RESERVES AND RESOURCES CERTIFICATION FOR THE AS OF

SINPHUHORM GAS FIELD

1ST JANUARY, 2012

Prepared by:

Prepared for:

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

Coastal Energy Company

Report No: Version/Date:

ECV1837.03 Rev0 / 29th March, 2012

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

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 29 th 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.

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

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

Table 1 Summary Statement of Coastal’s Reserves for the Sinphuhorm Gas Field as of 1st January, 2012 Remaining Product Classification

Ultimate Reserves

Net Present Values (US$ Million)

Reserves Company

After Income Taxes

Before Income Taxes

Gross

Net

0%

5%

10% 15% 20%

0%

5%

261,589

32,960

208

166

136

143

115

10% 15% 20%

Non-Associated Gas (MMcf) Proved Developed Producing

419,428

115

99

95

80

69 15

Proved Developed Non-Producing Proven Undeveloped

82,101

82,101

10,345

66

49

37

29

23

43

32

24

19

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

1,114,455 956,616 133,055

953

517

321

222

167

630

345

216

151

114

13

10

9

7

6

9

7

6

5

4

Total Proved + Probable Natural Gas Liquid (Mbbl) Proved Developed Producing

2,143

1,344

169

Proved Developed Non-Producing 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

72,048

44,942

5,663

221

176

145

122

105

152

122

101

85

74

Proven Undeveloped

14,105

14,105

1,777

70

52

39

30

24

46

34

26

20

16

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

Grand Total (MBOE)(1) Proved Developed Producing Proved Developed Non-Producing

Notes: (1) Using 6.0 Mscf/BOE

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.

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

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

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) Oil and Condensate (Mbbl)

137,922

593,874

4,504,520

70%

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%

89

485

3,968

70%

Oil and Condensate (Mbbl)

Coastal Net Entitlement Interest Basis

4)

Net Entitlement Interest

12.6%

14.0%

16.2%

Gas (MMscf)

17,378

83,142

729,732

70%

89

485

3,968

70%

Oil and Condensate (Mbbl) Notes: 1)

2) 3) 4)

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

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

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

Table of Contents RESERVES AND RESOURCES CERTIFICATION 1 

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

2 

Concessions EU1, E5N and L15/43 ............................................................................................5  2.1  2.2  2.3  2.4  2.5  2.6 

Overview ....................................................................................................................................................... 5  Petroleum System ........................................................................................................................................ 5  Database ........................................................................................................................................................ 6  Sinphuhorm Structure ................................................................................................................................. 6  Petrophysics .................................................................................................................................................. 7  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  3.2  3.3 

Thai Concession Terms ............................................................................................................................ 27  Capital and Operating Costs .................................................................................................................... 27  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

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

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

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

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

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

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 RPS has previously reviewed the Resources for this Asset for Coastal, Salamander and APICO in the reports:

ECV1837.03



“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).

2

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

North Phu Horm

L15/43 EU1

Sinphuhor m EU1

Sinphuhorm

E5N L15/43 E5N

L27/43

Nam Phong

Scale (km)

0

25

Map supplied by APICO

Sinphuhorm Gas Field (Concessions EU1, E5N) Current Coastal Concession L15/43 outline Original Coastal Concession L15/43 outline Current Coastal Concession L27/42 outline

Figure 1-1 – Location of Coastal’s Onshore Thailand Concessions ECV1837.03

rpsgroup.com

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

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

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*

-

35.0 (12.635)

100.0* (36.1)

PTT E&P

20.0

-

ExxonMobil

10.0

-

APICO LLC (of which Coastal)

*) 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 6001,000 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:  

ECV1837.03

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

5

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

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

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

2.6.2

Indosinian-1 Unconformity Truncation An additional GRV uncertainty relates to placement of the intersection of the thrusted southeasterly 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

7.53

17.05

54.91

57

92

165

-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

2

Gross Rock Volume (km .m) 2

Area (km ) Gas-water Contact (m TVDSS)

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

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.

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

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



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

17 June, 2011

3,168

South

Gradient Survey

PH-4

18th September, 2011

2,878

Central

Gradient Survey

th

th

PH-5

25 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.

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 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 109 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)

2.12

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

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

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

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

2

4

4

Total Wells

“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.

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

“Connected” GIIP, Bscf (Table 2-6) “Unconnected” GIIP, Bscf (Table 2-6)

1)

TOTAL GIIP, Bscf Overall Recovery Factor, % (back interpolated) Total Wellhead Gas EUR, Bscf Total Sales Gas EUR, Bscf Note 1) 2) 3)

2.12.3

3)

2)

Low Estimate

Best Estimate

High Estimate

714

824

957

0

2,586

5,876

714

3,410

6,833

90%

50%

83%

643

1,719

5,657

638

1,707

5,618

: No development of the “Unconnected” volumes for the Low Estimate. Best and High Estimates assume full production to 2050 (effective ultimate EUR). After applying shrinkage of 0.7% due to fuel and flare.

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.

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

Period

DCQ (MMscf/d)

DCQ Reduction Nam Phong 1 (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

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

1/10/2021 – 28/11/2021

108

0

108.0

Contract Year

6

16

3

4

Sinphuhorm (MMscf/d)

2

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.

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 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 Total “Unconnected” GIIP, Bscf

929

2,586

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

G

5,876

From "Mapped" minus "Connected" volumes

Gas Production & Remaining Resources Total EUR Sales Gas, Bscf

1)

638

1,707

5,618

M

Sales Gas Sold, Bscf

-157

-157

-157

N

Remaining EUR Sales Gas, Bscf

481

1,550

5,461

L

F+K Historical sales gas production L-N

Contracted and Uncontracted Gas P

Contracted Sales Gas, Bscf

Q

“Lost” Gas, Bscf

R

Sales Gas Volumes, Bscf

1)

S

Uncontracted Gas Resource, Bscf

2)

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352

964

964

-8

-8

-8

344

956

956

138

594

4,505

DCQ (including GSA extension/downtime) Inability to meet the contracted DCQ Sales Gas Profiles at end of GSA/extensions N-R : Uncontracted Gas Resources

17

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

Sinphuhorm - Hydrocarbon Resource Base Low Estimate

Best Estimate

High Estimate

Remarks

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

0.7

3.5

24.5

From production profiles

W

Uncontracted Condensate Resource, MMbbl

2)

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

High Estimate

1)

138

594

4,505

(Table 2-10)

Uncontracted Condensate (MMbbl)

0.7

3.5

24.5

(Table 2-10)

Uncontracted Sales Gas (Bscf)

Remarks

Note: 1)

ECV1837.03

After applying 0.7% shrinkage for fuel and flare.

18

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

L15/43

Scale (km)

0

25

N th Phu North Ph Horm H

Sinphuhorm

L27/43 Nam Phong

Map supplied by APICO

Sinphuhorm Gas Field (Concessions EU1, E5N) Current Coastal Exploration Concessions Original Coastal Concessions L15/43 and L27/43

Figure 2-1 – Location of the Sinphuhorm Gas Field and Concession L15/43 ECV1837.03

L27/43

rpsgroup.com

RESERVES AND RESOURCES CERTIFICATION

Dolomite

Karsted Ls.

FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

Figure 2-2 – Onshore Thailand Stratigraphic Column ECV1837.03

rpsgroup.com

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

PH-1

PH-2

PH-6 PH-4 PH-10 PH-7

PH-5 PH-3

SPH-1

5 km

Estimated Gas-Water Contact

Western Limit of Indosinian-1 Indosinian 1 Unconformity Truncation

Low: 2,156 mTVDSS

Best

Best: 2,279 mTVDSS

Maximum

High: 2,587 mTVDSS

Approximate “tank” areas

Figure 2-3 – Sinphuhorm Gas Field Top Structure Map (RPS) ECV1837.03

rpsgroup.com

RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 Sinphuhorm (Central Area) - Reservoir Pressure PH-10ST

PH-4

4000

Re eservoir Pressure (psia)

3800 3600 3400 3200 3000 2800 2600 2400 2200 2000 Jan-04

May-05

Oct-06

Feb-08

Jul-09

Nov-10

Apr-12

Date

Sinphuhorm (South Area) - Reservoir Pressure PH-5 PH 5

PH-3 PH 3

4000

Reservoirr Pressure (psia)

3800 3600 3400 3200 3000 2800 2600 2400 2200 2000 Sep-02

Jan-04

May-05

Oct-06

Feb-08

Jul-09

Nov-10

Apr-12

Date Sinphuhorm - Average Reservoir Pressure Central Area

South Area

3900

Reservoir Pressure e (psia)

3700

3500

3300

3100

2900

2700

2500 May 05 May-05

Oct 06 Oct-06

Feb 08 Feb-08

Jul 09 Jul-09

Nov 10 Nov-10

Apr 12 Apr-12

Date

Figure 2-4 – Sinphuhorm Gas Field Reservoir Pressure ECV1837.03

rpsgroup.com

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

Figure 2-5 – Sinphuhorm Gas Field Production History ECV1837.03

rpsgroup.com

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

Central Area ‐ Gas Rate & FWHP PH‐10ST Gas Rate

PH‐4 Gas Rate

PH‐10ST FWHP

PH‐4 FWHP

120.00 3000.0

100.00

2500.0

2000.0

60.00

1500.0

40.00

1000.0

20.00

500 0 500.0

0.00 29‐Nov‐06

FWHP (pssig)

Gas Rate (MM Mscf/d)

80.00

0.0 25‐Sep‐07

21‐Jul‐08

17‐May‐09

13‐Mar‐10

07‐Jan‐11

03‐Nov‐11

Date

South Area ‐ Gas Rate & FWHP PH‐5 Gas Rate

PH‐3 Gas Rate

PH‐5 FWHP

PH‐3 FWHP

100.00 3000.0 90.00 2500.0

80.00 70.00

50.00

1500.0

40.00

FWHP (psig)

Gas Rate (MMscf/d)

2000.0 60.00

1000 0 1000.0

30.00 20.00

500.0 10.00 0.00 29‐Nov‐06

0.0 25‐Sep‐07

21‐Jul‐08

17‐May‐09

13‐Mar‐10

07‐Jan‐11

03‐Nov‐11

Date

Figure 2-6 – Sinphuhorm Gas Field FWHPs ECV1837.03

rpsgroup.com

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

Central Area Central Area

Low Est.

Best Est.

300

400

High Est.

4500 4000 3500

P/Z (ps sia)

3000 2500 2000 1500 1000 500 444.5

0 0

100

200

500

600

700

Cumulative Gas (Bscf)

South Area South Area

Low Est.

Best Est.

High Est.

4500 4000 3500

P/Z (psia)

3000 2500 2000 1500 1000 500 379.5

0 0

50

100

150

200

250

300

350

400

450

Cumulative Gas ((Bscf))

Figure 2.7 – Sinphuhorm Gas Field P/Z GIIP Estimates (RPS) ECV1837.03

rpsgroup.com

500

RESERVES AND RESOURCES CERTIFICATION

From m Operator’s Technical Committee Mee eting (14th October. 2011)

FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

Figure 2.8 – Sinphuhorm Gas Field P/Z GIIP Estimate (Operator) ECV1837.03

rpsgroup.com

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

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 Tax

12.5% 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

ECV1837.03

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

27

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

Year

1P CAPEX

2P OPEX

CAPEX

3P 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

28

RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 Table 3-3 – Estimated Unitised Share for the Sinphuhorm Gas Field

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%

Reserves Case:

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

29

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

ECV1837.03

30

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

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

Sinphuhorm Sales Gas (Bscf) Sinphuhorm Condensate (MMbbl) Total (MMBOE)(1)

Proved

Proved plus Probable

Proved plus Probable plus Possible

344

957

957

1.8

4.9

4.9

59.0

164.3

164.3

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

1)

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

Proved plus Probable plus Possible

12.6%

14.0%

16.2%

Sinphuhorm Sales Gas (Bscf)

43

133

152

Sinphuhorm Condensate (MMbbl)

0.2

0.7

0.8

7.4

22.9

26.2

Working Interest (%)(1)

Total

(MMBOE)(2)

Notes: 1) 2)

ECV1837.03

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

31

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

1st January, 2011(1)

Proved plus Probable (Bscf)

Proved plus Probable plus Possible (Bscf)

370

993

993

4

-6

-6

Production

-30

-30

-30

1st

344

957

957

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors January, 2012

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)

1st January, 2011(1)

Proved plus Probable (MMbbl)

Proved plus Probable plus Possible (MMbbl)

1.9

5.2

5.2

0

-0.2

-0.2

Production

-0.1

-0.1

-0.1

1st January, 2012

1.8

4.9

4.9

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors

Note: 1)

ECV1837.03

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).

32

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

1st January, 2011(1)

Proved plus Probable (Bscf)

Proved plus Probable plus Possible (Bscf)

47

139

160

0

-2

-3

Production

-4

-4

-4

1st

43

133

152

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors January, 2012

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

1st January, 2011(1)

Proved plus Probable (MMbbl)

Proved plus Probable plus Possible (MMbbl)

0.2

0.7

0.8

0

0

0

Production

-0.0

-0.0

-0.0

1st January, 2012

0.2

0.7

0.8

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors

Note: 1)

ECV1837.03

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).

33

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

ECV1837.03

34

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

CASE PARAMETERS

COMPANY INTERESTS

Client

Coastal Energy gy

1P

12.6 %

Region

South East Asia

2P

14.0 %

Country

Thailand

3P

16.2 %

Field

Sinphuhorm Licence

Phase

Gas FORECAST FUTURE GROSS FIELD PRODUCTION (100% BASIS) Production

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 33

1

2012

346/366

92

32

32

91

33

33

91

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

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

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

344

957

957

Remaining Total 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 ECV1837.03

rpsgroup.com

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

CASE PARAMETERS

COMPANY INTERESTS

Client

Coastal Energy gy

1P

12.6 %

Region

South East Asia

2P

14.0 %

Country

Thailand

3P

16.2 %

Field

Sinphuhorm Licence

Phase

Condensate FORECAST FUTURE GROSS FIELD PRODUCTION (100% BASIS) Production

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

02 0.2

09 0.9

524

02 0.2

09 0.9

524

02 0.2

09 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

02 0.2

23 2.3

555

02 0.2

23 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

1.8

4.9

4.9

Remaining Total 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 ECV1837.03

rpsgroup.com

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

Sinphuhorm Sales Gas Profiles 120

MMscf/d

100 80 60 40 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

0

1P

2P

3P

Figure 4.3 – Sinphuhorm Gas Field Gas Production Forecast ECV1837.03

rpsgroup.com

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

Sinphuhorm Condensate Production Profiles 600 500

stb/d

400 300 200 100

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

0

1P

2P

3P

Figure 4.4 – Sinphuhorm Gas Field Condensate Production Forecast ECV1837.03

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

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 Remaining Product Classification

Ultimate Reserves

Net Present Values (US$ Million)

Reserves Company

Before Income Taxes

After Income Taxes

Gross

Net

0%

5%

10% 15% 20%

0%

5%

261,589

32,960

208

166

136

143

115

10% 15% 20%

Non-Associated Gas (MMcf) Proved Developed Producing

419,428

115

99

95

80

69 15

Proved Developed Non-Producing Proven Undeveloped

82,101

82,101

10,345

66

49

37

29

23

43

32

24

19

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

1,114,455 956,616 133,055

953

517

321

222

167

630

345

216

151

114

13

10

9

7

6

9

7

6

5

4

Total Proved + Probable Natural Gas Liquid (Mbbl) Proved Developed Producing

2,143

1,344

169

Proved Developed Non-Producing 422

422

53

4

3

2

2

1

3

2

2

1

1

Total Proved

Proven Undeveloped

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

72,048

44,942

5,663

221

176

145

122

105

152

122

101

85

74

Proven Undeveloped

14,105

14,105

1,777

70

52

39

30

24

46

34

26

20

16

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

Grand Total (MBOE)(1) Proved Developed Producing Proved Developed Non-Producing

Notes: (1) Using 6.0 Mscf/BOE

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012 Table 5-2 – Total Future Net Revenue Undiscounted Forecast Prices and Costs as of 1st January, 2012

Revenue

Royalties

Reserves Category

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 Proved plus Probable Reserves Proved plus Probable Reserves plus Possible Reserves

372

46

21

13

0

291

93

198

1,264

158

68

22

0

1,016

345

671

1,449

181

78

23

0

1,167

397

770

Table 5-3 – Sinphuhorm Field Volumetric Reserves Estimates Reservoir Data Monte Carlo Parameter Inputs

ECV1837.03

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

40

758,000

Original Gas in Place (MMcf)

90.0

Recovery Factor (%)

682,200

Ultimate Gas Recovery (Raw Gas) (MMcf)

157,839

Cumulative Production (Raw Gas) to 31st December, 2011 (MMcf)

524,361

Gas Reserves (Raw Gas) (MMcf)

7.0

5.14

(Sales Gas)

Liquid Recovery (bbl/MMcf)

1,765

Condensate Reserves (Mbbl)

12.6

Company Working Interest (%)

222

(Mbbl)

Company Gross Condensate Reserves

0

222

Company Net(1) Condensate Reserves (Mbbl)

343,690

Gas Reserves (Sales Gas) (MMcf)

12.6

Company Working Interest (%)

43,305

Company Gross Gas Reserves (MMcf)

0

Lessor Royalties & Burdens (%)

43,305

Company Net(1) Gas Reserves (MMcf)

291

@0%

228

@5%

184

@10%

(US$ million)

41

153

@15%

Before Income Taxes

Net Present Value

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

343,690

Gas Reserves (Sales Gas) (MMcf)

ECV1837.03

1

Sinphuhorm Field, Thailand

Pool & Location

487,656

(MMcf)

For Sale

Available

Gas

Remaining

Lessor Royalties & Burdens (%)

Surface Loss (%)

Natural Gas Liquids Reserves (Value Included with Non-Associated Gas)

Sinphuhorm Field, Thailand

Pool & Location

Non-Associated Gas Reserves

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

FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

RESERVES AND RESOURCES CERTIFICATION

1,909,600

Original Gas in Place (MMcf)

90.0

Recovery Factor (%)

1,718,640

Ultimate Gas Recovery (Raw Gas) (MMcf)

157,839

Cumulative Production (Raw Gas) to 31st December, 2011 (MMcf)

1,560,801

Gas Reserves (Raw Gas) (MMcf)

5.14

(Sales Gas)

Liquid Recovery (bbl/MMcf)

4,913

Condensate Reserves (Mbbl)

13.9

Company Working Interest (%)

683

(Mbbl)

Company Gross Condensate Reserves

0

Lessor Royalties & Burdens (%)

956,616

Gas Reserves (Sales Gas) (MMcf)

683

Company Net(1) Condensate Reserves (Mbbl)

1,451,545

(MMcf)

For Sale

Available

Gas

Remaining

14.0

Company Working Interest (%)

133,055

Company Gross Gas Reserves (MMcf)

0

Lessor Royalties & Burdens (%)

133,055

Company Net(1) Gas Reserves (MMcf)

1,016

@0%

552

@5%

343

@10%

(US$ million)

42

237

@15%

Before Income Taxes

Net Present Value

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

956,616

Gas Reserves (Sales Gas) (MMcf)

ECV1837.03

1

Sinphuhorm Field Thailand

Pool & Location

7.0

Surface Loss (%)

Natural Gas Liquids Reserves (Value Included with Non-Associated Gas)

Sinphuhorm Field, Thailand

Pool & Location

Non-Associated Gas Reserves

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

FOR THE SINPHUHORM GAS FIELD AS OF 1st JANUARY, 2012

RESERVES AND RESOURCES CERTIFICATION

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

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

1st

January, 2011

Remaining Reserves (MMcf)

Possible

Proved + Probable + Possible

Proved

Probable

Proved + Probable

370,477

622,873

993,351

10

993,360

3,519

-9,947

-6,428

-10

-6,438

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors Production

-30,306

1st January, 2012

343,690

-30,306 612,926

956,616

-30,306 0

956,616

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

1st

January, 2011

Remaining Reserves (Mbbl)

Possible

Proved + Probable + Possible

Proved

Probable

Proved + Probable

1,945

3,270

5,215

0

5,215

-42

-122

-164

0

-164

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors

ECV1837.03

Production

-138

1st January, 2012

1,765

-138 3,148

4,913

-138 0

4,913

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

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

1st January, 2011

Remaining Reserves (MMcf)

Possible

Proved + Probable + Possible

Proved

Probable

Proved + Probable

46,680

91,994

138,674

20,961

159,635

443

-2,244

-1,801

-1,538

-3,339

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors Production

-3,819

1st

43,305

January, 2012

-3,819 89,750

133,055

-3,819 19,422

152,477

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

1st January, 2011

Remaining Reserves (Mbbl)

Possible

Proved + Probable + Possible

Proved

Probable

Proved + Probable

245

483

728

110

838

-5

-22

-27

-10

-38

Extensions Discoveries Technical Revisions Acquisitions Depositions Economic Factors

ECV1837.03

Production

-17

1st January, 2012

222

-17 461

683

-17 100

783

44

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

Appendices

APPENDIX I GLOSSARY OF TECHNICAL TERMS

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

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

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPUHORM GAS FIELD AS OF 1st JANUARY, 2012 APPENDIX 1 - GLOSSARY OF TECHNICAL TERMS °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 km

3

Area in square kilometres 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

3

m /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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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPUHORM GAS FIELD AS OF 1st JANUARY, 2012 APPENDIX 1 - GLOSSARY OF TECHNICAL TERMS 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)

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RESERVES AND RESOURCES CERTIFICATION FOR THE SINPUHORM GAS FIELD AS OF 1st JANUARY, 2012 APPENDIX 1 - GLOSSARY OF TECHNICAL TERMS 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

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

APPENDIX II RESERVES AND RESOURCES DEFINITIONS AND GUIDELINES

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

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

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

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

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

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