ESERVES AND RESOURCES ERTIFICATION · The Reserve estimates shown in this report are estimated in...

RESERVES AND RESOURCES

CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1ST JANUARY, 2012

Prepared by:

RPS Energy Consultants Limited

#03-01 China House, 19 China Street,

Far East Square,

Singapore 049561

T: +65 6499 0060

F: +65 6499 0069

E: [email protected]

W: www.rpsgroup.com

Report No: ECV1837.03

Version/Date: Rev0 / 29th March, 2012

Prepared for:

Coastal Energy Company

3355 West Alabama Street, Suite 500, Houston, Texas 77098

Unit #03-01 China House, 19 China Street, Far East Square, Singapore 049561 T +65 6499 0060 F +65 6499 0069 E [email protected] W www.rpsgroup.com

RPS Energy Limited (Singapore Branch): Registered in England No. 146554. Centurion Court, 85 Milton Park, Abingdon, Oxfordshire OX14 4RY, United Kingdom.

Branch registered in Singapore UEN: T07FC7076E

Mr. Jerry Moon, Project Ref: ECV1837.03

Coastal Energy Company,

3355 West Alabama Street,

Suite 500,

Houston,

Texas 77098

29th March, 2012

Dear Jerry,

EVALUATION OF COASTAL’S RESERVES IN THE SINPHUHORM GAS FIELD

LICENCES EU1 AND E5N, ONSHORE THAILAND

AS OF 1ST JANUARY, 2012

In response to your request, RPS Energy Consultants Limited (“RPS”) has completed an update of the independent evaluation of the Reserves and value for the Sinphuhorm Field (“the Property”) in which Coastal Energy Company (“Coastal”) has an interest. We have estimated Proved, Probable and Possible Reserves as of 1st January, 2012. The Reserve estimates shown in this report are estimated in accordance with requirements of the London Stock Exchange and Toronto Ventures Exchange (“LSE” and “TSX”) including Canadian National Instrument 51-101 and the Reserve and Resource definitions of the Canadian Oil and Gas Evaluation Handbook. RPS was mandated to undertake this work with the signing of the Letter of Engagement (“LoE”) by Coastal on 29th December, 2011.

The work was undertaken by a team of petroleum engineers, geoscientists and economists and is based on data supplied by Coastal. The report has an effective date as of 1st January, 2012. Our approach has been to review the production and cost data supplied by Coastal for reasonableness and then independently estimate ranges of recoverable volumes. We have estimated the degree of uncertainty inherent in the measurements and interpretation of the data and have calculated a range of recoverable volumes, based on predicted field performance for the property and the contracted gas sales for Sinphuhorm.

RPS has included in Probable (P2) Reserves and Possible (P3) Reserves volumes that can be reasonably expected to be sold under the existing Gas Sales Agreement (“GSA”). The GSA limits the volumes that may be monetized and allows for a Daily Contract Quantity (“DCQ”) of 108 MMscfd, subject to a “Buyers Maximum DCQ Reduction Amount”. This DCQ Reduction allows the Sinphuhorm DCQ to be reduced in the early years in order to allow for preferential supply to the GSA from the nearby Nam Phong field. The exact Sinphuhorm DCQ reduction amounts will depend on the decline of the Nam Phong field. The DCQ reduction, as estimated by the Nam Phong Field production forecast provided by Coastal, has been used to estimate the Reserves for the Sinphuhorm property.

Gross and Net Working Interest Reserves attributable to Coastal are summarized in Table I.

We have taken the working interest that Coastal has in the Property as presented by Coastal and we have not investigated nor do we make any warranty as to Coastal’s interest in the Property.

The report shows the Reserves in barrels of oil equivalent (“BOE”) for Sinphuhorm using a conversion factor of 6.0 Mscf per BOE as per the SPE BOE calculation guidelines. Readers should note that BOE’s may be misleading, particularly if used in isolation.

RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

ECV1837.03 iii

Table 1

Summary Statement of Coastal’s Reserves for the Sinphuhorm Gas Field

as of 1st January, 2012

Net means net entitlement as per the Reserve and Resource definitions of the Canadian Oil and Gas Evaluation Handbook. Thailand is a Tax and Royalty regime. Royalty is treated as tax and paid in cash, and thus, attributable Net Entitlement Share is reported as Coastal’s working interest volumes including the volumes associated with Royalty.

Note that the majority of the Undeveloped Reserves are at risk of being re-classified as Contingent Resources at the end of 2012. This is due to the lack of demonstrated commerciality for the tighter, unfractured and undolomitised portions of the structure. Please see report (Section 2.11.1) for details.

Gross Net 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Non-Associated Gas (MMcf)

Proved Developed Producing 419,428 261,589 32,960 208 166 136 115 99 143 115 95 80 69

Proved Developed Non-Producing

Proven Undeveloped 82,101 82,101 10,345 66 49 37 29 23 43 32 24 19 15

Total Proved 501,529 343,690 43,305 274 215 173 144 122 186 147 119 99 84

Probable 612,926 612,926 89,750 679 303 148 79 45 444 198 97 52 30

Total Proved + Probable 1,114,455 956,616 133,055 953 517 321 222 167 630 345 216 151 114

Natural Gas Liquid (Mbbl)

Proved Developed Producing 2,143 1,344 169 13 10 9 7 6 9 7 6 5 4


Proven Undeveloped 422 422 53 4 3 2 2 1 3 2 2 1 1

Total Proved 2,565 1,765 222 17 14 11 9 8 12 9 8 6 5

Probable 3,148 3,148 461 46 21 10 6 3 30 14 7 4 2

Total Proved + Probable 5,713 4,913 683 63 34 21 15 11 42 23 14 10 8

Grand Total (MBOE)(1)




Total Proved 86,153 59,047 7,440 291 228 184 153 129 198 156 127 105 90

Probable 105,302 105,302 15,419 725 323 159 85 49 474 212 104 56 32

Total Proved + Probable 191,455 164,349 22,859 1016 552 343 237 178 671 368 231 161 122

After Income Taxes

Net Present Values (US$ Million)

Notes: (1) Using 6.0 Mscf/BOE

Remaining

Reserves

Company Before Income TaxesProduct Classification

Ultimate

Reserves


ECV1837.03 iv


ECV1837.03 v

Table 2

Summary Statement of Coastal’s Contingent Resources for the Sinphuhorm Gas Field as of 1st January, 2012

Low Estimate 1)

Best Estimate 2)

High Estimate 2)

Chance of Commercialization 3)

Gross (100%) Licence Basis

Gas (MMscf) 137,922 593,874 4,504,520 70%

Oil and Condensate (Mbbl) 708 3,463 24,493 70%

Coastal Net Working Interest Basis

Net Working Interest 12.6% 14.0% 16.2% 70%

Gas (MMscf) 17,378 83,142 729,732 70%

Oil and Condensate (Mbbl) 89 485 3,968 70%

Coastal Net Entitlement Interest Basis 4)

Net Entitlement Interest 12.6% 14.0% 16.2%

Gas (MMscf) 17,378 83,142 729,732 70%

Oil and Condensate (Mbbl) 89 485 3,968 70%

Notes: 1) The Low Estimate relates to recoverable volumes from the currently producing wells that are not assigned to the Nam

Phong Power Plant GSA. Volumes remain un-contracted and are available for sale pending a GSA. If these volumes were contracted to a GSA, then the contracted volumes would be re-classified as Proved Reserves. RPS has estimated that all the volumes lie within the EU1/E5N production concessions.

2) The Best and High Estimates include all recoverable sales gas and condensate volumes that have not been classified within the Reserves relating to the current GSA and the 15 year GSA extension periods.

3) The Chance of Commercialization relates to the chance of the reported volumes being commercialized in to a GSA. The 70% presented above would relate to the Low, Best and High Estimate volumes.

4) Coastal’s net entitlement is the same as their net working interest share as the royalty is paid in cash, rather than kind.


ECV1837.03 vi


ECV1837.03 vii

Table of Contents

RESERVES AND RESOURCES CERTIFICATION

1 Introduction .................................................................................................................................1

2 Concessions EU1, E5N and L15/43 ............................................................................................5

2.1 Overview ....................................................................................................................................................... 5 2.2 Petroleum System ........................................................................................................................................ 5 2.3 Database ........................................................................................................................................................ 6 2.4 Sinphuhorm Structure ................................................................................................................................. 6 2.5 Petrophysics .................................................................................................................................................. 7 2.6 Static Volumetric Estimates ........................................................................................................................ 7

2.6.1 Gas-Water Contact ....................................................................................................................................... 7 2.6.2 Indosinian-1 Unconformity Truncation ...................................................................................................... 8 2.6.3 Monte Carlo Probabilistic Simulation ........................................................................................................ 8

2.7 Reservoir Pressure and Temperature ...................................................................................................... 9 2.8 Production History ...................................................................................................................................... 9 2.9 Well Production Testing ............................................................................................................................. 9 2.10 Fluid Properties .......................................................................................................................................... 10 2.11 Material Balance Analysis .......................................................................................................................... 10

2.11.1 “Mapped” versus “Connected” GIIP Estimates.................................................................................... 12 2.12 Recoverable Hydrocarbons ...................................................................................................................... 12

2.12.1 Further Development Plans ...................................................................................................................... 13 2.12.2 EUR Volumes ............................................................................................................................................... 15 2.12.3 Resource Classification .............................................................................................................................. 15 2.12.4 Uncontracted Gas and Condensate Volumes ....................................................................................... 18

3 Commercial Evaluation ............................................................................................................27

3.1 Thai Concession Terms ............................................................................................................................ 27 3.2 Capital and Operating Costs .................................................................................................................... 27 3.3 Gas Contract and Prices ........................................................................................................................... 28

3.3.1 Sinphuhorm Contract Volumes ................................................................................................................ 28 3.3.2 Sinphuhorm Gas Price ............................................................................................................................... 28 3.3.3 Sinphuhorm Unitisation ............................................................................................................................. 28

4 Resource Statement .................................................................................................................31

5 NI 51-101 Reporting of Reserves .............................................................................................39

Appendices ..........................................................................................................................................45

Appendix I: Glossary of Technical Terms

Appendix II: Reserves and Resources Definitions and Guidelines


ECV1837.03 viii

Tables

Table 2-1 – Sinphuhorm Participants and their Working Interests ............................................................................. 5

Table 2-2 – Sinphuhorm GIIP (Bscf, 100% Basis) ............................................................................................................ 8

Table 2-3 – PH-5 Welltest Summary .............................................................................................................................. 10

Table 2-4 – The Latest Reservoir Pressure Measurements ........................................................................................ 11

Table 2-5 – Effective “Connected” Estimates of GIIP, Sinphuhorm Gas Field (Bscf, 100% Basis) ........................ 12

Table 2-6 – Differences between the “Mapped” and “Connected” GIIP Estimates, Sinphuhorm Gas Field (Bscf, 100% Basis) ......................................................................................................................................................................... 12

Table 2-7 – Drilling Infill and Appraisal Wells and Wells Allocations for Reserves ............................................... 14

Table 2-8 – Sinphuhorm Gas Field EUR (Bscf, 100% Basis) ........................................................................................ 15

Table 2-9 – Sinphuhorm Gas Sales Agreement – DCQ and DCQ Reduction ........................................................ 16

Table 2-10 – Contracted and Uncontracted Gas and Condensate Volumes ........................................................... 17

Table 2-11 – Uncontracted Recoverable Sales Gas Volumes ..................................................................................... 18

Table 3-1 – Principal Commercial Terms ...................................................................................................................... 27

Table 3-2 – Forecast CAPEX and OPEX (US$ Million, 2012) for the Sinphuhorm Development ....................... 27

Table 3-3 – Estimated Unitised Share for the Sinphuhorm Gas Field ....................................................................... 29

Table 4-1 – Sinphuhorm Field Gross Reserves Estimate as of 1st January, 2012 ................................................... 31

Table 4-2 – Sinphuhorm Field Coastal’s Net Entitlement Reserves Estimate as of 1st January, 2012 ................ 31

Table 4-3 – Sinphuhorm Field Gross Sales Gas Reserves Reconciliation ................................................................. 32

Table 4-4 – Sinphuhorm Field Gross Condensate Reserves Reconciliation ............................................................ 32

Table 4-5 – Sinphuhorm Field Coastal Net Company Sales Gas Reserves Reconciliation (Forecast Prices and Costs) .................................................................................................................................................................................. 33

Table 4-6 – Sinphuhorm Field Coastal Net Company Condensate Reserves Reconciliation (Forecast Prices and Costs) ........................................................................................................................................................................... 33

Table 5-1 – Sinphuhorm Field Summary of the Evaluation of the Petroleum Reserves as of 1st January, 2012 39

Table 5-2 – Total Future Net Revenue Undiscounted Forecast Prices and Costs as of 1st January, 2012 ........ 40

Table 5-3 – Sinphuhorm Field Volumetric Reserves Estimates Reservoir Data ...................................................... 40

Table 5-4 – Estimates of Proved Reserves and Net Present Values for the Sinphuhorm Field (as of 1st January, 2012) .................................................................................................................................................................................... 41

Table 5-5 – Estimates of Proved Plus Probable Reserves and Net Present Values for the Sinphuhorm Field (as of 1st January, 2012) ......................................................................................................................................................... 42

Table 5-6 – Sinphuhorm Field Remaining Gas Reserves Reconciliation, 100% Basis .............................................. 43

Table 5-7 – Sinphuhorm Field Remaining Condensate Reserves Reconciliation, 100% Basis ............................... 43

Table 5-8 – Sinphuhorm Field Remaining Gas Reserves Reconciliation, Coastal’s Net Entitlement ................... 44

Table 5-9 – Sinphuhorm Field Remaining Condensate Reserves Reconciliation, Coastal’s Net Entitlement ..... 44


ECV1837.03 ix

Figures

Figure 1-1 – Location of Coastal’s Onshore Thailand Concession ............................................................................. 3

Figure 2-1 – Location of the Sinphuhorm Gas Field and Concession L15/43 .......................................................... 19

Figure 2-2 – Onshore Thailand Stratigraphic Column ................................................................................................. 20

Figure 2-3 – Sinphuhorm Gas Field Top Structure Map (RPS) ................................................................................... 21

Figure 2-4 – Sinphuhorm Gas Field Reservoir Pressure ............................................................................................. 22

Figure 2-5 – Sinphuhorm Gas Field Production History ............................................................................................. 23

Figure 2-6 – Sinphuhorm Gas Field FWHPs .................................................................................................................. 24

Figure 2-7 – Sinphuhorm Gas Field P/Z GIIP Estimate (RPS) ..................................................................................... 25

Figure 2-8 – Sinphuhorm Gas Field P/Z GIIP Estimates (Operator) ......................................................................... 26

Figure 4-1 – Sinphuhorm Gas Field Gas Production Profile ....................................................................................... 35

Figure 4-2 – Sinphuhorm Gas Field Condensate Production Profile ......................................................................... 36

Figure 4-3 – Sinphuhorm Gas Field Gas Production Forecast ................................................................................... 37

Figure 4-4 – Sinphuhorm Gas Field Gas Production Forecast ................................................................................... 38


ECV1837.03 x


ECV1837.03 1

1 Introduction

Coastal, through its 36.1% interest in APICO LLC’s (“APICO”) share, participates in two production licenses; EU1 and E5N (at 12.6% Working Interest) and two concessions, currently in the exploration phase (L27/43 and L15/43 at 36.1% Working Interest). Coastal has engaged RPS Energy Consultants Limited (“RPS”) to perform a Reserves and Resources Update for the Sinphuhorm Gas Field. This evaluation covers the hydrocarbon Reserves and Contingent Resources associated with Coastal’s interest in the Sinphuhorm Gas Field (the “Asset”, Figure 1-1).

The Reserves Evaluation of the Asset followed the Scope of Work as agreed by Coastal and RPS:

Sinphuhorm Gas Field Review

1. Geological Review.

2. Production Data Review.

3. Gas Sales Agreement and Production/Cashflow Forecasting.

4. Further Field Development Review.

5. Estimation of the Proved (“1P”), Proved plus Probable (“2P”), Proved plus Probable plus Possible (“3P”) Reserves and the Contingent Resources.

6. Issue of the final Reserves and Resources Update Report; this report.

The deliverable is a Formal Reserves Update Report Letter for the Asset. It presents our opinions on whether the existing studies, models and estimates are reasonable and appropriate. In addition to documenting the methodology used for RPS’s independent analyses and checks, we also highlight any red flags or items of material interest to the Lenders.

The evaluation presented in this report reflects our informed judgment, based on accepted standards of professional investigation, but is subject to generally recognized uncertainties associated with the interpretation of geological, geophysical and engineering data. The evaluation has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. However, RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the property. Our estimates of Reserves and Resources are based on data provided by Coastal. We have accepted, without independent verification, the accuracy and completeness of this data.

The report represents RPS’s best professional judgment and should not be considered a guarantee or prediction of results. It should be understood that any evaluation, particularly one involving future performance and development activities may be subject to significant variations over short periods of time as new information becomes available. This report relates specifically and solely to the subject Property and is conditional upon various assumptions that are described herein. This report must, therefore, be read in its entirety. This report was provided for the sole use of Coastal and their corporate advisors on a fee basis.

The Reserve estimates shown in this report are estimated and presented in accordance with requirements of the London Stock Exchange and Toronto Ventures Exchange (“LSE” and “TSX”) including Canadian National Instrument 51-101 and the Reserve and Resource definitions of the Canadian Oil and Gas Evaluation Handbook. Further, RPS has been guided by the March 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (“PRMS”) in assessing the volumes.


ECV1837.03 2

RPS has previously reviewed the Resources for this Asset for Coastal, Salamander and APICO in the reports:

“Salamander Reserves Statement for the Sinphuhorm Field” dated 20th October, 2010, evaluating the Reserves as of 1st July, 2010 (Project ECV1665).

“Coastal Energy Due Diligence for the Sinphuhorm Field” dated 29th October, 2010, evaluating the Reserves and Contingent Resources as of 1st July, 2010 (Project ECV1658).

“APICO LLC Resource Statement for the Sinphuhorm Gas Field” dated 24th November, 2010, evaluating the Resources as of 1st July, 2010 (Project ECV1705).

“Salamander Reserves Statement for the Sinphuhorm Field” dated 19th January, 2011, evaluating the Reserves as of 1st January, 2011 (Project ECV1666).

“Coastal Energy Sinphuhorm Gas Field Reserves Update” dated 3rd March, 2011, evaluating the Reserves and Contingent Resources as of 1st January, 2011 (Project ECV1725).

“Evaluation of APICO LLC’s Reserves in the Sinphuhorm Gas Field, Licences EUI and E5N, Onshore Thailand” dated 14th June, 2011, evaluating the reserves as of 1st January, 2011 (Project ECV1738).

“Salamander Reserves Statement for the Sinphuhorm Field” dated 23rd September, 2011, evaluating the Reserves as of 1st July, 2011 (Project ECV1764).

RESERVES AND RESOURCES CERTIFICATION RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

North Phu Horm

L15/43

EU1

Sinphuhorm

Sinphuhorm

EU1

E5NE5N

E5NL15/43

L27/43

Nam Phong

0 25Scale (km)

Sinphuhorm Gas Field (Concessions EU1, E5N)

Current Coastal Concession L15/43 outline

Original Coastal Concession L15/43 outline

Current Coastal Concession L27/42 outline

Map supplied by APICO

rpsgroup.comECV1837.03

Figure 1-1 – Location of Coastal’s Onshore Thailand Concessions


ECV1837.03 4


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2 Concessions EU1, E5N and L15/43

2.1 Overview

Coastal, through its 12.6% interest in APICO’s share, participates in two production licenses; EU1 and E5N and three concessions, currently in the exploration phase (L27/43 at 36.1%, L13/48 at 21.7% and L15/43 at 36.1% Working Interest). These are located in the Khorat Plateau, onshore Thailand and are shown in Figure 1-1.

The Sinphuhorm Gas Field, which has historically been referred to as the Phu Horm Field, was discovered by Esso in 1983 with the Sinphuhorm-1 well. The Thai authorities mandated the change of name from Phu Horm to Sinphuhorm. The structure straddles the two production licenses of EU1 and E5N, and appears to extend southwards into the Block L15/43 (Figure 2-1).

The gas field has been on production since November 2006 and is subject to ongoing delineation and development activities. APICO own a 35% non-operated working interest in the EU1 and E5N concessions. APICO owns 100% of the L15/43 concession and is Operator. The field production licence expires on the 19th May, 2034. The Sinphuhorm production license extends until 19th May, 2034. As of 1st January, 2012, the participants of the concession were as presented in Table 2-1:

Table 2-1 – Sinphuhorm Participants and their Working Interests

Participants EU1 and E5N

(%) L15/43, L27/43

(%)

Hess Thailand 35.0* -

APICO LLC

(of which Coastal)

35.0

(12.635)

100.0*

(36.1)

PTT E&P 20.0 -

ExxonMobil 10.0 -

*) denotes Operator of the concession

2.2 Petroleum System

The Khorat Plateau covers an area of about 170,000 km2. It is rimmed on its western and southern margins by an escarpment of mostly steeply dipping sediments that form cuestas rising from 600-1,000 m above sea level. The sedimentary sequence consists of an initial rift sequence of Carboniferous to Triassic age sediments, and a “sag” sequence of Late Triassic to Cretaceous age sediments. The two sequences are separated by a regional unconformity, the Indosinian-1 Unconformity, which represents the main collision of Indochina with its neighbours.

The principal petroleum system is within the Permo-Triassic and underlying Carboniferous (Figure 2-2). The Mid Permian Pha Nok Khao Formation platform limestones and dolomites are the principal reservoirs. These are immediately below, and are truncated by, the major Indosinian-1 Unconformity. The proven hydrocarbon systems within Permian carbonates are:

Fractured massive carbonates contained within thrust-related structures, as in the Sinphuhorm Gas Field.

Partially dolomitised carbonates, as in the Sinphuhorm Gas Field.


ECV1837.03 6

Secondary reservoirs are the Early Permian, Si That Formation, and the Triassic aged, Huai Hin Lat Formation, which is a succession of interbedded sands and shales lying above the Indosinian-1 Unconformity.

Triassic gas-prone lacustrine shales and coals, buried within half-grabens, and matured during the Cretaceous, are the postulated source rocks. Permian marine shales may be secondary source rocks.

2.3 Database

The Coastal concessions in the Khorat Basin are covered by seismic data of several vintages dating back to 1979. New seismic was acquired in 2005 to the south of the Sinphuhorm, as well as over discovery areas to the east. The central crestal portion of the Sinphuhorm Gas Field has been delineated with the drilling of eight wells (PH-1 to -7 and PH-10). Well PH-10 has been on production since December 2007. The South PH-1 well has been drilled in the northern portion of Concession L15/43, indicating that the closure extends to the south. However, flow test rates were disappointing in that well and PH-6, located to the central northern part of the field. Both of these wells are still being evaluated for future stimulation operations. The reservoir at Sinphuhorm -7 on the western flank of the field was tight and no flow was achieved during testing.

RPS reviewed an independent third party petrophysical study that had been completed on these logs for another participant within the field development. An audit by RPS found these log evaluations to be reasonable and appropriate. Production and well test data were provided for all producing and tested Sinphuhorm wells.

2.4 Sinphuhorm Structure

RPS has completed an independent interpretation of the Sinphuhorm during a previous study for one of APICO’s part-owners (Salamander). It is evident that two key horizons form the closure across the majority of the Sinphuhorm structure (see the stratigraphic column in Figure 2-2 and the top structure map in Figure 2-3).

The lower surface is formed by the top of the Si That Formation. This complex surface dips to the SE and forms a conformable base to the overlying Pha Nok Khao Formation. However, the Si That/Pha Nok Khao bedding plane also forms the décollement surface for a low angle thrust that trends NE-SW. The thrust plane contains small conjugate thrust faults that are interpreted to have created fracturing within the Pha Nok Khao Formation, enhancing porosity and permeability locally. The interpretation of the Si That Formation is complicated by the presence of these smaller conjugate thrusts plus larger sub-trusts to the west of the structure. Nevertheless, a Best Estimate interpretation has been audited by RPS and is deemed sufficient to adequately represent the base of the reservoir sequence.

The upper surface is, for the most part, formed by the Indosinian-1 Unconformity that has eroded the top of the SE dipping Pha Nok Khao reservoir sequence and the older Si That Formation. The unconformity shows a strong change in seismic character to the underlying Pha Nok Khao and Si That Formations. Therefore, a robust time interpretation is achieved for this event. As the Pha Nok Khao Formation dips to the SE, the combined Indosinian-I and Pha Nok Khao horizons diverge in the far eastern portion of the interpretation. This is, however, outside the closure of the Sinphuhorm structure. Thus, the Indosinian-I Unconformity can be interpreted as forming the top reservoir equivalent surface for the Sinphuhorm Gas Field.

Sinphuhorm straddles the EU1 and E5N blocks, and probably extends south into Block L15/43. The drilling of well South PH-1 shows that gas is present in the southern block. Unfortunately, the rock quality was poor, which has affected the deliverability of the well. This well is currently


ECV1837.03 7

suspended pending evaluation of fracture stimulation potential. The presence of gas justifies the extension of the mapped field closure into Block L15/43.

2.5 Petrophysics

The reservoir consists of fractured tight platform limestones and dolomites of the Mid Permian Pha Nok Khao Formation. The pre-Triassic section below the Indosinian-1 Unconformity is structurally complex and thrusted. Where thrusting has occurred, the porosity and permeability of the reservoir is interpreted to have been increased by fracturing. Thus, essentially, a dual porosity system has been established in the reservoir rock. The opposite is noted at the PH-7 and South PH-1 well locations, which have not encountered significant sections of fractured reservoir and, thus have low gas deliverability.

RPS has reviewed the third party evaluation of the Sinphuhorm wells conducted on behalf of another field development participant and notes that log analyses have adequately assessed the rock parameters of the limestone/dolomite matrix. Although the data sampling within the wells was not optimal, best efforts have been made in assessing the rock parameters. Notably, the seemingly poorer quality wells have the most complete datasets, which may skew the formation averages towards the low side. In addition to the reservoir rock matrix, RPS has reviewed published material of fractured reservoirs to estimate a range of rock parameters (porosity and water saturation) for the fractured intervals of the Pha Nok Khao Formation.

2.6 Static Volumetric Estimates

The static volumetric estimate of GIIP have been based around uncertainties associated the rock properties and the Gross Rock Volume (“GRV”). The GRV provides the largest uncertainty as there remain wide ranges in the possible values for the:

i) the estimated gas-Water Contact (“GWC”) defining the vertical limit of the hydrocarbon-bearing reservoir and

ii) the north-westerly extent of the Pha Nok Khao Formation, which, together with the GWC place a large uncertainty in the areal extent of the hydrocarbon closure.

These are discussed below:

2.6.1 Gas-Water Contact

A GWC has not been penetrated by any of the nine wells drilled on the Sinphuhorm structure. The range of possible contacts is vertically dispersed (431 m) and GRV estimates have been based on the following assumptions:

Low Case: the lowest tested gas in PH-1 at 2,156 mTVDSS.

Best Case: lowest interpreted gas in PH-2 DST#3 interval at 2,279 mTVDSS.

High Case: pressure data analysis of the gas and water columns suggesting a contact at 2,587 mTVDSS.

These three water levels have been used to form the Low, Best and High estimates for the extent of the field, based on mapping. RPS notes, however, that there is the distinct possibility that there are separate pressure gas containers (“tanks”) across the mapped closures of the Sinphuhorm Gas Field and that not all of the tanks have been defined/penetrated to date.


ECV1837.03 8

2.6.2 Indosinian-1 Unconformity Truncation

An additional GRV uncertainty relates to placement of the intersection of the thrusted south-easterly dipping top Si That Formation (base of reservoir) and the Indosinian I Unconformity (top reservoir). This forms a linear structural-stratigraphic closure of the field along its western flank. The intersection of these two surfaces is relatively well defined along the SW portion as strong amplitude impedance events. However, the same is not true for the region to the NW and North of PH-1, where the intersection is not very well defined on the seismic, due to tuning and the low resolution of the seismic data.

RPS has previously interpreted that the Top Indosinian-I Unconformity time interpretation forms a robust representation of the top reservoir. The base pick, marked by the Si That Formation, has considerably more interpretation uncertainty, due to conjugate thrusting and deformation. RPS previously applied a time to depth conversion using a polynomial function, based on the check-shot surveys of wells PH-1 and PH-2. Other wells did not have time-depth curves loaded in the database. Previously, RPS noted that misties between the time pick and the stratigraphic well depth were considerable in some wells, requiring broad correction before adjusted top and base surfaces could be used in volumetric calculations. The corrected grids push the structure down in the area of wells PH-3 and PH-10.

2.6.3 Monte Carlo Probabilistic Simulation

RPS has created a Monte Carlo probabilistic simulation in the REP5™ software, applying a dual porosity (matrix and fracture) system and associated water saturations. The inputs to the Monte Carlo analysis are presented in Table 2-2. The probabilistic simulation was run through 100,000 iterations and the P90, P50, P10 values were extracted.

Table 2-2 – Sinphuhorm GIIP (Bscf, 100% Basis)

Monte Carlo Parameter Inputs Low Input Mid Input High Input

Gross Rock Volume (km2.m) 7.53 17.05 54.91

Area (km2) 57 92 165

Gas-water Contact (m TVDSS) -2,156 -2,279 -2,587

Net-to-Gross (%) 100 100 100

Matrix Porosity (%) 1.5 2.5 3.0

Matrix Water Saturation (%) 60.0 42.5 35.0

Fracture Porosity (%) 0.22 0.67 2.00

Fracture Water Saturation (%) 20 15 10

Gas Expansion Factor (scf/rcf) 207 208 209

Monte Carlo Outputs P90 P50 P10

GIIP (Bscf) 1,643 3,410 6,833


ECV1837.03 9

2.7 Reservoir Pressure and Temperature

Production and reservoir pressure data were supplied by the field Operator to Coastal. Reservoir pressures have been measured from wells PH-3ST, -4, -5 and -10ST using downhole gauges. Other reservoir pressures have been derived from surface measurements (from wells PH-4 and PH-5).

Pressure and production data have demonstrated that there are (at least) two pressure separate compartments (“tanks”) within the mapped closure. Further, and as demonstrated in this section, RPS has noted a stark difference between the volumetric estimation of the GIIP (Section 2.6) and that of the material balance volumetric modeling based on production and reservoir pressure (Section 2.11). The material balance analysis suggests that the producing wells are unlikely to be communicating with the full mapped reservoir volume. Therefore, RPS has categorised the GIIP volumes as either “Mapped” (via structural closure) or “Connected” (via pressure communication in the wellbores).

The “Connected” GIIP was estimated utilizing the dynamic data with the material balance method applied for South and Central areas, and assumes volumetric depletion. The Central area consists of wells PH-4 and PH-10ST, whereas the South area comprises wells PH-3 and PH-5. Interference pressure data has confirmed pressure communication between wells PH-4 and PH-10ST in Central area and between wells PH-3 and PH-5 in South areas1. Therefore, for this evaluation, a two tank material balance model is used. Figure 2-4 depicts the reservoir pressures for these two areas.

2.8 Production History

Gas and condensate production history for Sinphuhorm up to and including 31st December, 2011 is presented in Figure 2-5.

2.9 Well Production Testing

The well test history for the Sinphuhorm Gas Field is summarized below:

Phu Horm-3 was spudded on the 10th June, 2002 and temporarily suspended on 24th August, 2002 due to a gas kick. The well was re-entered on the 18th March, 2003 and the reservoir section was drilled using underbalanced drilling techniques to reach a total depth of 2695 mMDBRT (metres measured depth below rotary table). A buildup test over 300 hours was run, preceded by a flow period of about equal duration in October 2003. The maximum gas rate during DST-1 was 44.8 MMscf/d at 252 psi drawdown.

Phu Horm-4 was spudded on the 9th June, 2004. The reservoir section was drilled underbalanced and reached a total depth of 2621 mMDBRT. A buildup test lasting about 600 hours was run, preceded by a flow of period of 170 hours in November 2004. The average gas rate during the extended well test is 39.0 MMscf/d at 110 psi drawdown.

Phu Horm-5 was drilled during July-September 2004. The reservoir section was drilled underbalanced with the top of reservoir at 2477 mMDRT to a total depth of 2921 mMDRT. A buildup test lasting about 180 hours was run, preceded by a modified-isochronal test to obtain well deliverability during 17-27 July 2007. The average gas rates are provided in Table 2-3.

1 Sinphuhorm Field Reserves Assessment Methodology by HESS Oil & Gas (Thailand) Limited, dated 31st December, 2008.


ECV1837.03 10

Table 2-3 – PH-5 Welltest Summary

Flow Number

Average Gas Rate (MMscf/d)

Condensate-Gas Ratio (stb/MMscf)

Water-Gas Ratio (stb/MMscf)

Drawdown (psi)

1 10.9 5.2 0.6 61

2 21.2 5.3 0.7 232

3 33.2 5.3 1.5 496

Phu Horm-7 was spudded on the 27th September, 2006. The reservoir section was drilled under-balanced with no gas shows. PH-7 was suspended and the rig was released on 9th May, 2007.

Phu Horm-6 was drilled in a batch mode with the Phu Horm-7, and was spudded on the 12th January, 2007. On 15th April, 2007, the well was suspended after extensive flow testing. The gas flow rates were deemed sub-commercial for a tie-in at the time. The average sustained flow rate on test was 1.5 MMscf/day; however, during under-balanced drilling of the Pha Nok Khao Formation the well produced gas at rates up to 4 MMscf/day. It appears that some formation damage may have occurred when the well was killed during the later stages of the drilling operation. The well may be re-entered and stimulated at a later date; and all forecasts assume that, after stimulation, this well will achieve a similar inflow capacity as that currently seen from Phu Horm-10.

Phu Horm-10 was spudded on the 27th July, 2007. The well was sidetracked due to a stuck bottom-hole assembly. The main flow test (post-acidization) was conducted from 16th to 19th September, 2007 with an average flow rate of 9.9 MMscf/d at WHP of 1825 psi. SIWHP at the end of the test was 2773 psi. The Phu Horm-10 well was brought on stream as a production well in the first quarter of 2008 and produced at an average rate of 10 MMscf/d. There are indications of mechanical problems with the completion in this well and a re-entry is currently being planned.

The South Phu Horm–1 well was spudded on 18th February, 2008 and reached a total depth of 2660 mMDBRT. This well also tested gas at sub-commercial rates. The well was suspended pending evaluation of the stimulation potential.

2.10 Fluid Properties

Sinphuhorm gas is dry, with a methane content of 96 mole percent and a pentane plus (C5+) content of less than one mole percent.

Surface gas, liquid and water samples were collected from the PH-3, -4, and -5 wells during multi-rate tests. Further Pressure Volume Temperature (“PVT”) analyses were performed on wells PH-3 and -4. These tests show carbon dioxide up to 0.5 mole percent and very minimal traces of hydrogen sulphide (0.001%). Based on production data, the average Condensate Gas Ratio (“CGR”) is approximately 5.1 stb/MMscf.

2.11 Material Balance Analysis

Sufficient data is available to assess the range of in-place hydrocarbons within the Sinphuhorm Gas Field. This has been completed using geological mapping (Section 2.6) but can also be achieved by assessing the material balance of the field based on the current wells and pressure analyses.

An interpretation of the gas volumes that are in effective communication with the currently producing wells (PH-3, -4, -5 and 10ST) has been conducted. Material Balance (“P/Z”) methods were used to estimate the volume of “Connected” GIIP for individual tanks, as illustrated in Figure 2-8. Two separate tanks were modeled in MBalTM. Each tank has two wells;


ECV1837.03 11

PH-4 and -10ST in the Central area, and;

PH-3 and -5 in the Southern area.

Three possibilities were considered in the material balance modeling:

volumetric depletion,

water drive, and

compartmentalization.

Although a pressure match could be achieved by assuming a weak aquifer, aquifer influx is discounted as less probable as only a limited amount of relatively early production data is available. As of 31st December 2011, approximately 19% of the Best Estimate GIIP volume has been produced. Moreover, the mature, adjacent field of Nam Phong has demonstrated a volumetric depletion.

RPS has also assessed additional “estimated” reservoir pressures from the PH-3 and PH-5 for the South Area and PH-4 for the Central Area. These pressures were estimated from flowing well head pressures (“FWHPs”) (Figure 2-6) and are therefore only indicative of the actual reservoir pressure.

The last downhole pressure measurements were obtained during the static gradient survey is shown in Table 2-4.

Table 2-4 – The Latest Reservoir Pressure Measurements

Well Date Pressure (psia) Area Measurement

PH-3 17th June, 2011 3,168 South Gradient Survey

PH-4 18th September, 2011 2,878 Central Gradient Survey

PH-5 25th September, 2011 3,009 South Gradient Survey

PH-1 20th September, 2011 3,538 North Gradient Survey

RPS had generated the P/Z plots (Figure 2-7) for South and Central Areas separately using all the available pressure data. The GIIP distribution by “tank” is provided in Table 2-5, with the range of Low, Best and High Estimates based on the uncertainty associated with plotting the straight line through the data points. These volumes are the classified as “Connected” GIIPs. The Operator’s Best Estimate GIIP from the P/Z plot (Figure 2-8) assuming “Connected Area” as one tank is 769 Bscf, which is equal to the average of RPS’s Low Estimate and Best Estimate GIIPs.

Compartmentalization remains a possibility in the Central area but more pressure data are required to support this model. As the P/Z plot shows a straight line relationship (Figure 2-7), RPS has concluded that a volumetric depletion mechanism is most likely for the Sinphuhorm Gas Field based on the available data.


ECV1837.03 12

Table 2-5 – Effective “Connected” Estimates of GIIP, Sinphuhorm Gas Field (Bscf, 100% Basis)

Area Gas Initially In-Place (Bscf)

Low Best High

Central Area (PH-4 and PH-10ST) 327.8 379.5 446.3

South Area (PH-3 and PH-5) 386.1 444.5 510.9

Total 713.9 824.0 957.1

If the above volumes are back-interpolated using the average rock and engineering input parameters from the “Mapped” GIIP assessment, is discovered that the “tanks” cover approximate areas of 10-9 to 12 km2 each, which is significantly less that the Mapped Low Estimate GIIP area of 57 km2 and the Best Estimate GIIP area of 92 km2 (see Table 2-2).

A pressure gradient survey in PH-1 (about 4.3 km north of PH-10ST) conducted on 30th October, 2010 indicates a pressure depletion of 89 psi (2.5%) from the virgin reservoir pressure of 3680 psia taken in December 1984. The recent pressure gradient survey was conducted on 20th September, 2011 indicates a pressure depletion of 141 psi (3.8%). The PH-1 Shut-in Tubing Head Pressure monitoring indicating a pressure drop of 15 psi from 28th April, 2011 to 8th September, 2011.

2.11.1 “Mapped” versus “Connected” GIIP Estimates

The “Mapped” GIIP volume estimates are significantly larger than those that have been estimated using the material balance “Connected” tank assessment. This indicates that the Sinphuhorm Gas Field, as currently developed is only tapping a portion of the “Mapped” field, which may cover a significantly larger area. However, and as evidenced from the five non-producing wells/areas in the field, there may be several unidentified and un-penetrated ”tanks” that are not in communication. Wells outside the current Central and Southern area “tanks” have encountered generally tight reservoir that may, or may not, be conducive to production through stimulation (i.e. acidisation, fraccing etc). Presently, RPS has defined gas hosted in areas within the “Mapped” closure but not within the “Connected” “tanks” as the “Unconnected” volumes (Table 2-6).

Table 2-6 – Differences between the “Mapped” and “Connected” GIIP Estimates, Sinphuhorm Gas Field (Bscf, 100% Basis)

Gas Initially In-Place (Bscf)

Low Best High

“Mapped” GIIP (Table 2-2) 1,643 3,410 6,833

“Connected” GIIP (Table 2-5) 714 824 957

Difference (“Unconnected”) 929 2,586 5,876

2.12 Recoverable Hydrocarbons

The difference between the volumetric estimates and the material balance modeling suggests that the producing wells may not be communicating with the full reservoir volume. The Best Estimates


ECV1837.03 13

of “Connected” GIIP are approximately a quarter of the volume of the Best Estimate “Mapped’ GIIP.

The field is most likely divided into two or more areas that are separated by a large fault or zones of tight/un-fractured Pha Nok Khao Formation. This compartmentalisation is supported by pressure data that suggests the two areas are not in significant pressure communication.

2.12.1 Further Development Plans

The Operator has detailed in its five-year work plan and budget (“WP&B”) that there will be four wells drilled within the Sinphuhorm structure. No maps detailing the location for these wells planned in 2013 have been provided to RPS. For their location description it is noted that one well will be sited in the southern portion of the field, a further in the central portion and two additional wells in the Northern sector. It is unknown whether the northern wells will be targeting a new “tank”, testing the “Unconnected” area, or drilling the northern portion of the Central “tank”.

Well PH-8 in the Northern area. Well PH-9 in the Northern area. Well PH-11 in the Southern area - possibly part of the Southern “tank” (PH-5 / PH-3) –

effectively increasing the rate of recovery of hydrocarbons with marginal incremental volume.

Well PH-12 in the Central area - possibly part of the Central “tank” (PH-10ST / PH-4) – effectively increasing the rate of recovery of hydrocarbons with marginal incremental volume.

In addition to drilling new wells, the Operator has presented plans to conduct the following appraisal in 2013:

Well PH-6 in the Northwestern area – a workover or sidetrack on the tight PNK formation that may be connected to the Central area “tank”.

Well PH-10ST in the Central “tank” – a workover of this well.

“Connected” Area Development

The “Connected” gas resources have been estimated using static material balance P/Z modeling methods, based on production and pressure data supplied by Coastal and Salamander. The “Connected” GIIP, as previously mentioned, was derived from material balance calculations shown in Figure 2-8 with resulting GIIP values presented in Table 2-5. The EUR has been updated following plans by the Operator to drill additional wells. RPS has assigned two wells to the Low Estimate (the Southern and Central area wells) and four additional wells to the Best and High Estimates.

Besides the currently producing wells, the gas recovery from the planned wells is included in various reserve estimates as in Table 2-7. The Low Estimate case consists of two infill wells only and the Best and High Estimates cases consist of two infill wells plus two appraisal wells. These wells have been included in the material balance model. The wells inflow performance was assumed to be average of the currently producing wells.


ECV1837.03 14

Table 2-7 – Drilling Infill and Appraisal Wells and Wells Allocations for Reserves

Schedule Drilling Area Low

Estimate

Wells

Best

Estimate

Wells

High

Estimate

Wells

Q1 – 2013 North of Central Area - PH-8 PH-8

Q2 – 2013 North of Central Area - PH-9 PH-9

Q3 – 2013 South PH-11 PH-11 PH-11

Q4 – 2013 Central PH-12 PH-12 PH-12

Total Wells 2 4 4

“Unconnected” Area Development

It is likely that significantly more wells would be required to access the “Mapped” volumes that lie outside the “Connected” tanks (i.e. the presently “Unconnected” volumes). The Operator has presented that there are no firm development plans to develop the tight, unfractured, undolomitised limestones.

In late 2007, RPS devised a conceptual plan of development for the “Unconnected” volumes based upon analogue well spacing noted in the neighbouring Nam Phong field (approximately one well every 4.0 km2) and other tight gas analogue fields (approximately one well every 2.5 km2). Although not adopted by the Operator or Joint Venture partners, the volumes associated with that development plan were classified as Reserves as the Operator had intended to appraise the tighter sections of the PNK limestone. However, the last appraisal of the tighter gas in the production concessions (EU1/E5N) resulted in a failed well. That well, PH-7, was spudded in late 2007 and suspended in May 2008. Further appraisal has not occurred over the past 4 years and there are no definitive plans to undertake the tight gas development in the Operator’s five-year WP&B.

The SPE document “Guidelines for Application of the Petroleum Resource Management System” published in November 2011 (footnote: 2) state that a reasonable timeframe may be given for the development of Reserves; placing that period at 5 years (section 2.1.2 of the Guidelines). That five year time marker will be reached by the end of 2012 and, as per the Guidelines, the Operator must now demonstrate a firm intention to proceed with development based upon all of the following criteria:

Evidence to support a reasonable timetable for development. A reasonable assessment of the future economics of such development projects meeting

defined investment and operating criteria. A reasonable expectation that there will be a market for all or at least the expected sales

quantities of production required to justify development. Evidence that the necessary production and transportation facilities are available or can be

made available. Evidence that legal, contractual, environmental and other social and economic concerns

will allow for the actual implementation of the recovery project being evaluated. To be included in the Reserves class, a project must be sufficiently defined to establish its

commercial viability. There must be a reasonable expectation that all required internal and

2 SPE, AAPG, WPC, SPEE, SEG, November 2011: Guidelines for Application of the Petroleum Resources Management System, pp221.


ECV1837.03 15

external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame.

To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

RPS has maintained a portion of the currently defined “Unconnected” volumes as Reserves but notes that these will be re-classified as Contingent Resources unless all of the commercial determination requirements stated above are demonstrated by the end of 2012.

2.12.2 EUR Volumes

We have not included any of the “Unconnected” volumes within the Low Estimate EUR for the Sinphuhorm Field, such that Proved Reserves are only derived from the “Connected” volume “tanks”. The Best and High Estimate EURs are derived on analogue well spacing and a 15 year extension to the Gas Sales Agreement.

The Sinphuhorm EUR volumes are presented in Table 2-8:

Table 2-8 – Sinphuhorm Gas Field EUR (Bscf, 100% Basis)

Gas Volumes

Low

Estimate

Best

Estimate

High

Estimate

“Connected” GIIP, Bscf (Table 2-6) 714 824 957

“Unconnected” GIIP, Bscf (Table 2-6) 1) 0 2,586 5,876

TOTAL GIIP, Bscf 714 3,410 6,833

Overall Recovery Factor, % (back interpolated) 90% 50% 83%

Total Wellhead Gas EUR, Bscf 2) 643 1,719 5,657

Total Sales Gas EUR, Bscf 3) 638 1,707 5,618

Note :

1) No development of the “Unconnected” volumes for the Low Estimate.

2) Best and High Estimates assume full production to 2050 (effective ultimate EUR).

3) After applying shrinkage of 0.7% due to fuel and flare.

2.12.3 Resource Classification

Not all of the above EUR volumes can be classified as Reserves. A Gas Sales Agreement (“GSA”) limits the volumes that may be monetized. This GSA allows for a Daily Contract Quantity (“DCQ”) of 108 MMscf/d, subject to a “Buyers Maximum DCQ Reduction Amount”. The DCQ Reduction allows the Sinphuhorm DCQ to be reduced in the early years in order to allow for preferential supply to the GSA from the Nam Phong field. The GSA is a 15 year contract that supplies gas to the Nam Phong Power Plant and expires on the 28th November, 2021.


ECV1837.03 16

The exact Sinphuhorm DCQ reduction amounts will depend on the decline of the Nam Phong field. The DCQ reduction, as currently provided by Coastal and Salamander, is therefore as set out in the profile in Table 2-9 but will be dependent on the effective Nam Phong producing rates.

Table 2-9 – Sinphuhorm Gas Sales Agreement – DCQ and DCQ Reduction

Contract

Year Period

DCQ

(MMscf/d)

DCQ Reduction

Nam Phong 1

(MMscf/d)

Sinphuhorm 2

(MMscf/d)

1 1/10/2006 – 30/09/2007 108 19.0 89.0

2 1/10/2007 – 30/09/2008 108 15.6 92.4

3 1/10/2008 – 30/09/2009 108 11.1 96.9

4 1/10/2009 – 30/09/2010 108 17.6 90.4

5 1/10/2010 – 30/09/2011 108 12.7 95.3 5

6 3 1/10/2011 – 30/09/2012 108 12.0 96.0 5

7 1/10/2012 – 30/09/2013 108 11.2 96.8

8 1/10/2013 – 30/09/2014 108 9.7 98.4

9 1/10/2014 – 30/09/2015 108 8.3 99.7

10 1/10/2015 – 30/09/2016 108 7.2 100.8

11 1/10/2016 – 30/09/2017 108 6.2 101.8

12 1/10/2017 – 30/09/2018 108 5.3 102.7

13 1/10/2018 – 30/09/2019 108 4.6 103.4

14 1/10/2019 – 30/09/2020 108 3.9 104.1

15 1/10/2020 – 30/09/2021 108 3.3 104.7

16 4 1/10/2021 – 28/11/2021 108 0 108.0

Notes 1) The Nam Phong Expected Forecast (updated by Coastal and Salamander) 2) Sinphuhorm DCQ – GSA DCQ – Nam Phong Production 3) 1st January, 2012 is in Contract Year 6. 4) Contract Year 16 has 58 days (from 1st October, 2021 to 28th November, 2021) 5) The buyer had requested an increase to the DCQ rate to 96 MMscf/d from 9th January, 2011.

Therefore, the average DCQ rate for contract year 5 (from 1st October, 2010 to 30th September, 2011) was 95.3 MMscf/d. RPS had assumed that the DCQ rate remains 96 MMscf until the end of contract year 6. For the subsequent contract years, the DCQ rates remain as per the previous evaluation.

As of 31st December, 2011, 156.7 Bscf of gas has been sold from the Sinphuhorm Gas Field. Due to flooding, the gas production has been reduced from September until December 2011. It has been assumed that the production will be back to normal rate in April 2012. As of December 2011, approximately 8 Bscf of contracted gas volume is not sold due to gas production at reduced rate.


ECV1837.03 17

It should be noted that the Sinphuhorm production license for the EU1 and E5N blocks expire on 19th May, 2034 extend beyond the current GSA expiry date of 28th November, 2021. Coastal are confident that an extension or new GSA might be signed, particularly as the field will be producing at its highest rate in 2021. Based that a new/extended GSA will be signed, we have estimated 2P and 3P Reserves volumes.

Section 3.3.3 of the March 2007 SPE PRMS document states that ”where the risk of cessation of rights to produce, or inability to secure gas contracts, is not considered significant, evaluators may choose to incorporate the uncertainty by categorizing quantities to be recovered beyond the current contract as Probable or Possible Reserves”.

In the current economic climate, RPS believes that it is probable, but, by no means certain, that the vendor will locate a willing buyer for the remaining gas volumes; and that the resulting terms will be sufficiently attractive for Coastal and its partners to maintain their ongoing participation. Note, however, the extension GSA volumes are almost exclusively produced from the conceptual development of the “Unconnected” volumes. Thus, they are at risk of being re-classified as Contingent Resources as stated in Section 2.11.1 of this report. Table 2-10 provides a summary.

Table 2-10 – Contracted and Uncontracted Gas and Condensate Volumes

Sinphuhorm - Hydrocarbon Resource Base

Low Estimate

Best Estimate

High Estimate Remarks

"Connected" Gas

A South Area “Connected” GIIP, Bscf 328 379 446 From P/Z Analysis (Table 2-5)

B Central Area “Connected” GIIP, Bscf 386 444 511 From P/Z Analysis (Table 2-5)

C Total “Connected” GIIP, Bscf 714 824 957 A+B

D Recovery Factor, % 90% 90% 90% Best Estimate from Material Balance Modelling

E "Connected" EUR Wellhead Gas, Bscf 643 742 861 C*D

F "Connected" EUR Sales Gas, Bscf 638 736 855 E*(100%-0.7%) : for Shrinkage

"Unconnected" Gas

G Total “Unconnected” GIIP, Bscf 929 2,586 5,876 From "Mapped" minus "Connected" volumes

H Recovery Factor, % 0% 38% 82% From Nam Phong and US analogue

J "Unconnected" EUR Wellhead Gas, Bscf 0 977 4796 G*H

K "Unconnected" EUR Sales Gas, Bscf 0 970 4,763 J*(100%-0.7%) : for Shrinkage

Gas Production & Remaining Resources

L Total EUR Sales Gas, Bscf 1) 638 1,707 5,618 F+K

M Sales Gas Sold, Bscf -157 -157 -157 Historical sales gas production

N Remaining EUR Sales Gas, Bscf 481 1,550 5,461 L-N

Contracted and Uncontracted Gas

P Contracted Sales Gas, Bscf 352 964 964 DCQ (including GSA extension/downtime)

Q “Lost” Gas, Bscf -8 -8 -8 Inability to meet the contracted DCQ

R Sales Gas Volumes, Bscf 1) 344 956 956 Sales Gas Profiles at end of GSA/extensions

S Uncontracted Gas Resource, Bscf 2) 138 594 4,505 N-R : Uncontracted Gas Resources


ECV1837.03 18

Sinphuhorm - Hydrocarbon Resource Base

Low Estimate

Best Estimate


Condensate Production & Remaining Resources

T CGR, stb/MMscf 5.1 5.1 5.1 From production ratios

U Condensate Sold, MMbbl -0.8 -0.8 -0.8 Historical sales condensate production

V Sales Condensate Volumes, MMbbl 1.8 4.9 4.9 R*T : Sales Condensate at end of GSA/extensions

W Uncontracted Condensate Resource, MMbbl 2) 0.7 3.5 24.5 From production profiles

Notes:

1) Assumes only “Connected” volumes are sold in the Low Estimate Gas Sales case. 2) Uncontracted Sales Gas and Condensate volumes are assigned to Contingent Resources.

Maintenance days have been allocated in the Gas Sales Agreement; applying 20 days per year in the Low Estimate and no downtime for the Best and High Estimates. This reduces solely the minimum obligation of the buyer and not the vendor.

2.12.4 Uncontracted Gas and Condensate Volumes

Volumes of gas that will not be produced during the GSA extension term have been classified as Contingent Resources Table 2-11. The majority of these lie within the “Unconnected” area. Note that these volumes may be increased should the “Unconnected” volumes currently assigned to Reserves be re-classified as Contingent Resources (see Section 2.11.1 of this report).

Table 2-11 – Uncontracted Recoverable Sales Gas Volumes

Sinphuhorm – Uncontracted Recoverable Volumes

Low Estimate

Best Estimate


Uncontracted Sales Gas (Bscf) 1) 138 594 4,505 (Table 2-10)

Uncontracted Condensate (MMbbl) 0.7 3.5 24.5 (Table 2-10)

Note:

1) After applying 0.7% shrinkage for fuel and flare.


L15/43

N th Ph H0 25

Scale (km)

North Phu Horm

Sinphuhorm

Nam Phong

L27/43

Sinphuhorm Gas Field (Concessions EU1, E5N)

Current Coastal Exploration Concessions

Original Coastal Concessions L15/43 and L27/43

Map supplied by APICO


Figure 2-1 – Location of the Sinphuhorm Gas Field and Concession L15/43

L27/43


Kar

sted

Ls.

Do

lom

ite

Kar

sted

Ls.

Do

lom

ite

Kar

sted

Ls.

Do

lom

ite


Figure 2-2 – Onshore Thailand Stratigraphic Column


PH-2PH-1

PH-6

PH-2PH-1

PH-6

PH-7 PH-10PH-4

PH-3PH-5

PH-7 PH-10PH-4

PH-3PH-5

SPH-1SPH-1

Western Limit of Indosinian 1

5 km

Low: 2,156 mTVDSS

Best: 2,279 mTVDSS

High: 2,587 mTVDSS

Estimated Gas-Water Contact

Best

Maximum

Western Limit of Indosinian-1 Unconformity Truncation

Approximate “tank” areas


Figure 2-3 – Sinphuhorm Gas Field Top Structure Map (RPS)


3800

4000

Sinphuhorm (Central Area) - Reservoir Pressure

PH-10ST PH-4

2400

2600

2800

3000

3200

3400

3600

es

erv

oir

Pre

ss

ure

(p

sia

)

2000

2200

2400

Jan-04 May-05 Oct-06 Feb-08 Jul-09 Nov-10 Apr-12

Re

Date

Sinphuhorm (South Area) - Reservoir Pressure

PH-5 PH-3

2800

3000

3200

3400

3600

3800

4000

rP

res

su

re (

ps

ia)

PH 5 PH 3

2000

2200

2400

2600

2800

Sep-02 Jan-04 May-05 Oct-06 Feb-08 Jul-09 Nov-10 Apr-12

Re

se

rvo

ir

Date

3500

3700

3900

e (p

sia)

Sinphuhorm - Average Reservoir Pressure

Central Area South Area

2500

2700

2900

3100

3300

May 05 Oct 06 Feb 08 Jul 09 Nov 10 Apr 12

Res

ervo

ir P

ress

ure


Figure 2-4 – Sinphuhorm Gas Field Reservoir Pressure

May-05 Oct-06 Feb-08 Jul-09 Nov-10 Apr-12

Date



Figure 2-5 – Sinphuhorm Gas Field Production History


3000.0120.00

Central Area ‐ Gas Rate & FWHP

PH‐10ST Gas Rate PH‐4 Gas Rate PH‐10ST FWHP PH‐4 FWHP

2000.0

2500.0

80.00

100.00

sig)

Mscf/d)

500 0

1000.0

1500.0

20.00

40.00

60.00

FWHP (ps

Gas Rate (M

M

0.0

500.0

0.00

20.00

29‐Nov‐06 25‐Sep‐07 21‐Jul‐08 17‐May‐09 13‐Mar‐10 07‐Jan‐11 03‐Nov‐11

Date

South Area ‐ Gas Rate & FWHP

2500.0

3000.0

80.00

90.00

100.00

PH‐5 Gas Rate PH‐3 Gas Rate PH‐5 FWHP PH‐3 FWHP

1000 0

1500.0

2000.0

40.00

50.00

60.00

70.00

FWHP (psig)

Gas Rate (M

Mscf/d)

0.0

500.0

1000.0

0.00

10.00

20.00

30.00

29‐Nov‐06 25‐Sep‐07 21‐Jul‐08 17‐May‐09 13‐Mar‐10 07‐Jan‐11 03‐Nov‐11


Figure 2-6 – Sinphuhorm Gas Field FWHPs

Date


4500

Central AreaCentral Area Low Est. Best Est. High Est.

2500

3000

3500

4000

sia

)

500

1000

1500

2000

P/Z

(ps

444.500 100 200 300 400 500 600 700

Cumulative Gas (Bscf)

South Area

3500

4000

4500

South AreaSouth Area Low Est. Best Est. High Est.

1500

2000

2500

3000

P/Z

(ps

ia)

379.50

500

1000

0 50 100 150 200 250 300 350 400 450 500

Cumulative Gas (Bscf)


Figure 2.7 – Sinphuhorm Gas Field P/Z GIIP Estimates (RPS)

( )


. 201

1)et

ing

(14th

Oct

ober

cal C

omm

ittee

Mee

m O

pera

tor’s

Tec

hni

Fro

m


Figure 2.8 – Sinphuhorm Gas Field P/Z GIIP Estimate (Operator)


ECV1837.03 27

3 Commercial Evaluation

3.1 Thai Concession Terms

The Sinphuhorm gas field lies within the EU1 and E-5 production licenses on the Khorat Plateau, Thailand. The principal commercial terms are summarized in Table 3-1:

Table 3-1 – Principal Commercial Terms

Royalty (paid in cash or in kind) - tax creditable 12.5%

Tax 50%

Depreciation rate for capital expenditure 20% p.a.

It is assumed that maintenance operations are curtailed and de-manning commences in the last four years of the contract period.

3.2 Capital and Operating Costs

Table 3-2 presents a summary of the forecasted Capital Expenditure (“CAPEX”) and Operating Expenditure (“OPEX”) for the 1P, 2P, and 3P profiles provided by Coastal.

Table 3-2 – Forecast CAPEX and OPEX (US$ Million, 2012) for the Sinphuhorm Development

Year 1P 2P 3P

CAPEX OPEX CAPEX OPEX CAPEX OPEX

2012 4.3 14.8 4.3 14.8 4.3 14.8

2013 56.65 20.6 116.8 20.6 116.8 20.6

2014 10.2 14.3 16.4 14.3 16.4 14.3

2015 14.4 14.8 14.4 14.8 14.4 14.8

2016 10.7 15.1 10.7 15.1 10.7 15.1

2017 15.1 15.1 15.1

2018 15.1 15.1 15.1

2019 15.1 15.1 15.1

2020 15.1 15.1 15.1

2021 15.1 15.1 15.1

2022 15.1 15.1

2023 15.1 15.1

2024 15.1 15.1


ECV1837.03 28

Year 1P 2P 3P

CAPEX OPEX CAPEX OPEX CAPEX OPEX

2025 15.1 15.1

2026 15.1 15.1

2027 15.1 15.1

2028 15.1 15.1

2029 15.1 15.1

2030 15.1 15.1

2031 15.1 15.1

2032 15.1 15.1

2033 15.1 15.1

2034 15.1 15.1

2035 15.1 15.1

2036 15.1 15.1

3.3 Gas Contract and Prices

3.3.1 Sinphuhorm Contract Volumes

A gas sales contract is in place between the parties in the Sinphuhorm field and the Petroleum Authority of Thailand (“PTT”) as the buyer. The agreed contract volumes are shown in Table 2-9.

The contracted volumes also assume that the maximum scheduled number of maintenance days are taken as defined in the contract.

3.3.2 Sinphuhorm Gas Price

The contract gas price is based on a formula linking the final gas price to the 6-month average price for Singapore posted HSFO 180. The final “Contract Price” is based on the “Current Price”, which is a function of the “Normal Price”, and a “Floor Price”, multiplied by a scaling factor.

3.3.3 Sinphuhorm Unitisation

For the 1P case, the “Connected” Sinphuhorm gas is estimated to be contained entirely within the EU1 and E-5 production licenses, in which Coastal has a 12.6% working interest. For the 2P and 3P case, the field, as modelled, extends out of the Production Licenses and into the adjacent L15/43 exploration license, where Coastal has a 36.1% working interest. For the 2P and 3P cases, we have assumed the probability that this field may be unitised from 1st January, 2014. The estimated unitised shares are as shown in Table 3-3.


ECV1837.03 29

Table 3-3 – Estimated Unitised Share for the Sinphuhorm Gas Field

Reserves Case: EU1 and E-5 L15/43 Coastal Final Working

Interest in Unitised Share

1P 100% 0% 12.60%

2P 94.0% 6.0% 14.00%

3P 84.7% 15.3% 16.20%

The percentages that RPS has presented in this report are based solely on RPS’s assessment of the structure of the Sinphuhorm Gas Field and any envisaged unitisation activities. Any working interest and resource estimates regarding the unitised share for the Sinphuhorm Gas Field are subject to change with further data acquisition and future activities.


ECV1837.03 30


ECV1837.03 31

4 Resource Statement

The extent of the Sinphuhorm Field has not been fully delineated by drilling. In RPS’s assessment, the “Connected” volume does not extend into the exploration concession to the South (L15/43), so there are no unitization assumptions in the Low Estimate EUR Forecast. Resulting Proved volumes are based on the assumption that Coastal’s Working Interest will remain at 12.6%.

For the Best Estimate GIIP, approximately 6% of the “Mapped” field was estimated to lie in block L15/43. Coastal’s Working Interest in that concession is 36.1% through their 100% interest in APICO. Thus, any production from this area would result in a small increase in Coastal’s Working Interest in the Sinphuhorm Field. It is estimated that this would have the effect of increasing Coastal’s Working Interest in a unitized Sinphuhorm field to 14.0% in the Best Estimate scenario. This Working Interest has been used in the estimation of the 2P Reserves and 2C Contingent Resources.

The High Estimate 3P and 3C cases assume approximately 15.3% of the mapped field lies in block L15/43. This increased Coastal’s Working Interest in the Sinphuhorm Field to 16.2%. It has been assumed that negotiations and equity determinations will be completed by 1st January, 2014, at which time equalization payments will be made.

Table 4-1 and Table 4-2 show the gross sales gas and condensate Reserves as of 1st January, 2012.

Table 4-1 – Sinphuhorm Field Gross Reserves Estimate as of 1st January, 2012

Gross Reserves

Proved Proved plus Probable

Proved plus Probable plus

Possible

Sinphuhorm Sales Gas (Bscf) 344 957 957

Sinphuhorm Condensate (MMbbl) 1.8 4.9 4.9

Total (MMBOE)(1) 59.0 164.3 164.3

Notes: 1) Gas to BOE conversion factor is 6.0 Bscf per 1.0 million barrels of oil equivalent (BOE).

Table 4-2 – Sinphuhorm Field Coastal’s Net Entitlement Reserves Estimate as of 1st January, 2012

Coastal’s Net Entitlement Reserves

Proved Proved plus Probable


Possible

Working Interest (%)(1) 12.6% 14.0% 16.2%

Sinphuhorm Sales Gas (Bscf) 43 133 152

Sinphuhorm Condensate (MMbbl) 0.2 0.7 0.8

Total (MMBOE)(2) 7.4 22.9 26.2

Notes: 1) Coastal’s Working Interest from 1st January, 2014 after unitisation. 2) Gas to BOE conversion factor is 6.0 Bscf per 1.0 million barrels of oil equivalent (BOE).


ECV1837.03 32

Table 4-3 and Table 4-4 show the sales gas and condensate Reserves reconciliation. Apart from production adjustments, the revisions to 1st January, 2012 for the field have shown:

The reduction in gas Reserves are due to Coastal’s assumption that the Nam Phong field decline is much less than previously assumed; this reduces the Sinphuhorm DCQ rate.

A slight decrease in condensate volume is due to use of lower historical CGR and reduced raw gas production.

Table 4-3 – Sinphuhorm Field Gross Sales Gas Reserves Reconciliation

Proved (Bscf)

Proved plus Probable

(Bscf)


Possible (Bscf)

1st January, 2011(1) 370 993 993

Extensions

Discoveries

Technical Revisions 4 -6 -6

Acquisitions

Depositions

Economic Factors

Production -30 -30 -30

1st January, 2012 344 957 957

Note: 1) Previous estimates based on work by RPS for Coastal Energy in a

report entitled “Sinphuhorm Gas Field Reserves Update as of 1st January, 2011”, issued on the 14th April, 2011 (ECV1725).

Table 4-4 – Sinphuhorm Field Gross Condensate Reserves Reconciliation

Proved (MMbbl)

Proved plus Probable (MMbbl)


Possible (MMbbl)

1st January, 2011(1) 1.9 5.2 5.2

Extensions

Discoveries

Technical Revisions 0 -0.2 -0.2

Acquisitions

Depositions

Economic Factors

Production -0.1 -0.1 -0.1

1st January, 2012 1.8 4.9 4.9




ECV1837.03 33

Reconciliations have been completed for Coastal’s Working Interest and Net Company Reserves, as presented in Table 4-5 and Table 4-6.

Table 4-5 – Sinphuhorm Field Coastal Net Company Sales Gas Reserves Reconciliation (Forecast Prices and Costs)

Proved (Bscf)

Proved plus Probable

(Bscf)


Possible (Bscf)

1st January, 2011(1) 47 139 160

Extensions

Discoveries

Technical Revisions 0 -2 -3

Acquisitions

Depositions

Economic Factors

Production -4 -4 -4

1st January, 2012 43 133 152



Table 4-6 – Sinphuhorm Field Coastal Net Company Condensate Reserves Reconciliation (Forecast Prices and Costs)

Proved (MMbbl)

Proved plus Probable (MMbbl)


Possible (MMbbl)

1st January, 2011(1) 0.2 0.7 0.8

Extensions

Discoveries

Technical Revisions 0 0 0

Acquisitions

Depositions

Economic Factors

Production -0.0 -0.0 -0.0

1st January, 2012 0.2 0.7 0.8




ECV1837.03 34

The gas and condensate production profiles are presented in Figure 4-1 and Figure 4-2, respectively. Forecast charts for the respective hydrocarbon streams are presented in Figure 4-3 and Figure 4-4.


Client Coastal Energy 1P 12.6 %

CASE PARAMETERS COMPANY INTERESTS

gy

Region South East Asia 2P 14.0 %

Country Thailand 3P 16.2 %

Field Sinphuhorm Licence

Phase Gas

Production

FORECAST FUTURE GROSS FIELD PRODUCTION (100% BASIS)

Year 1P or P90 2P or P50 3P or P10

Days

Cum. Cum. Cum.

mmscf/d bscf bscf mmscf/d bscf bscf mmscf/d bscf bscf

1 2012 346/366 92 32 32 91 33 33 91 33 33

2 2013 345/365 97 34 65 97 35 69 97 35 69

3 2014 345/365 99 34 99 99 36 105 99 36 105

4 2015 345/365 100 34 134 100 36 141 100 36 141

5 2016 346/366 101 35 169 102 37 178 102 37 178

6 2017 345/365 102 35 204 102 37 216 102 37 216

7 2018 345/365 103 35 240 103 38 253 103 38 253

8 2019 345/365 104 36 275 103 38 291 103 38 291

9 2020 346/366 104 36 311 104 38 329 104 38 329

10 2021 314/365 103 32 344 106 39 368 106 39 368

11 2022 365 109 40 407 109 40 407

12 2023 365 108 39 447 108 39 44712 2023 365 108 39 447 108 39 447

13 2024 366 108 39 486 108 39 486

14 2025 365 108 39 526 108 39 526

15 2026 365 109 40 566 109 40 566

16 2027 365 109 40 606 109 40 606

17 2028 366 107 39 645 107 39 645

18 2029 365 108 39 684 108 39 684

19 2030 365 108 39 724 108 39 72419 2030 365 108 39 724 108 39 724

20 2031 365 108 40 763 108 40 763

21 2032 366 107 39 802 107 39 802

22 2033 365 108 39 842 108 39 842

23 2034 365 108 39 881 108 39 881

24 2035 365 108 39 921 108 39 921

25 2036 333 108 36 957 108 36 957

Sub Total 344 957 957

Remaining

Total 344 957 957

Notes: 1P uses 314 days in 2021 (from 1 Jan 2021 till 28 Nov 2021 with 18 days maintenance days)

1P - Assumes 20 maintenance days per year.

2P & 3P - No maintenance days and end date is 28 November 2036.


Figure 4.1 – Sinphuhorm Gas Field Gas Production Profile


Client Coastal Energy 1P 12.6 %

CASE PARAMETERS COMPANY INTERESTS

gy

Region South East Asia 2P 14.0 %

Country Thailand 3P 16.2 %

Field Sinphuhorm Licence

Phase Condensate

Production

FORECAST FUTURE GROSS FIELD PRODUCTION (100% BASIS)

Year 1P or P90 2P or P50 3P or P10

Days

Cum. Cum. Cum.

stb/d MM bbls MM bbls stb/d MM bbls MM bbls stb/d MM bbls MM bbls

1 2012 346/366 472 0.2 0.2 467 0.2 0.2 467 0.2 0.2

2 2013 345/365 499 0.2 0.3 497 0.2 0.4 497 0.2 0.4

3 2014 345/365 507 0.2 0.5 507 0.2 0.5 507 0.2 0.5

4 2015 345/365 514 0.2 0.7 514 0.2 0.7 514 0.2 0.7

5 2016 346/366 519 0 2 0 9 524 0 2 0 9 524 0 2 0 95 2016 346/366 519 0.2 0.9 524 0.2 0.9 524 0.2 0.9

6 2017 345/365 524 0.2 1.0 524 0.2 1.1 524 0.2 1.1

7 2018 345/365 528 0.2 1.2 528 0.2 1.3 528 0.2 1.3

8 2019 345/365 532 0.2 1.4 531 0.2 1.5 531 0.2 1.5

9 2020 346/366 535 0.2 1.6 535 0.2 1.7 535 0.2 1.7

10 2021 314/365 529 0.2 1.8 542 0.2 1.9 542 0.2 1.9

11 2022 365 561 0.2 2.1 561 0.2 2.1

12 2023 365 555 0 2 2 3 555 0 2 2 312 2023 365 555 0.2 2.3 555 0.2 2.3

13 2024 366 554 0.2 2.5 554 0.2 2.5

14 2025 365 555 0.2 2.7 555 0.2 2.7

15 2026 365 561 0.2 2.9 561 0.2 2.9

16 2027 365 561 0.2 3.1 561 0.2 3.1

17 2028 366 552 0.2 3.3 552 0.2 3.3

18 2029 365 554 0.2 3.5 554 0.2 3.5

19 2030 365 555 0.2 3.7 555 0.2 3.7

20 2031 365 556 0.2 3.9 556 0.2 3.9

21 2032 366 551 0.2 4.1 551 0.2 4.1

22 2033 365 555 0.2 4.3 555 0.2 4.3

23 2034 365 555 0.2 4.5 555 0.2 4.5

24 2035 365 555 0.2 4.7 555 0.2 4.7

25 2036 333 553 0.2 4.9 553 0.2 4.9

Sub Total 1.8 4.9 4.9

Remaining

Total 1.8 4.9 4.9

Notes: 1P uses 314 days in 2021 (from 1 Jan 2021 till 28 Nov 2021 with 18 days maintenance days)

1P - Assumes 20 maintenance days per year.

2P & 3P - No maintenance days and end date is 28 November 2036.


Figure 4.2 – Sinphuhorm Gas Field Condensate Production Profile


Sinphuhorm Sales Gas Profiles

80

100

120

20

40

60

MM

scf/

d

0

20

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

1P 2P 3P


Figure 4.3 – Sinphuhorm Gas Field Gas Production Forecast


Sinphuhorm Condensate Production Profiles

400

500

600

200

300

400

stb

/d

0

100

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

1P 2P 3P


Figure 4.4 – Sinphuhorm Gas Field Condensate Production Forecast


ECV1837.03 39

5 NI 51-101 Reporting of Reserves

A summary of the Reserves for the Sinphuhorm field as calculated in accordance with Canadian National Instrument 51-101 and the Reserve and Resource definitions of the Canadian Oil and Gas Evaluation Handbook is shown in Table 5-1 to Table 5-9.

Thailand is a Tax and Royalty regime. Royalty is treated as tax, and thus, attributable Net Entitlement Share is reported as Coastal’s working interest volumes including Royalty.

Table 5-1 – Sinphuhorm Field Summary of the Evaluation of the Petroleum Reserves as of 1st January, 2012

Gross Net 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Non-Associated Gas (MMcf)




Total Proved 501,529 343,690 43,305 274 215 173 144 122 186 147 119 99 84

Probable 612,926 612,926 89,750 679 303 148 79 45 444 198 97 52 30

Total Proved + Probable 1,114,455 956,616 133,055 953 517 321 222 167 630 345 216 151 114

Natural Gas Liquid (Mbbl)

Proved Developed Producing 2,143 1,344 169 13 10 9 7 6 9 7 6 5 4


Proven Undeveloped 422 422 53 4 3 2 2 1 3 2 2 1 1

Total Proved 2,565 1,765 222 17 14 11 9 8 12 9 8 6 5

Probable 3,148 3,148 461 46 21 10 6 3 30 14 7 4 2

Total Proved + Probable 5,713 4,913 683 63 34 21 15 11 42 23 14 10 8

Grand Total (MBOE)(1)




Total Proved 86,153 59,047 7,440 291 228 184 153 129 198 156 127 105 90

Probable 105,302 105,302 15,419 725 323 159 85 49 474 212 104 56 32

Total Proved + Probable 191,455 164,349 22,859 1016 552 343 237 178 671 368 231 161 122

After Income Taxes

Net Present Values (US$ Million)

Notes: (1) Using 6.0 Mscf/BOE

Remaining

Reserves

Company Before Income TaxesProduct Classification

Ultimate

Reserves


ECV1837.03 40

Table 5-2 – Total Future Net Revenue Undiscounted Forecast Prices and Costs as of 1st January, 2012

Reserves Category Revenue Royalties

Operating Costs

Development Costs

Abandonment &

Reclamation Costs

Future Net

Revenue Before Income

Tax

Income Tax

Future Net

Revenue After

Income Tax

US$ Million

Proved Reserves 372 46 21 13 0 291 93 198

Proved plus Probable Reserves

1,264 158 68 22 0 1,016 345 671

Proved plus Probable Reserves plus Possible Reserves

1,449 181 78 23 0 1,167 397 770

Table 5-3 – Sinphuhorm Field Volumetric Reserves Estimates Reservoir Data

Monte Carlo Parameter Inputs Low Input Mid Input High Input

Gross Rock Volume (thousand acre.ft) 6,105 13,820 44,520

Gas-water Contact (m TVDSS) -2,156 -2,279 -2,587

Net-to-Gross (%) 100 100 100

Matrix Porosity (%) 1.5 2.5 3.0

Matrix Water Saturation (%) 60.0 42.5 35.0

Fracture Porosity (%) 0.22 0.67 2.00

Fracture Water Saturation (%) 20 15 10

Gas Expansion Factor (scf/rcf) 207 208 209

Monte Carlo Outputs P90 P50 P10

GIIP (Bscf) 1,643 3,410 6,833

R

ESER

VES

AN

D R

ESO

UR

CES

CER

TIF

ICA

TIO

N

FOR

TH

E SI

NPH

UH

OR

M G

AS

FIEL

D A

S O

F 1st

JAN

UA

RY

, 201

2

EC

V183

7.03

41

Tab

le 5

-4 –

Est

imat

es o

f P

rove

d R

eser

ves

and

Net

Pre

sent

Val

ues

for

the

Sinp

huho

rm F

ield

(as

of

1st

Janu

ary,

201

2)

Non

-Ass

ocia

ted

Gas

Res

erve

s

Pool

&

Loca

tion

O

rigi

nal

Gas

in

Plac

e (M

Mcf

)

Rec

over

y Fa

cto

r (%

)

Ult

imat

e G

as

Rec

over

y (R

aw

Gas

) (M

Mcf

)

Cum

ulat

ive

Prod

ucti

on

(Raw

Gas

) to

31s

t D

ecem

ber,

20

11

(MM

cf)

Gas

R

eser

ves

(Raw

G

as)

(MM

cf)

Surf

ace

Loss

(%

)

Rem

aini

ng

Gas

Ava

ilabl

e

For

Sale

(MM

cf)

Gas

R

eser

ves

(Sal

es

Gas

) (M

Mcf

)

Com

pany

W

orki

ng

Inte

rest

(%

)

Com

pany

G

ross

G

as

Res

erve

s (M

Mcf

)

Less

or

Roy

alti

es

&

Bur

dens

(%

)

Com

pany

N

et(1

) G

as

Res

erve

s (M

Mcf

)

Net

Pre

sent

Val

ue

Bef

ore

Inco

me

Tax

es

(US$

mill

ion)

@

0%

@5%

@

10%

@

15%

Sinp

huho

rm

Fiel

d,

Tha

iland

75

8,00

0 90

.0

682,

200

157,

839

524,

361

7.0

487,

656

343,

690

12.6

43

,305

0

43,3

05

291

228

184

153

Nat

ural

Gas

Liq

uids

Res

erve

s (V

alue

Incl

uded

wit

h N

on-A

ssoc

iate

d G

as)

Pool

&

Loca

tion

G

as

Res

erve

s (S

ales

G

as)

(MM

cf)

Liqu

id

Rec

over

y

(bbl

/MM

cf)

(Sal

es

Gas

)

Con

dens

ate

Res

erve

s (M

bbl)

Com

pany

W

orki

ng

Inte

rest

(%

)

Com

pany

G

ross

C

onde

nsat

e R

eser

ves

(Mbb

l)

Less

or

Roy

alti

es

&

Bur

dens

(%

)

Com

pany

N

et(1

)

Con

dens

ate

Res

erve

s (M

bbl)

Sinp

huho

rm

Fiel

d,

Tha

iland

34

3,69

0 5.

14

1,76

5 12

.6

222

0 22

2

1 N

et E

ntitl

emen

t: T

haila

nd is

a T

ax a

nd R

oyal

ty r

egim

e. R

oyal

ty is

tre

ated

as

tax

and

is p

aid

in c

ash,

and

thu

s, a

ttri

buta

ble

Net

Ent

itlem

ent

Shar

e is

rep

orte

d as

Coa

stal

’s w

orki

ng in

tere

st

volu

mes

incl

udin

g as

soci

ated

Roy

alty

vol

umes

.

R

ESER

VES

AN

D R

ESO

UR

CES

CER

TIF

ICA

TIO

N

FOR

TH

E SI

NPH

UH

OR

M G

AS

FIEL

D A

S O

F 1st

JAN

UA

RY

, 201

2

EC

V183

7.03

42

Tab

le 5

-5 –

Est

imat

es o

f P

rove

d P

lus

Pro

babl

e R

eser

ves

and

Net

Pre

sent

Val

ues

for

the

Sinp

huho

rm F

ield

(as

of

1st

Janu

ary,

201

2)

Non

-Ass

ocia

ted

Gas

Res

erve

s

Pool

&

Loca

tion

O

rigi

nal

Gas

in

Plac

e (M

Mcf

)

Rec

over

y Fa

cto

r (%

)

Ult

imat

e G

as

Rec

over

y (R

aw

Gas

) (M

Mcf

)

Cum

ulat

ive

Prod

ucti

on

(Raw

Gas

) to

31s

t D

ecem

ber,

20

11

(MM

cf)

Gas

R

eser

ves

(Raw

G

as)

(MM

cf)

Surf

ace

Loss

(%

)

Rem

aini

ng

Gas

Ava

ilabl

e

For

Sale

(MM

cf)

Gas

R

eser

ves

(Sal

es

Gas

) (M

Mcf

)

Com

pany

W

orki

ng

Inte

rest

(%

)

Com

pany

G

ross

G

as

Res

erve

s (M

Mcf

)

Less

or

Roy

alti

es

&

Bur

dens

(%

)

Com

pany

N

et(1

) G

as

Res

erve

s (M

Mcf

)

Net

Pre

sent

Val

ue

Bef

ore

Inco

me

Tax

es

(US$

mill

ion)

@

0%

@5%

@

10%

@

15%

Sinp

huho

rm

Fiel

d,

Tha

iland

1,

909,

600

90.0

1,

718,

640

157,

839

1,56

0,80

1 7.

0 1,

451,

545

956,

616

14.0

13

3,05

5 0

133,

055

1,01

6 55

2 34

3 23

7

Nat

ural

Gas

Liq

uids

Res

erve

s (V

alue

Incl

uded

wit

h N

on-A

ssoc

iate

d G

as)

Pool

&

Loca

tion

G

as

Res

erve

s (S

ales

G

as)

(MM

cf)

Liqu

id

Rec

over

y

(bbl

/MM

cf)

(Sal

es

Gas

)

Con

dens

ate

Res

erve

s (M

bbl)

Com

pany

W

orki

ng

Inte

rest

(%

)

Com

pany

G

ross

C

onde

nsat

e R

eser

ves

(Mbb

l)

Less

or

Roy

alti

es

&

Bur

dens

(%

)

Com

pany

N

et(1

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPUHORM GAS FIELD AS OF 1st JANUARY, 2012

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Table 5-6 – Sinphuhorm Field Remaining Gas Reserves Reconciliation, 100% Basis

Period & Factor Remaining Reserves (MMcf)

Proved Probable Proved + Probable Possible

Proved + Probable + Possible

1st January, 2011 370,477 622,873 993,351 10 993,360

Extensions

Discoveries

Technical Revisions 3,519 -9,947 -6,428 -10 -6,438

Acquisitions

Depositions

Economic Factors

Production -30,306 -30,306 -30,306

1st January, 2012 343,690 612,926 956,616 0 956,616

Table 5-7 – Sinphuhorm Field Remaining Condensate Reserves Reconciliation, 100% Basis

Period & Factor Remaining Reserves (Mbbl)



1st January, 2011 1,945 3,270 5,215 0 5,215

Extensions

Discoveries

Technical Revisions -42 -122 -164 0 -164

Acquisitions

Depositions

Economic Factors


1st January, 2012 1,765 3,148 4,913 0 4,913


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Table 5-8 – Sinphuhorm Field Remaining Gas Reserves Reconciliation, Coastal’s Net Entitlement

Period & Factor Remaining Reserves (MMcf)



1st January, 2011 46,680 91,994 138,674 20,961 159,635

Extensions

Discoveries

Technical Revisions 443 -2,244 -1,801 -1,538 -3,339

Acquisitions

Depositions

Economic Factors

Production -3,819 -3,819 -3,819

1st January, 2012 43,305 89,750 133,055 19,422 152,477

Table 5-9 – Sinphuhorm Field Remaining Condensate Reserves Reconciliation, Coastal’s Net Entitlement

Period & Factor Remaining Reserves (Mbbl)



1st January, 2011 245 483 728 110 838

Extensions

Discoveries

Technical Revisions -5 -22 -27 -10 -38

Acquisitions

Depositions

Economic Factors


1st January, 2012 222 461 683 100 783


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Appendices

APPENDIX I

GLOSSARY OF TECHNICAL TERMS


ECV1837.03 46


ECV1837.03 47

APPENDIX 1 - GLOSSARY OF TECHNICAL TERMS

1C Low Estimate Contingent Resources

2C Best Estimate Contingent Resources

3C High Estimate Contingent Resources

1P Proved Reserves

2P Proved plus Probable Reserves

3P Proved plus Probable plus Possible Reserve

Acre Area in acre

AOF Absolute Open Flow

API American Petroleum Institute

B billion

bbl barrels

bbl/d barrels per day

BBTUD Billions of British Thermal Units per Day

bcpd barrels of condensate per day

BOE barrel of oil equivalent

Bg gas formation volume factor

Bgi gas formation volume factor (initial)

Bo oil formation volume factor

Boi oil formation volume factor (initial)

Bw water volume factor

bcpd barrels of condensate per day

bopd barrels of oil per day

BTU British Thermal Unit

Bscf billions of standard cubic feet

bwpd barrels of water per day

°C Temperature in Centigrade

cc cubic centimetre

CGR condensate gas ratio

cP Viscosity in centiPoise

DCQ daily contracted quantity direct

DST Drill Stem Test

Entitlement Volumes the volumes of oil and/or gas which a Contractor receives under the terms of a PSC

ELT Economics Limit Test

EUR Estimated Ultimate Recovery


ECV1837.03 48


°F Temperature in Fahrenheit

FBHP flowing bottom hole pressure

FTHP flowing tubing head pressure

FTHT flowing tubing head temperature

ft Length in feet

ft3 Volume in cubic feet

ftSS depth in feet below sea level

GEF Gas Expansion Factor

GIP Gas in Place

GIIP Gas Initially in Place

gm Weight in grams

gm/cc Density in grams per cubic centimetre

GOR gas/oil ratio

GRV gross rock volume

GSA Gas Sales Agreement

GWC gas water contact

Ib Weight in pounds

Ib/cuft Density in pounds per cubic feet

KB Kelly Bushing

km Length in kilometres

km2 Area in square kilometres

km3 Volume in cubic kilometres

m Length in meter

MM million

MM$ million US dollars

MD measured depth

mD permeability in millidarcies

MDT Modular Formation Dynamics Tester

m3 cubic metres

m3/d cubic metres per day

MMscf/d millions of standard cubic feet per day

Money of the Day Cash values calculated to include the effect of inflation

NTG net to gross ratio

NPV Net Present Value

OWC oil water contact


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P1 Proved Reserves

P2 Probable Reserves

P3 Possible Reserves

P10 Probability of 10% chance the value would be larger than the reported and considered high value

P50 Probability of 50% chance the value would be larger than the reported and considered best value

P90 Probability of 90% chance the value would be larger than the reported and considered low value

Pb bubble point pressure

Pc capillary pressure

petroleum deposits of oil and/or gas

phi porosity fraction

phie Effective porosity fraction

pi initial reservoir pressure

PRMS Petroleum Resources Management System (SPE Terminology)

PSC Production Sharing Contract

psi pounds per square inch

psia pounds per square inch absolute

psig pounds per square inch gauge

rcf Volume in reservoir cubic feet

Real Cash values calculated to exclude the effects of inflation

scf standard cubic feet measured at 14.7 pounds per square inch and 60°F

scfd standard cubic feet per day

scf/stb standard cubic feet per stock tank barrel

stb stock tank barrels measured at 14.7 pounds per square inch and 60°F

stb/d stock tank barrels per day

stb/MMscf stock tank barrels per million standard cubic feet measured at 14.7 pounds per square inch and 60°F

STOIIP stock tank oil initially in place

Sw water saturation

US$ United States Dollars

TAC Technical Assistance Contract

TAN Total Acid Number (of oil)

Tscf trillion standard cubic feet

TVDSS true vertical depth (sub-sea)


ECV1837.03 50


TVT true vertical thickness

TWT two-way time

US$ United States Dollar

Vsh shale volume

WI Working Interest

WC water cut

WHP Well Head Pressure

porosity


ECV1837.03 51

APPENDIX II

RESERVES AND RESOURCES DEFINITIONS AND GUIDELINES


ECV1837.03 52


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RESERVES AND RESOURCES DEFINITIONS AND GUIDELINES Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), American Association of

Petroleum Geologists (AAPG), Society of Petroleum Evaluation Engineers (SPEE)

Petroleum Resources Management System (PRMS)

Definitions and Guidelines (3)

Preamble

Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework.

International efforts to standardize the definition of petroleum resources and how they are estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American Association of Petroleum Geologists (AAPG), SPE and WPC jointly developed a classification system for all petroleum resources. This was followed by additional supporting documents: supplemental application evaluation guidelines (2001) and a glossary of terms utilized in Resources definitions (2005). SPE also published standards for estimating and auditing Reserves information (revised 2007).

These definitions and the related classification system are now in common use internationally within the petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources estimation. However, the technologies employed in petroleum exploration, development, production and processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with other organizations to maintain the definitions and issues periodic revisions to keep current with evolving technologies and changing commercial opportunities.

The SPE PRMS document consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications, and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”; the latter document remains a valuable source of more detailed background information.

These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that SPE PRMS will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings.

It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements.

3 These Definitions and Guidelines are extracted from the Society of Petroleum Engineers / World Petroleum Council / American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007, and available, free and in full, at: www.spe.org/spe-app/spe/industry/reserves/index.htm


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RESERVES

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 satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

Proved Reserves

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes:

the area delineated by drilling and defined by fluid contacts, if any, and

adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved Reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that the locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.


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It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves

Possible Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

(See above for separate criteria for Probable Reserves and Possible Reserves.)

The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.


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CONTINGENT RESOURCES

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable 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 sub-classified based on project maturity and/or characterized by their economic status.

PROSPECTIVE RESOURCES

Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration.

Prospect- A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.

Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.

Lead- A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.

Play- A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.

Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.


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