT Test Depth

Sand Member Fault Block Well Yes / No SS TVD Porosity Permeability Temp Water Gas Oil Water Gas-Oil



(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



(3) Oligocene sand correlations




RPS

Table 5.8

H Discovery


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


STOOIP


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


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


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


Year Gross Oil

Operating


Operating


Operating

Expense Investment


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


RPS

Table 7.3

GULF OF THAILAND, SONGKHLA D AND E AREAS


Year Gross Oil

Operating


Operating


Operating

Expense Investment


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


RPS

Table 7.4

GULF OF THAILAND, SONGKHLA H AREA


Year Gross Oil

Operating


Operating


Operating

Expense Investment


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


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


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


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.


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



InvestmentOperating


Cum Disc. Cash Flow


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



Reserves Class:



2

Appendix 3.3

Proved Developed Shut-In As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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



Reserves Class:



3

Appendix 3.4

Proved Developed Non-Producing As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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



Reserves Class:



4

Appendix 3.5

Proved Undeveloped As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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



Reserves Class:



5

Appendix 3.6

Proved plus Probable As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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



Reserves Class:



6

Appendix 3.7

Probable As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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



Before Income Tax AnalysisReserves Class:


7

Appendix 3.8

Proved plus Probable plus Possible As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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





8

Appendix 3.9

Possible As of date: 01/01/2012



InvestmentOperating


Cum Disc. Cash Flow


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





9

APPENDIX 4

Appendix 4.1

Proved Total As of date: 01/01/2012



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



Reserves Class:

After Income Tax Analysis


1

Appendix 4.2

Proved Developed Producing As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



Reserves Class:



2

Appendix 4.3

Proved Developed Shut-In As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



Reserves Class:



3

Appendix 4.4

Proved Developed Non-Producing As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



Reserves Class:



4

Appendix 4.5

Proved Undeveloped As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



Reserves Class:



5

Appendix 4.6

Proved plus Probable As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



Reserves Class:



6

Appendix 4.7

Probable As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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



After Income Tax AnalysisReserves Class:


7

Appendix 4.8

Proved plus Probable plus Possible As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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





8

Appendix 4.9

Possible As of date: 01/01/2012



InvestmentOperating


Annual AT Cash Flow

Cum Disc. Cash Flow


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





9

RESERVES CERTIFICATION REPORT Songkhla A Field Bau Ban … · 2012-05-31 · RPS Reserves...

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