COASTAL ENERGY COMPANY

Transcription

1 COASTAL ENERGY COMPANY Thailand Property Evaluation As of December 31, 2007 Huddleston & Co., Inc. Petroleum and Geological Engineers Houston, Texas

2 TABLE OF CONTENTS Letter of Transmittal Report Preparation Review of Assets Geologic Descriptions Onshore Summary Offshore Summary Reserve and Resource Estimates Reserve Estimates Phu Horm Field Bua Ban Field Songkhla Field Contingent and Prospective Resources Contingent Resources Prospective Resources Economic Analysis Constant and Forecast s Operating Expenses Capital Expenditures Income Tax Considerations Report Qualifications Figures Tables Appendices

3 List of Figures 1 Map of Thailand Onshore and Offshore License Areas 2 Map of Thailand Onshore License Areas and Fields 3 Map of Thailand Offshore License Areas and Fields 4 Seismic Cross Section of Phu Horm Field Area 5 Schematic Cross Section of Songkhla Basin Area 6 Phu Horm Field Monthly (11/06 12/07) 7 Map of Offshore Prospective WFT Prospects 8 Map of Offshore Prospective Songkhla Prospects 9 Graphical Summaries of Estimated Future Offshore Properties 10 Graphical Summaries of Estimated Future Onshore Properties

4 List of Tables 1 Assets to Coastal Energy 1.1 Offshore Property Evaluation 1.2 Onshore Property Evaluation 1.3 Combined Property Evaluation 2 Summary of Coastal Energy Licenses and Working Interests Thailand 3 Summary of Reserves Offshore, Onshore, and Combined 4 Contract Summary and Phu Horm Field Volumes 5 Phu Horm Field Monthly and Condensate (11/06 12/07) 6 Summary of Volumetric Parameters for Formations 7 Summary of Volumetric Parameters for Formations 8 Summary of Reserve Assignments Offshore Block G5/43 Bua Ban Field 9 Summary of Reserve Assignments Offshore Block G5/43 Songkhla Field 10 Summary of Contingent Resources Offshore, Onshore, and Combined 11 Assignment of Contingent Resources for Onshore Blocks EU1/E5N Phu Horm Field Pha Nok Khao Formation Volumes Only 12 Summary of Prospective Resources Offshore, Onshore, and Combined 13 Summary of Assumptions 14 Forecast Case, Crude and Condensate Calculations 15 Summary of Lease Operating Expenses Constant Pricing Case Interests Combined Offshore and Onshore Properties 16 Summary of Lease Operating Expenses Constant Pricing Case to Coastal Energy Combined Offshore and Onshore Properties 17 Summary of Capital Expenditures Constant Pricing Case Interests Combined Offshore and Onshore Properties

5 List of Tables Page Two 18 Summary of Capital Expenditures by Field Constant Case Interests Offshore, Onshore, and Combined 19 Summary of Capital Expenditures by Field Constant Pricing Case to Coastal Energy Offshore, Onshore, and Combined 20 Comparison of Before and After Income Tax s Constant Pricing Case Offshore, Onshore, and Combined 21 Comparison of Before and After Income Tax s Forecast Pricing Case Offshore, Onshore, and Combined

6 List of Appendices A Glossary of Technical Terms B Conversion Factors and Abbreviations C Certificates of Qualification D Canadian Form F2 E Definitions of Reserves and Resources Petroleum Resources Classification System and Definitions, Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum Geologists (AAPG), February 2000 Petroleum Reserves Definitions, SPE, WPC, March 1997 Reserve Definitions, Canadian Securities Administrators National Instrument F Detailed Projections Constant Case to Coastal Energy Offshore Property Evaluation (Proved + Probable + Possible) Table 1.1 Data G Detailed Projections Constant Case to Coastal Energy Onshore Property Evaluation (Proved + Probable + Possible) Table 1.2 Data H Detailed Projections Constant Case to Coastal Energy Combined Property Evaluation (Proved + Probable + Possible) Table 1.3 Data I Detailed Projections Forecast Case to Coastal Energy Offshore Property Evaluation (Proved + Probable + Possible) Table 1.1 Data J Detailed Projections Forecast Case to Coastal Energy Onshore Property Evaluation (Proved + Probable + Possible) Table 1.2 Data K Detailed Projections Forecast Case to Coastal Energy Combined Property Evaluation (Proved + Probable + Possible) Table 1.3 Data

7 Huddleston & Co., Inc. Petroleum and Geological Engineers 1 Houston Center 1221 McKinney, Suite 3700 Houston, Texas PHONE (713) FAX (713) April 21, 2008 Coastal Energy Company Board of Directors Attention: Mr. Randy L. Bartley, CEO Walker House, 87 Mary Street PO Box 908GT George Town, Grand Caymans KY Cayman Islands Gentlemen: Re: Coastal Energy Company Thailand Property Evaluation As of December 31, 2007 Pursuant to your request, we have evaluated certain oil, gas, and condensate interests owned by the Coastal Energy Company and its subsidiaries ( Coastal Energy ) both onshore and offshore Thailand. The reserves and resources shown herein have been prepared with consideration for our understanding of National Instrument ( NI ) (Disclosure of and Activities) guidelines for Canadian Securities Administrators for the TSX Venture Exchange ( TSX ) in Canada and provisions as a Competent Person s Report for the Alternative Market ( AIM ) of the London Stock Exchange. Our conclusions, as of December 31, 2007, follow: Table 1.1 to Coastal Energy Offshore Property Evaluation* Proved Developed Proved Probable Proved + Proved + Probable Constant Case (Appendix F) Producing Undeveloped Proved Undeveloped Probable Possible + Possible Estimated Future /Cond., Mbbl 0 7,563 7,563 16,136 23,699 7,137 30,836 Estimated Future, MMcf Future (FNR), M$ 0 390, ,666 1,371,069 1,761, ,515 2,316,249 FNR Discounted at 5%, M$ 0 331, ,730 1,124,847 1,456, ,116 1,879,693 FNR Discounted at 10%, M$ 0 281, , ,294 1,212, ,236 1,540,969 FNR Discounted at 15%, M$ 0 238, , ,853 1,016, ,485 1,274,760 FNR Discounted at 20%, M$ 0 201, , , , ,343 1,062,974 Forecast Case (Appendix I) Future (FNR), M$ 0 295, ,903 1,146,371 1,442, ,511 1,899,786 FNR Discounted at 5%, M$ 0 249, , ,628 1,199, ,728 1,554,136 FNR Discounted at 10%, M$ 0 210, , ,519 1,002, ,598 1,281,443 FNR Discounted at 15%, M$ 0 176, , , , ,493 1,064,424 FNR Discounted at 20%, M$ 0 147, , , , , ,097 Projected Future s by - Constant Case, M$ (70,793) (70,793) 15,726 (55,066) 0 (55,066) ,806 93, , ,238 35, , , , , ,325 43, ,821 Subtotal 0 220, , , ,497 78, ,355 Thereafter 0 170, , ,766 1,054, ,657 1,529, , ,666 1,371,069 1,761, ,515 2,316,249 *Numbers subject to rounding.

8 Coastal Energy Company Board of Directors April 21, 2008 Page Two Table 1.2 tocoastal Energy Onshore Property Evaluation* Proved Developed Proved Probable Proved + Proved + Probable Constant Case (Appendix G) Producing Undeveloped Proved Undeveloped Probable Possible + Possible Estimated Future /Cond., Mbbl Estimated Future, MMcf 49, , , , , ,574.3 Future (FNR), M$ 290,067 19, , , , ,183 FNR Discounted at 5%, M$ 207,402 10, ,968 96, , ,500 FNR Discounted at 10%, M$ 154,347 5, ,728 38, , ,450 FNR Discounted at 15%, M$ 119,227 2, ,609 15, , ,506 FNR Discounted at 20%, M$ 95, ,877 6, , ,548 Forecast Case (Appendix J) Future (FNR), M$ 282,667 17, , , , ,761 FNR Discounted at 5%, M$ 204,683 8, , , , ,690 FNR Discounted at 10%, M$ 154,427 4, ,710 41, , ,119 FNR Discounted at 15%, M$ 120,973 1, ,595 16, , ,466 FNR Discounted at 20%, M$ 97, ,064 7, , ,092 Projected Future s by - Constant Case, M$ ,514 (1,512) 18, , , , , , , ,236 (3,314) 16, , ,922 Subtotal 57,245 (4,348) 52, , ,897 Thereafter 232,822 23, , , , , ,067 19, , , , ,183 Table 1.3 to Coastal Energy Combined Property Evaluation* Proved Developed Proved Probable Proved + Proved + Probable Constant Case (Appendix H) Producing Undeveloped Proved Undeveloped Probable Possible + Possible Estimated Future /Cond., Mbbl 271 7,589 7,861 16,361 24,222 7,137 31,359 Estimated Future, MMcf 49, , , , , ,574.3 Future (FNR), M$ 290, , ,314 1,617,603 2,317, ,515 2,872,432 FNR Discounted at 5%, M$ 207, , ,699 1,221,378 1,771, ,116 2,194,193 FNR Discounted at 10%, M$ 154, , , ,016 1,411, ,236 1,739,419 FNR Discounted at 15%, M$ 119, , , ,750 1,153, ,485 1,412,266 FNR Discounted at 20%, M$ 95, , , , , ,343 1,165,521 Forecast Case (Appendix K) Future (FNR), M$ 282, , ,709 1,414,327 2,010, ,511 2,467,547 FNR Discounted at 5%, M$ 204, , ,409 1,053,689 1,517, ,728 1,871,826 FNR Discounted at 10%, M$ 154, , , ,929 1,202, ,598 1,481,562 FNR Discounted at 15%, M$ 120, , , , , ,493 1,203,890 FNR Discounted at 20%, M$ 97, , , , , , ,189 Projected Future s by - Constant Case, M$ ,514 (72,305) (52,791) 15,726 (37,065) 0 (37,065) ,495 94, , , ,211 35, , , , , , ,247 43, ,743 Subtotal 57, , , , ,393 78, ,252 Thereafter 232, , ,224 1,130,300 1,557, ,657 2,033, , , ,314 1,617,603 2,317, ,515 2,872,432 Huddleston & Co., Inc.

9 Coastal Energy Company Board of Directors April 21, 2008 Page Three Report Preparation The projected reserves and revenues shown herein have been prepared in accordance with our understanding of the requirements of NI and the Canadian and Evaluation Handbook, Volume 1 Reserves Definitions and Evaluation Practices and Procedures and are intended for Canadian securities filing purposes. Canadian regulations and guidelines provide for estimates of unrisked Proved and Probable reserves and associated revenues discounted at 5%, 10%, 15%, and 20%, based on constant prices and costs. Disclosures utilizing forecasted pricing assumptions may also be reported as additional disclosures under TSX guidelines. The projected reserves and revenues shown herein have also been prepared in accordance with our understanding of the requirements for a Competent Person Report for the AIM market of the London Stock Exchange. The AIM regulations and guidelines provide for estimates of unrisked Proved, Probable, and Possible reserves and associated revenues discounted at 10%, based on constant prices and costs. Disclosures utilizing forecasted pricing assumptions may also be reported as additional disclosures under AIM guidelines. AIM guidelines also allow for the inclusion of Contingent and Prospective Resource estimates. At the request of Coastal Energy, the reserve volumes and revenues in this report has been divided into two (2) categories. The segregation of the onshore Thailand gas properties is in compliance with Canadian regulations surrounding the accounting treatment of Coastal Energy s net ownership interest in these properties. Tables and cash flows have also been prepared that combine the reserve volumes and revenues of the two separate entities. As shown in Tables 1.1, 1.2, and 1.3 and for the purposes of TSX admission, the Coastal Energy reserves have been presented in Proved ( 1P ) and Proved + Probable ( 2P ) formats using both constant and forecast economic assumptions. For the purposes of AIM admission, the Coastal Energy reserves have been presented in Proved + Probable + Possible ( 3P ) formats, again using both constant and forecast economic assumptions. Detailed cash flow projections can be found in Appendices F through K. Furthermore, for AIM admission purposes, both Contingent and Prospective resource volumes have been been prepared. Also, after income tax cases have been prepared. Economic projections were not prepared for the Contingent and Prospective resources; only their associated oil and gas volumes are presented. Various tables and appendices presented herein have been prepared both separately and with combined reserve and resource categories to properly satisfy the individual exchange guidelines. The Society of Petroleum Engineers ( SPE ) requires reserves to be economically recoverable with prices and costs being received on the effective date of the report. In addition, the SPE has promulgated Standards Pertaining to the Estimating and Auditing of and Reserve Information that specifies requirements for the qualifications and independence of reserve estimators and auditors and accepted methods for the estimation of future reserves. Reserve definitions from March 1997 from the SPE and the World Petroleum Congress ( WPC ) and Reserve Definitions, reserve and resource definitions from the February 2000 SPE/WPC/American Association of Petroleum Geologists ( AAPG ) Petroleum Resources Classification System and Definitions, and reserve definitions from the Canadian Securities Administration NI are included in Appendix E. The estimated reserves and resources shown herein have been prepared with consideration for SPE, WPC, and AAPG reserve classification definitions which comply with reserve and resource definitions as adopted by the Canadian Institute of Mining, Metallurgy & Petroleum ( CIM ) (Petroleum Society). All cash flow data in this report has been expressed in United States ( US ) dollars. Huddleston & Co., Inc.

10 Coastal Energy Company Board of Directors April 21, 2008 Page Four Review of Assets A summary of Coastal Energy s licenses and working interests in their Thailand assets appears in Table 2. The reserve and resource assets are located in both onshore and offshore licensed areas. The primary onshore reserve asset is the currently producing Phu Horm Field which is located approximately 290 miles northeast of Bangkok (Figure 1). The gas field is located primarily in Blocks EN5 and EU1 (Figure 2) and is operated by Amerada Hess ( Hess ). The 2006 International Petroleum Encyclopedia states that the Phu Horm Field was becoming Thailand s largest onshore gas field. The structure covers approximately 89 square miles in the Udon Thani and Khon Kaen provinces. Small portions of several Phu Horm subsurface formations extend onto the L15/43 license area, which is operated by APICO LLC ( APICO ). Coastal Energy owns 36.1% of APICO and is the largest shareholder in the company. Contingent and Prospective resources in several of the onshore license areas, Blocks EU1/E5N, L15/43, and L27/43 have also been evaluated in this report. Onshore license areas L15/43, L27/43, and L13/48 are also operated by APICO and are in the exploration phase of development. The Coastal Energy offshore assets are located in Block G5/43 in the Songkhla Basin in the southern Gulf of Thailand (Figure 1). Coastal Energy operates and owns a 100% working interest position in the offshore Block G5/43 assets. Two reserve discoveries, the Bua Ban Field and the Songkhla Field, are currently under development in Block G5/43 by Coastal Energy (Figure 3). The Songkhla Field is located approximately 15 miles offshore in about 78 feet of water and is scheduled for initial production in late The Bua Ban Field is located approximately 7.5 miles offshore in about 60 feet of water and is scheduled for initial production in mid Several other prospects containing Contingent and Prospective resources in Block G5/43 in the Gulf of Thailand have also been evaluated in this report. Offshore license area G5/50 is also operated by Coastal Energy and is in the exploration phase of development. Geologic Description Onshore Summary: The Phu Horm Field lies in the Khorat Plateau area of Thailand and underlies a large north-south trending surface anticline that had been formed by folding and faulting during the Late Cretaceous period. Tertiary through Cretaceous rocks have been eroded from the crest of the structure, leaving a Jurassic through Triassic sequence of non-marine sandstones, siltstones, and claystones. This sequence exceeds 7,800 feet in thickness and overlies the Permian Pha Nok Khao formation. A schematic of the stratigraphic sequence at the Phu Horm Field is attached as Figure 4. The Permian Pha Nok Khao formation is a wedge-shaped, platform carbonate that dips towards the east, and consists of mudstone, wackestone, and packstone. A dolomitized 377 to 790 feet thick interval has been encountered in the PH-1, PH-2, and PH-5 wells. The dolomite was not reached in either the PH-3 or the PH-4. Hess drilled three additional wells in the Phu Horm Field in 2007; the PH-6, PH-7, and PH-10. All three wells were directionally drilled from the PH-4 well pad. The PH-10 well was tied into the field s production system and began producing gas in November The other two wells are in various stages of early production testing and completion and/or sidetracking operations. The Lower Huai Hin Lat formation, a Triassic-aged conglomeratic sequence overlying the Pha Nok Khao, has also been penetrated by the wells at the Phu Horm Field. The Lower Huai Hin Lat formation consists primarily of conglomerates, carbonates, and siltstones. The producing section is approximately 98 to 115 feet thick in the PH-1 and PH-3 wells. The Lower Huai Hin Lat thickens away from the crest of the structure. Huddleston & Co., Inc.

11 Coastal Energy Company Board of Directors April 21, 2008 Page Five A third formation immediately below the Pha Nok Khao, the Lower Permian Si That formation, is also present in the field. The Si That sequence is a Lower Permian-aged sequence comprised of an upper clastics section with some coals and a thicker carbonate section. The Si That formation lies immediately below the Pha Nok Khao. A wedge of the Si That is present on the western flank of the structure. The Si That formation tested roughly 1.0 MMcf per day of gas in the Cairn 2 well, located approximately 30 miles east of the Phu Horm Field in the southern area of Block L13/48. The Si That has not been tested in the Phu Horm Field. Cores from the Pha Nok Khao formation show that the porosity ranges between 1% and 4% in the limestone and between 2% and 6% in the dolomite. Fractures are evident, but permeability measurements were generally below 1.0 millidarcy. Porosity in the Huai Hin Lat formation varies from 2% to 4%. These values were based on PH-1 log analyses and PH-2 core analyses. Porosities in the Si That formation were between 1% and 2%. A third appraisal well, the Dong Mun-3 ( DM-3 ) well was spudded in the Dong Mun Field in the onshore Block L27/43 in November As of December 31, 2007, the well was still being drilled by the operator. Two wells have already been drilled on the Dong Mun structure. The DM-1 well was drilled and tested by Esso in The DM-2 well was also drilled in 1990 but was suspended and never tested. Both wells had significant gas shows while drilling through the upper Phu Kheng sandstone series formations. Wireline logs show the sandstone porosities to be in the 3% to 5% range. The DM-1 well was extensively production tested in the deeper carbonates of the Pha Nok Khao formation. The test rates ranged from 0.26 to 23.6 MMcf per day. In addition to the DM-3 well, operators on the onshore license areas have drilling operations underway in the first quarter of 2008 for the South Phu Horm-1 well in hopes of extending the productive limits of the currently producing Phu Horm Field. Offshore Summary: Three discrete Tertiary half graben basins, the Songkhla, Nakhon, and Kho Kra Basins, lie within the offshore Block G5/43. The basins contain up to 13,000 feet of sedimentary section and are characterized by early Tertiary rift phase, during which lacustrine sediment systems were dominant. The structures within the basins are primarily tilted fault traps or antiform features related to rollover into the basin margin faults. Structuring is best developed at the Oligocene and older levels, with ultimate top seal provided by a thick calcareous claystone unit of late-oligocene age. A schematic stratigraphic sequence of the Songkhla Basin is attached as Figure 5. The Bua Ban structure is a North-South elongated anticline running along the downthrown side of the Western Bounding Fault of the Songkhla Basin. The field is located approximately 17 miles north of the port of Songkhla and 10 miles from the coast. The Lower Oligocene formation appears to have been deposited as a lacustrine delta, with sediment entering the basin from the west, crossing the Western Boundary Fault to the North of the Bua Ban structure, and spreading out along the downthrown side of the fault system. The regional seal across the entire basin is the Upper Oligocene lacustrine shale. In 1990 the Bua Ban 1 well was drilled as a straight hole in 61 feet of water on a separate structure west of the Songkhla 1 well. The objective was the Lower Oligocene section that was found to be oil-bearing in the Songkhla 1 well. The Bua Ban 1 well was drilled to a total depth of 9,799 feet. The wellbore penetrated the Lower Oligocene at about 7,826 feet and found thin-bedded sands separated by a tight grey, micareous, and slightly carbonaceous claystone. The upper of these two sands, extending from 7,826 to 7,869 feet, was a very fine, well sorted sub-angular, well cemented argillaceous light brown to light grey/brown oil-stained sandstone. Visible porosity was described as poor to fair, and the associated show exhibited yellow fluorescence with the presence of a light straw cut in the sample. The lower sand from 7,913 to 7,964 feet was similar to the above sandstone except that there was less oil staining. Huddleston & Co., Inc.

12 Coastal Energy Company Board of Directors April 21, 2008 Page Six The Bua Ban Fan was encountered in the Bua Ban 3 well at 7,368 feet true vertical depth ( TVD ) through 7,666 feet TVD, with indications of hydrocarbon fluorescence and gas peaks containing butane. Repeat formation test ( RFT ) samples indicated an oil column within the Bua Ban reservoir. samples obtained from 7,290 and 7,558 feet TVD had a specific gravity of 0.85 (about 25 API). Reserve and Resource Estimates Reserve Estimates Huddleston assigned oil reserves to two offshore oil fields in Block G5/43, the Bua Ban Field and the Songkhla Field, and gas and condensate reserves to one onshore gas field in Blocks EU1 and E5N, the Phu Horm Field. The Block G5/43 offshore license area has been assigned Proved Undeveloped, Probable Undeveloped, and Possible Undeveloped oil reserves and is owned by Coastal Energy. The EU1 and EN5 onshore license areas have been assigned Proved Developed Producing, Proved Undeveloped, and Probable Undeveloped gas and condensate reserves and are owned by APICO, of which Coastal Energy owns 36.1%. For AIM admission purposes, Table 3 summarizes the Proved, the Proved + Probable, and the Proved + Probable + Possible reserve assignments under various interest scenarios for the three Coastal Energyowned fields in Thailand. The section of Table 3 summarizes reserves resulting from cash flow projections in which both working interests and revenue interests were set equal to 100%. The Working Interest section summarizes reserves resulting from cash flow projections in which both working interests and revenue interests were set equal to the net working interests owned by the particular Coastal Energy entity. As shown in Table 2, Coastal Energy owns a 100% working interest position in the two offshore oil fields, Bua Ban and Songkhla. Coastal Energy owns a 12.6% working interest position in the onshore gas field production license EU1 and EN5 at Phu Horm via APICO. In this case the royalty volumes were included in the net reserve volumes because the revenue interests were set equal to the net working interests. The to Coastal Energy section summarizes reserves resulting from cash flow projections that used net working interests and net revenue interests. In this case the net revenue interests have been reduced to reflect the deduction of royalty volumes. All Proved reserve assignments have been supported by actual production operations or well tests in the target reservoirs. The schedules of future recovery and production profiles for such reservoirs may be affected by the actual performance of individual completions. Phu Horm Field: Eight wells have been drilled in the Phu Horm Field. PH-1, the discovery well, was drilled in 1983, and PH-2 was drilled in Both wells were drilled in Block EU1 license area and Esso Exploration Inc. operated both wells. The PH-3 well was drilled in 2003 by Hess and is located in Block E5N. The PH-4 and PH-5 wells were drilled in 2004 and are located in the south of Block EU1 and the south of Block E5N, respectively. In 2007 Hess directionally drilled three more wells form the PH-4 well pad. The PH-6 well was drilled to the north and encountered approximately 1,965 gross feet of Pha Nok Khao carbonates. The well had gas shows form the mud log but showed poor gas flow rates of 3.1 to 5.1 MMcf per day on subsequent tests with no obvious fracture zones in the wellbore. Work on the well was suspended pending additional workover operations scheduled for late The PH-7 well was drilled to the west and encountered approximately 1,788 gross feet of tight Pha Nok Khao carbonate section. There were no gas shows in the Pha Nok Khao formation because of the lack of any significant dolomite sections and fractured zones. The well was suspended pending possible sidetracking operations. The PH-10 well was drilled to the east and encountered 800 gross feet of the Pha Nok Khao formation. The well tested about 6.8 MMcf of gas per day pre-acid and about 10.0 MMcf per day post-acid treatment. The well was placed on-line in late November 2007, and produced about 7.0 MMcf per day through mid-december Huddleston & Co., Inc.

13 Coastal Energy Company Board of Directors April 21, 2008 Page Seven The onshore license area containing Blocks EU1 and E5N covers the majority of the producing Phu Horm Field. Reserves and revenues for the Phu Horm Field have been prepared with consideration for our understanding of the terms of the July 19, 2005, Phu Horm Sales Agreement ( GSA ) between PTT Public Company Limited ( PTT ) and Hess and other partners in Blocks EU1/EN5. The GSA allows make-up gas to be produced from Blocks EU1/E5N to run the Nam Phong Power Station that is owned and operated by the Electricity Generating Authority of Thailand and is located approximately 25 miles south of the Phu Horm Field. Furthermore, the GSA also specifies the parameters to be used in the calculation of the gas price and associated gas price adjustments for gas produced from the EU1/E5N license area. As shown in Table 4, the GSA provides for a Daily Contract Quantity ( DCQ ) volume of 108 MMcf per day. Until recently, the primary field supplying gas to the Nam Phong Power Station was the older Nam Phong Field, located a few miles west of the power station. As gas production from the Nam Phong Field declines, more gas will be produced from the Phu Horm Field. The future gas production schedule for the Nam Phong Field, as shown in Table 4, was supplied by Coastal Energy. The difference between the GSA DCQ volumes and the Nam Phong Field gas volumes was used to determine the DCQ volumes attributable to gas from the Phu Horm Field. The Phu Horm Field began producing gas to the Nam Phong Power Station under the PTT contract on November 30, As of December 2007, the average daily gas rate was MMcf per day (see Figure 6 and Table 5). As shown in Table 5, the associated condensate yield for 2007 averaged approximately 5.47 barrels per MMcf of gas. Cumulative production volumes, as of December 31, 2007 were estimated to be 33,243 MMcf of gas and 181,762 barrels of condensate from the Phu Horm Field. The total estimated ultimate gas and condensate reserves shown for the Proved and Probable reserve categories at the Phu Horm Field (from Table 4) were based on volumetric calculations. All of the gas and condensate reserves at the Phu Horm Field were limited to the Pha Nok Khao formation in Blocks EU1 and E5N. volumes in the Pha Nok Khao formation that were contained in the adjacent Block L15/43 or other volumes in formations other than the Pha Nok Khao formation in either Blocks EU1/E5N or Block L15/43 were classified as Contingent and/or Prospective resources. Volumetric cases for low, best and high estimates for the Pha Nok Khao and the Si That formations were developed by Huddleston using the same depth assignments for both formations. The low estimate case used lowest known gas down to 7,320 feet TVD subsea ( TVDSS ) and was based on the lowest gas from the PH-1 well logs. The low estimate for the Pha Nok Khao formation was the basis for the Huddleston assigned Proved reserve volumes for the Phu Horm Field. The best estimate case used the lowest known gas down to 7,475 feet TVDSS, which was taken from the lowest perforation of Drill Stem Test ( DST ) #3 for the PH-2 well. The high estimate case used lowest known gas down to 8,485 feet TVDSS and was based on gas-water contact interpretations by the operator, Hess, from pressure data, mud log data, drilling shows and well logs. As shown in Table 4, a total of Bcf of gas reserves were assigned to the Pha Nok Khao formation under Blocks EU1 and E5N in the Phu Horm Field. On a gross basis, approximately Bcf was assigned as Proved, Bcf to Proved Developed Producing and 41.2 Bcf To Proved Undeveloped, and Bcf was assigned as Probable Undeveloped. The total gross Proved volume of Bcf includes Bcf of cumulative gas production as of December 31, The Proved Bcf assignment was taken from the Low Estimate volumetric reserve case volume of Bcf as shown in Table 7. A summary of the various engineering and geologic parameters that were used to develop the volumetric estimates can be found in Tables 6 and 7. Huddleston & Co., Inc.

14 Coastal Energy Company Board of Directors April 21, 2008 Page Eight The scheduling of the Proved Developed Producing gas reserves was based on the historical performance of the producing wells in the Phu Horm Field as of December 31, Four of the last eight wells drilled in the Phu Horm Field, the PH-3, PH-4, PH-5, and PH-10, will serve as the take points for the current Proved Developed Producing gas volumes. The two earlier wells, the PH-1 and the PH-2, have been plugged and abandoned. Currently the four existing wells are producing the DCQ rates as stated in the GSA. The producing wells have a high Productivity Index ( PI ) with reported Absolute Open Flow ( AOF ) Potentials ranging from 98 to 258 MMcf of gas per day. Productivity from these wells exceeds the rates measured in the two earlier wells drilled at Phu Horm. Budgets supplied by Coastal Energy show that five more wells will be drilled through The primary term of the GSA runs 15 years beginning in 2006 through Huddleston assumed that the GSA would be extended another 10 years, through Probable gas reserve volumes were assigned to the Huddleston-assumed extension of the GSA. The total ultimate Proved + Probable gas reserve volume of Bcf (of which Bcf is Probable) can be compared to the Best Estimate of 1,638.7 Bcf as shown in Table 7. Huddleston has not received any engineering or geologic information on the two license blocks shown in Table 2. There have been no reserve or resource volumes assigned to the onshore License Area Block L13/48 or to the offshore License Block Area G5/50 in this report. Bua Ban Field: The discovery well for the field was the Bua Ban 1 well that was drilled as a straight hole in January The well reached a total depth of 9,799 feet and found oil in the Lower Oligocene formation from 7,620 to 7,960 feet. Several Lower Oligocene intervals flow tested 420 to 768 barrels per day of 29 API waxy crude oil. In 2005 three more wells were drilled into the Lower Oligocene formation in the Bua Ban Field area: the Bua Ban 2, 2A, and 3 wells. The three wells helped define the productive limits of the oil field. The Bua Ban 2 well was drilled in July 2005 as a long-reach deviated well to a total depth of 7,968 feet TVD. An attempt was made to test the well but the lack of proper equipment and other failures resulted in the well not being tested. The well was temporarily abandoned without testing. The Bua Ban 2A well was drilled as a sidetrack of the 2 well. The main formation was encountered on the Bua Ban 2A well at 7,343 feet to 7,630 feet TVD, with indications of hydrocarbon fluorescence and gas peaks. RFT samples indicated an oil column within the Bua Ban reservoir. samples with a specific gravity between and 0.85 (around 25 API) were obtained from 7,483 feet to 7,521 feet TVD. Attempts were made to test the Bua Ban 2A well, but due to barite plugging problems the well would not flow properly and was not tested. The Bua Ban 3 well was kicked off from the Bua Ban 2/2A plug back. The Bua Ban 3 well was drilled as a long-reach deviated well to a total measured depth of 9,156 feet (7,779 feet TVD). The first DST tested the interval from 7,642 feet to 7,665 feet TVD. The second DST tested the interval from 7,620 feet to 7,642 feet TVD. Both tested intervals were within the lower sandstone unit of the Bua Ban Fan and both tests showed the presence oil. The second DST had a reported maximum flow rate of barrels of oil per day on a 5/16-inch choke with specific gravity of and a pressure of 80 psi at the wellhead. After logging and testing the well was plugged and abandoned. Huddleston assigned Proved Undeveloped, Probable Undeveloped, and Possible Undeveloped reserves in the Lower Oligocene formation at the Bua Ban Field. The Coastal Energy development schedule showed that the larger 1,772 acre Bua Ban Field would be developed with a total of seventeen producing wells, equating to roughly a 104 acre drainage area per well. Huddleston scheduled sixteen wells as Proved Undeveloped and one more as Probable Undeveloped. The seventeen-well assignment was based on Coastal Energy s planned installation of two platforms in the Bua Ban area. Huddleston & Co., Inc.

15 Coastal Energy Company Board of Directors April 21, 2008 Page Nine The reserve assignments for all of the reserve categories were primarily based on well test data taken from the existing four wells at the Bua Ban Field and the one well drilled and tested at the Songkhla Field. These performance-based assignments were compared to volumetrically derived reserve volumes to test their validity. The performance-based assignments are summarized in Tables 8 and 9 for Bua Ban and Songkhla, respectively. The Proved Undeveloped, Incremental Probable, and Incremental Possible reserve volumes (as shown in Tables 8 and 9) were input into the cash flow model and scheduled relative to the production scheme: natural flow with an assumed depletion drive production mechanism in the reservoir for Proved Undeveloped reserves and enhanced flow for the recovery of the incremental Probable and Possible Undeveloped reserves. Enhanced flow rates were attributable to high volume downhole electric submersible pumps ( ESP ) and the drilling of water injection wells. At the Bua Ban Field the oil start rate under natural flow from the Lower Oligocene Unit C formation was 600 barrels of oil per day per well. The start rate was based on test rates from the Bua Ban wells of 420 to 768 barrels of oil per day. The Proved Undeveloped reserve assignment was 6.0 million barrels of oil for sixteen wells. Volumetrically the Bua Ban Field was estimated to be 1,772 acres with 82.4 feet of net oil pay for the 1P and 2P cases (see Table 6). A recovery factor for the Low Estimate case of 10% yields a recoverable oil volume of million barrels of oil. Huddleston assigned the lower of the two volumes, 6.0 million barrels of oil, to the Proved Undeveloped reserve category. This Proved assignment represents about a 8.4% recovery factor for the Lower Oligocene formation under primary depletion. The incremental Probable Undeveloped reserve assignment was developed from a Proved + Probable reserve case. This case was developed to account for the use of ESP s and a water injection program plus the drilling of one more Probable well. A production schedule was modeled by assuming that the ESP s would allow all seventeen wells to produce at 1,200 barrels of oil per day per well. This higher rate was determined from a Schlumberger report on the Songkhla Field (to be discussed later) that was supplied by Coastal Energy. The Proved + Probable model yielded a total of 21.8 million barrels of oil, which represents about a 30% recovery factor. The difference between the 2P case and the 1P case was 15.8 million barrels of oil, which was assigned to the Probable Undeveloped category as incremental recoverable reserves. The incremental Possible Undeveloped reserve assignment was developed from a 3P reserve case. The Possible Undeveloped reserve case assumed the development of additional structural highs in the Lower Oligocene formation in the Bua Ban Field. These structural highs were identified as a result of 3D seismic interpretations which show possible thick zones in the Lower Oligocene which have not been proven by drilling, but which will be drilled by Coastal Energy in A 3P production schedule was again modeled by assuming that all seventeen wells will have ESP s installed with water injection operations. The 3P model yielded a total of 27.8 million barrels of oil, which represents about a 30% recovery factor for the larger 3P reservoir volumes. The difference between the 3P modeled case and the 2P modeled case was 6.0 million barrels of oil, which was assigned to the Possible Undeveloped category as incremental recoverable reserves. Songkhla Field: The Songkhla 1 well was drilled in 1988 in 78 feet of water to a total depth of 8,675 feet and discovered oil in the Lower Oligocene formation between 7,436 and 7,610 feet. Two sandstone sections of the Lower Oligocene encountered oil shows and were tested over a period of thirteen days. Test results recovered 30 API crude oil with a pour point of 109 F containing 33.8% paraffin, a maximum of 6% CO 2, 10 ppm of H 2 S, and a gas-oil ratio ( GOR ) of 140 scf per barrel. Test rates ranged from 950 to 1,500 barrels of oil per day from the Lower Oligocene formation. Huddleston & Co., Inc.

16 Coastal Energy Company Board of Directors April 21, 2008 Page Ten Coastal Energy had Schlumberger perform an evaluation of the Songkhla Field. Coastal Energy supplied Huddleston with preliminary Schlumberger reports in January The Schlumberger reports used all of the available geologic and reservoir data for the Songkhla Field to develop a reservoir model, perform reservoir simulation, and ultimately to test various production scenarios for the future development of the Songkhla Field. Schlumberger s preliminary results showed a range of recoveries for various development scenarios. The recoveries ranged from approximately 270,000 barrels of oil for a one-well, natural flow, limited aquifer case (1.3% recovery) to million barrels of oil for a five-well case with ESP s and water injection (40.5% recovery). The primary zone of interest in the study was the Lower Oligocene Unit 3 reservoir at approximately 7,345 feet TVDSS. The Schlumberger initial oil production rates ranged from 1,500 barrels of oil per day per well for the natural flow case to 2,000 barrels of oil per day per well for wells with ESP s installed. The Schlumberger report stated that nitrogen injection in a crestal well would lead to early breakthrough at the producers. Their model of a three-well nitrogen injection scenario showed a recovery as high as million barrels of oil (29.4% recovery). Huddleston assigned Proved Undeveloped, Probable Undeveloped, and Possible Undeveloped reserves in the Lower Oligocene formation at the Songkhla Field. The Coastal Energy development schedule shows that the 326 acre Songkhla Field will be developed with a total of four producing wells, equating to roughly an 81.5 acre drainage area per well. Huddleston scheduled all four wells as Proved Undeveloped. The Proved reserves volumes were based on natural flow from the Lower Oligocene Unit reservoir with an initial start rate of 1,200 barrels of oil per day per well. The start rate was based on test rates from the Songkhla 1 well of 950 to 1,500 barrels of oil per day. Under natural flow and assumed depletion drive mechanism in the reservoir the total Proved Undeveloped reserve assignment was million barrels of oil. Volumetrically the Songkhla Field was estimated to be 326 acres with 81.8 feet of net oil pay (see Table 6). A recovery factor for the Low Estimate case of 10% yields a recoverable oil volume of million barrels of oil. Huddleston assigned the million barrels of oil to the Proved Undeveloped reserve category. This Proved assignment represents about a 10% recovery factor for the Lower Oligocene formation under primary depletion. The incremental Probable Undeveloped reserve assignment was developed from a 2P reserve case. This case was developed to account for the use of ESP s and water injection in the four Proved wellbores. A production schedule was modeled by assuming that the ESP s would allow the four wells to produce at 2,000 barrels of oil per day per well. This higher rate was determined from the above discussed Schlumberger report. The 2P model yielded a total of 4.9 million barrels of oil, which represents about a 21% recovery factor. The difference between the modeled case and the Proved case was million barrels of oil, which was assigned to the Probable Undeveloped category as incremental recoverable reserves. The incremental Possible Undeveloped reserve assignment was developed from a 3P reserve case. The Possible Undeveloped reserve case assumed the use of ESP s and a water injection program. A production schedule was modeled by all four wells will have ESP s installed with water injection operations. The 3P model yielded a total of million barrels of oil, which represents about a 30% recovery factor. The difference between the 3P modeled case and the 2P modeled case was million barrels of oil, which was assigned to the Possible Undeveloped category as incremental recoverable reserves. All of the oil volumes evaluated in this report for both the Bua Ban Field and the Songkhla Field have been assigned to either the Proved, Probable, or Possible reserve categories. No oil volumes from either of these two fields has been classified as either Contingent or Prospective resources. Huddleston & Co., Inc.

17 Coastal Energy Company Board of Directors April 21, 2008 Page Eleven The associated gas production from the offshore oil volumes was estimated to be 140 standard cubic feet per barrel (scf/bbl). The GOR and associated gas volumes are presented in Table 6 for illustrative purposes only. Coastal Energy plans to use all of the offshore produced gas for lease use purposes and none of this gas will be sold. The Huddleston future reserve and revenue projections contained in this report do not include any economic values for the offshore gas volumes nor are the volumes included in either of the Contingent or Prospective resource categories. Contingent and Prospective Resources Contingent Resources are those quantities of oil and gas that are determined to be potentially recoverable from known accumulations, but which are not currently considered to be commercially recoverable because of price and technology limitations. Prospective Resources are those quantities of oil and gas that are determined to be potentially recoverable from undiscovered accumulations. There is a significantly higher risk with Prospective Resources, relative to Contingent Resources, that they will not mature into revenue generating projects. As per AIM guidelines, both Contingent and Prospective resource volumes shown in this report are assigned a geological risk factor. For Contingent Resources the geologic risk factor is defined as the estimated chance or probability that the volumes will be economically extracted from known accumulations. For Prospective Resources the geologic risk factor is defined as the estimated chance or probability of discovering hydrocarbons in sufficient quantities for them to be tested to the surface, which is the chance or probability of the Prospective Resources maturing into a Contingent Resource. Contingent Resources: For AIM exchange purposes, the estimates for Contingent resources are summarized in Table 10 for various license blocks and associated formations. Contingent resources were assigned for one offshore license area, Block G5/43, and to three onshore license areas, Blocks EU1/E5N, L15/43, and L27/43. The offshore block contained two oil prospects, the Benjarong Prospect and the Songkhla SW Prospect (Figure 3). Huddleston assigned Contingent oil resources to these two prospects based on the results from earlier exploratory drilling operations on the two prospects. The Benjarong 1 well was drilled in April 1996 and reached a total depth of 10,440 feet. The Lower Oligocene formation was not present in the wellbore but a low permeability sand section below 9,971 feet in the Eocene formation showed hydrocarbon fluorescence, an estimated 60.5 feet of net pay, and recovered a small amount (about one gallon) of 31.5 API waxy crude. The well was later plugged and abandoned due to low permeability of the Eocene formation, testing problems, license expirations, and low oil prices. The Songkhla SW 1 well was drilled in May 1990 and reached a total depth of 9,255 feet. The Lower Oligocene formation at 7,540 to 7,705 feet flow tested 90% water and 10% oil with a nominal amount of gas. A deeper zone at 7,877 to 8,010 feet flow tested 100% water. The well was later plugged and abandoned. The Songkhla South 1 well was drilled in April 1990 to a total depth of 9,152 feet. The well did not find any significant hydrocarbon shows in the Lower Oligocene formation and was plugged and abandoned. Coastal Energy supplied core data, well log interpretations, geologic maps, and seismic cross-sections for the Benjarong and Songkhla SW prospect areas. Huddleston used this information to develop subsurface maps, which were planimetered to develop low, best, and high estimates for the Contingent resource assignments. The Contingent resource assignments were based on volumetric calculations with Huddleston & Co., Inc.

18 Coastal Energy Company Board of Directors April 21, 2008 Page Twelve consideration for analogy to the Bua Ban and Songkhla Fields. A summary of the Contingent volumetric parameters appears in Table 6. The oil volumes for the two offshore prospects were classified as Contingent because the early exploratory wellbores did penetrate and test known hydrocarbon formations, the Lower Oligocene and the Eocene. Huddleston assigned geologic risk factors of 30% (see Table 10) to the two Contingent offshore oil prospects because of limited and low volume test results. The onshore blocks had Contingent gas and associated condensate resources assigned to the Pha Nok Khao and Huai Hin Lat formations in the Phu Horm Field in Blocks EU1/E5N and L15/43. Contingent gas resources were also assigned to the Pha Nok Khao formation in the Dong Mun Field in Block 27/43. The onshore Contingent resource assignments were based on engineering and geological data supplied by Coastal. Table 11 was developed by Huddleston to show the evolution of Contingent resource assignments relative to production, GSA contract terms, and previously discussed Proved and Probable reserve assignments for the Pha Nok Khao formation of the Phu Horm Field in Blocks EU1 and E5N. The last line in Table 11 can be traced directly to the gross estimated volumes for the Pha Nok Khao formation on the onshore Blocks EU1/E5N in Table 10. The Contingent resource assignment for the Pha Nok Khao formation was based on volumetric calculations as shown in Table 7. The Huai Hin Lat formation in the Phu Horm Field lies above the Pha Nok Khao formation and underlies Blocks EU1, E5N, and L15/43. It is uncertain whether or not the Huai Hin Lat formation has ever tested in conjunction with flow testing operations of the Pha Nok Khao formation in other Phu Horm wells. The Huai Hin Lat has been penetrated and logged by the drilled wells. The associated condensate yield for the formation was assumed to be 4.67 barrels per MMcf. The gas and condensate volumes for the Huai Hin Lat formation were classified as Contingent because of the terms of the GSA contract and the lack of test information. The Pha Nok Khao formation in the Dong Mun Field, Block L27/43, was drilled and tested by Esso in The DM-1 well tested 0.26 to 23.6 MMcf per day in 1990 from the Pha Nok Khao carbonate formation. The DM-2 well was also drilled in 1990 but was suspended and never tested. Both wells had significant gas shows while drilling through the upper Phu Kheng sandstone series formations. Wireline logs show the sandstone porosities to be in the 3% to 5% range. The gas volumes for the Pha Nok Khao formation were classified as Contingent because of the terms of the GSA contract. Huddleston assigned geologic risk factors between 30% and 50% for the various Contingent gas resource assignments as shown in Table 10. Prospective Resources: For AIM exchange purposes, the estimates for Prospective resources are summarized in Table 12 for various license blocks and associated formations. Prospective resources were assigned to thirteen oil prospects in one offshore license area, Block G5/43, and to three gas prospects in three onshore license areas, Blocks EU1/E5N, L15/43, and L27/43. The offshore block contained five oil prospects, the Western Fault Terrace ( WFT ) WFT-A, B, C, D and E Prospects (Figure 7). These five WFT prospects lie on strike with the Bua Ban Field. The G5/43 offshore block also contains eight additional Songkhla oil prospects as shown in Figure 8. These eight Songkhla prospects lie on strike with the Songkhla Field. Coastal Energy supplied geologic maps and seismic cross-sections for the offshore oil prospect areas. Huddleston used this information to develop subsurface maps, which were planimetered to develop low, best, and high estimates for the Prospective resource assignments. The Prospective resource assignments in the Oligocene and Eocene formations were based on volumetric calculations with consideration for analogy to the Bua Ban and Songkhla Fields. A summary of the volumetric parameters appears in Table 6. The oil volumes for the thirteen Huddleston & Co., Inc.

19 Coastal Energy Company Board of Directors April 21, 2008 Page Thirteen offshore prospects were classified as Prospective because none of them have been drilled to date, but represent potentially recoverable volumes from undiscovered accumulations. As summarized in Table 12, Huddleston assigned geologic risk factors of between 5% and 10% to the thirteen offshore oil prospects. Two onshore blocks had Prospective gas resource volumes assigned to the Si That formation in the Phu Horm Field in Blocks EU1/E5N and L15/43. The Si That formation lies immediately below the Pha Nok Khao formation and is present on the western flank of the Phu Horm structure. The Si That formation tested approximately 1.0 MMcf of gas per day in the Cairn 2 well which is located approximately 30 miles east of the Phu Horm Field in the southern area of Block L13/48. The Si That has not been tested in the Phu Horm Field. The onshore Block L27/43 also had Prospective gas resource volumes assigned to the Phu Kheng sandstones in the Dong Mun Field. The Phu Kheng sandstones consists of three individual sandstone formations, the Phu Kradung, the Upper Nam Phong, and the Lower Nam Phong. Esso drilled the DM-1 and the DM-2 wells in 1990 and both wells had significant gas shows while drilling through the upper Phu Kheng sandstone series formations, but the sandstones were never tested. The gas volumes for the Phu Kheng sandstones were classified as Prospective because of the terms of the GSA contract and the lack of test data. The Prospective resource assignment for the Si That and Phu Kheng formations were based on engineering and geological data supplied by Coastal Energy. The Prospective gas resource assignments were based on volumetric calculations with consideration for analogy to the Pha Nok Khao formation at the Phu Horm Field. Huddleston assigned geologic risk factors between 2% and 5% for the various Prospective gas resource assignments as shown in Table 12. As stated above, the Contingent and Prospective resource volumes contained in this report have no economic value attributable to them. Economic Analysis Constant and Forecast s: For the purposes of TSX and AIM admission, the Coastal Energy reserves discussed in this report have been prepared using two economic scenarios, a constant price case and a forecast price case, and two sets of tax assumptions, before and after income taxes. s for the constant price case were determined for the oil, gas, and condensate reserves for the three fields using data supplied by Coastal Energy. Table 13 summarizes the constant and forecast prices that were used to generate the future revenues contained in this report. The initial price for the offshore crude oil constant pricing case at Bua Ban and Songkhla Fields was $99.03 per barrel. The offshore price was based on the difference between Brent crude oil and Tapis crude oil. Huddleston calculated a differential of +$5.35 per barrel based on a comparison of posted prices for the twelve-month period from January 2007 through December The +$5.35 per barrel differential was then applied to the posted Brent spot price as of December 31, 2007 of $96.68 per barrel to yield the constant price for the offshore crude oil of $99.03 per barrel. A transportation fee of $0.50 per barrel was deducted in the cash flow model. The initial oil price and transportation fee were held constant throughout the life of the offshore oil properties. The initial price for the onshore condensate at the Phu Horm Field was $84.72 per barrel. The onshore price was based on the posted price of Australian Northwest Shelf ( NWS ) crude oil was reduced by an adjustment factor of Huddleston applied adjustment factor to a December 2007 posted price for NWS crude of $88.90 to yield the constant price for the onshore condensate of Huddleston & Co., Inc.

20 Coastal Energy Company Board of Directors April 21, 2008 Page Fourteen $84.72 per barrel. A transportation fee of $1.59 per barrel was deducted in the cash flow model. The initial oil price and transportation fee were held constant throughout the life of the offshore oil properties. The initial price for the onshore gas at the Phu Horm Field was $5.98 per Mcf. The onshore gas price was based on the difference between Brent crude oil and Singapore Spot HSFO 108 CST crude oil. Huddleston calculated a differential of -$22.93 per barrel based on the past six-month average of posted prices for the period July 2007 through December The -$22.93 per barrel differential and the December 31, 2007 HSFO price of $58.83 was then used in the gas price formula as specified in the GSA to determine a gas price of $6.054 per MMBtu. Huddleston then applied the actual historical Btu adjustment factor of Btu/scf, which was taken from Phu Horm gas sales statements supplied by Coastal Energy, to determine an initial gas price for the constant case of $5.98 per Mcf. The initial gas price was held constant throughout the life of the onshore gas properties. Projected prices for the forecast case were based on a projection of Brent crude oil as shown in Table 14. The Brent crude oil price projection as of December 31, 2007 was taken from the Gilbert Lausten Jung ( GLJ ) Petroleum Consultants website ( GLJ projected prices through 2017, and then applied a 2% per year escalation for the life of the properties. The projected forecast prices for the oil, gas, and condensate reserves from the three fields were calculated by applying the various pricing differentials and adjustment factors as discussed for the constant price case. The initial forecasted price for the offshore crude oil reserves at Bua Ban and Songkhla Fields was $95.85 per barrel. The forecasted price was projected for eleven years, throughout the life of the assigned offshore oil reserves. The initial forecasted price for the onshore gas reserves at the Phu Horm Field was $6.93 per Mcf. The initial forecasted price for the associated onshore condensate reserves at the Phu Horm Field was $85.21 per barrel. Both forecasted gas and condensate prices were projected for twenty-four years, throughout the life of the assigned onshore reserves. Operating Expenses: Fixed and variable operating expenses for the three fields were supplied by Coastal Energy. Coastal Energy supplied 2008 and 2009 capital budget projections for their onshore and offshore fields. The budget projections for the onshore Phu Horm Field were developed by APICO. Huddleston reviewed and adjusted the budgeted fixed operating expense projections where necessary. Adjustments were made to eliminate sunk operating expenses, i.e., those expenses realized by Coastal Energy prior to the effective date of December 31, operating expenses that did not relate directly to the operation of the three fields shown in Table 3, such as expenses allocated to exploratory activities in other fields, were also eliminated. Tables 15 and 16 summarize the annual projected fixed and variable operating expenses for the constant price case by reserve category for the gross interest ownership position and the Coastal Energy net ownership position, respectively. The monthly fixed operating expenses for the offshore Bua Ban Field and the offshore Songkhla Field were $2,836,500 and $1,413,497, respectively. The monthly fixed operating expenses for the onshore Phu Horm Field was $1,170,667. fixed operating expenses, on a 100% basis, for all three fields was $5,420,664 per month or about $65.0 million per year. Huddleston allocated the fixed operating expenses on a reserve category basis in the cash flow model. As is shown in Tables 15 and 16, the Proved reserve categories were burdened with a larger proportional share of allocated fixed operating expenses, followed by Probable, then Possible reserve categories. The fixed operating expenses for the constant price case were held constant throughout the life of the properties. Fixed operating expenses for the forecast price case were immediately escalated at 2% per year throughout the life of the properties. Variable operating expenses in the form of transportation fees for the crude oil at the two offshore fields and condensate at the onshore gas field were input into the cash flow model as a dollar per barrel Huddleston & Co., Inc.

21 Coastal Energy Company Board of Directors April 21, 2008 Page Fifteen expense. The Coastal Energy supplied data showed a transportation fee of $0.50 per barrel for offshore oil and a fee of $1.59 per barrel for onshore condensate. The impact of the variable operating expenses by reserve class can be seen in Tables 15 and 16. The variable operating expenses for the constant price case were held constant throughout the life of the properties. Variable operating expenses for the forecast price case were immediately escalated at 2% per year throughout the life of the properties. Capital Expenditures: Capital expenditure estimates and the scheduling of such expenditures were supplied by Coastal Energy. Coastal Energy supplied 2008 and 2009 capital budget projections for their onshore and offshore fields. The budget projections for the onshore Phu Horm Field were developed by APICO. Huddleston reviewed and adjusted the capital expenditures in the budget projections where necessary. Adjustments were made to eliminate sunk capital costs, i.e., those expenditures realized by Coastal prior to the effective date of December 31, capital expenditures that did not relate directly to the three fields shown in Table 3, such as capital expenditures allocated to exploratory activities in other fields, were also eliminated. Table 17 summarizes the annual projected capital expenditures for the constant price case by reserve category for the 100% ownership position. Tables 18 and 19 summarize the annual projected capital expenditures for the constant price case by field, then by reserve category for the gross interest ownership position and the Coastal Energy net ownership position, respectively. At the onshore Phu Horm Field expenditures began in 2005 and are scheduled to continue into The initial development of the field has been designed to meet the 108 MMcf per day DCQ requirement of the Nam Phong Power Station. Currently, four existing wells are producing the DCQ rates as stated in the GSA. Budgets supplied by Coastal show that five more wells will be drilled through Abandonment expenses have been assigned to the producing wells and field facilities in the year after they deplete. The Songkhla Field development has been scheduled to begin in early Surface facilities such as the process and wellhead platforms are being fabricated with installation scheduled for September Drilling operations are scheduled to begin in July 2008 with first production scheduled for November Abandonment expenses have been assigned to the wells and platform in the year after the field s reserves deplete. The Bua Ban Field development has been scheduled to begin in Drilling operations are scheduled to begin in June 2008 with a drilling barge. First production is scheduled for April 2009, after the installation of surface facilities and the A platform in March The B platform is scheduled for installation in August Abandonment expenses have been assigned to the wells and platforms in the year after the field s reserves deplete. Capital costs were projected on the basis of information provided by Coastal Energy. We have reviewed the estimates provided and believe they are consistent with the projected operations. The schedules of future operations were based on our understanding of available capital, representations by the company with respect to development operations, and our estimates of the ability to schedule such operations. Capital expenditures for the constant price case were held constant for the life of the properties. Capital expenditures for the forecast case were immediately escalated at 2% per year for the life of the properties. Income Tax Considerations: Tables 20 and 21 summarize the revenues attributable to the offshore and onshore reserves for the constant and forecasted pricing cases, respectively. The net revenues are Huddleston & Co., Inc.

22 Coastal Energy Company Board of Directors April 21, 2008 Page Sixteen reported before and after income taxes and have been discounted using rates of 0%, 5%, 10%, 15%, and 20%. A tax rate of 40% was used to prepare the after tax cash flow projections. The 40% rate was reduced from 50% due to the ability of Coastal Energy to offset the income tax by the royalty paid to the Thai government. Report Qualifications General office overhead has not been deducted from future revenues. We utilized certain geological and geophysical interpretations prepared by Coastal Energy in the calculation of the estimated reserve volumes. We have generally reviewed these interpretations and believe they are consistent with the available subsurface and geophysical information. However, in some cases the results of additional subsurface data and future geophysical operations may result in revisions to the subsurface interpretations and therefore to the estimated reserve volumes. The estimated reserves shown herein are substantially based on volumetric calculations and may be subject to a significant level of revision as additional drilling operations are conducted and additional performance data is obtained from both existing and future completions. In some cases the projections are dependent on the results of future operations. Proved Undeveloped, Probable, and Possible reserves will be subject to successively increasing levels of variation. There is a significantly greater level of certainty associated with the Proved reserves than with both Probable and Possible reserves and Contingent and Prospective resources. The development of the reserves shown herein may be affected by a variety of factors including availability of capital, the results of previous operations, the timing of facilities construction, and market conditions. THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES ARE NOT REPRESENTED AS MARKET VALUE. ESTIMATES FOR INDIVIDUAL COMPLETIONS SHOULD BE CONSIDERED IN CONTEXT WITH THE OVERALL ESTIMATED REVENUES. ACTUAL PERFORMANCE OF THE INDIVIDUAL COMPLETIONS MAY VARY CONSIDERABLY FROM THE PROJECTIONS, PARTICULARLY IN COMPARISON TO THE TOTAL COMPOSITE PRODUCTION. We did not inspect the properties or conduct independent well tests. Ownership, product prices, and other factual data have been derived from the files of Coastal Energy. We have generally tested the validity of these data and believe the information to be correct. Respectfully submitted, JPK:klh John P. Krawtz, P.E. Huddleston & Co., Inc.

23 FIGURES 1 10

24 FIGURE 1 Map of Thailand Onshore and Offshore License Areas Onshore Blocks: EU1, E5N, L15/43, L27/43, L13/48 Offshore Blocks: G5/43, G5/50 0 km 250 Source: Coastal Energy Company

25 FIGURE 2 Map of Thailand Onshore License Areas and Fields Phu Horm Field Block L15/43 Block L13/48 Nam Phong Field and Power Plant Khon Kaen Block L27/43 Dong Mun Field 0 Km 100 Source: Coastal Energy Company

26 FIGURE 3 Map of Thailand Offshore License Areas and Fields SONGKHLA -1 BUA BAN-2 SONGKHLA S-1 BUA BAN-2A BUA BAN-1 BUA BAN-3 SONGKHLA SW-1 BENJAROMG-1 5 km Source: Coastal Energy Company

27 FIGURE 4 Seismic Cross Section of Phu Horm Field Phu Horm 1 2 NW SE W E Top Upper Nam Phong Formation Top Lower Nam Phong Formation Indosinian 2 Unconformity "Triassic" Indosinian 1 Unconformity "Permian" Top Si That Formation "Upper Carboniferous" Mid-Carboniferous Unconformity U81a405 Source: Coastal Energy Company/NuCoastal/APICO K79a km

28 FIGURE 5 Schematic Cross Section of Songkhla Basin Area W Western Fault Terrace Bua Ban-1 and Benjarong-1 in Lw Oligocene and Eocene Basin centre untested stratigraphic plays Basin Centre Songkhla-1 and Songkhla SW-1 in Lw Oligocene and Eocene Eastern flank untested fan plays E Miocene 1 Up Oligocene 2 Eocene Lw Oligocene 0 Km 5 TWT 3 Fluvial sandstones Fan sandstones Lacustrine source rocks Lacustrine seal shales Fluvial shales Basement & PreT Source: Coastal Energy Company/Auldana Advisors

29 COND., bbl/d 400 Dec-07 FIGURE 6 Huddleston & Co., Inc PHU HORM GAS FIELD DAILY PRODUCTION (11/30/06-12/31/07) Nov-06 Dec-06 Jan-07 Nov-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07 Jul-07 Aug-07 Sep-07 Oct-07 DATE PTT Nomination Daily Sales Delivered Condensate GAS, MMcf/d

30 FIGURE 7 Map of Offshore Prospective WFT Prospects WFT-D WFT-A WFT-C WFT-B Bua Ban WFT-E Source: Coastal Energy Company/Auldana Advisors

31 FIGURE 8 Map of Offshore Prospective Songkhla Prospects Songkhla West Songkhla North A In A P2 Songkhla-1 A1 Pro-West-A&B Pro-West-C Proposed CPP Expl-1b Exp-1a Expl P3 P4 P1 Songkhla P2 South-West P3 In2 P4 WHP B WHP A Songkhla Flow line In1 P1 In Songkhla South-East A Songkhla-South-1 Songkhla South A5 Songkhla East Depth Map ry Scale Thailand 1:50000 Block Contour inc G5/43 25 License Date 06/06/2007 Source: Coastal Energy Company m 1:50000 MAP of prospects with Area outline