€¦ · TABLE OF CONTENTS Letter of Transmittal Report Preparation Review of 2010 Offshore...

Huddleston & Co., Inc. Petroleum and Geological Engineers

Texas Registered Engineering Firm F-1024 Houston, Texas

COASTAL ENERGY COMPANY

Thailand Property Evaluation

Special Pricing Report As of December 31, 2010

and

As of April 1, 2011

TABLE OF CONTENTS

Letter of Transmittal

Report Preparation

Review of 2010 Offshore Activity

Songkhla A Field

Songkhla C Field

Other Offshore Exploratory Areas

Review of Assets

Geologic Description

Offshore Summary

Onshore Summary

Reserve and Resource Estimates

Reserve Estimates

Contingent and Prospective Resources

Contingent Resources

Prospective Resources

Economic Analysis

Forecast Price Cases

December 31, 2010 Effective Date

April 1, 2011 Effective Date

Operating Expenses

Capital Expenditures

Income Tax Considerations

Report Qualifications

Figures

Tables

Appendices

List of Figures

1 Map of Thailand Onshore and Offshore License Areas

2 Map of Thailand Offshore Fields and Prospect Areas

3 Map of Thailand Onshore License Area and Prospect Areas

4 Seismic Cross Section of Songkhla Basin Area

5 Songkhla A and Songkhla C Fields Historical Production

6 Graphical Summaries of Estimated Future Net Production – Offshore Properties

List of Tables

1 Assets Net to Coastal Energy – Offshore Property Evaluation

1.1 December 31, 2010 Effective Date and Prices

1.2 April 1, 2011 Effective Date and Prices

2 Summary of Coastal Energy Licenses and Working Interests – Thailand

3 Summary of Remaining Reserves – Offshore

4 Summary of Volumetric Parameters for Offshore Oil Formations (Tables 4A through 4F)

5 Summary of Volumetric Parameters for Onshore Gas Formations

6 Summary of Remaining Reserve Assignments – Offshore Block G5/43 (Tables 5A through 5K)

7 Songkhla A and Songkhla C Fields – Gross Historical Oil Production

8 Summary of Contingent Resources – Offshore and Onshore

9 Summary of Prospective Resources – Offshore and Onshore

10 Forecast Price Case – Crude Oil Price Assumptions and Calculations

10A December 31, 2010 Effective Date and Prices

10B April 1, 2011 Effective Date and Prices

11 Summary of Lease Operating Expenses – Forecast Price Case – 100% Interests – Offshore

12 Summary of Lease Operating Expenses – Forecast Price Case – Net to Coastal Energy – Offshore

13 Summary of Capital Expenditures by Reserve Classification – Forecast Price Case – 100% Interests – Offshore

14 Summary of Capital Expenditures by Field – Forecast Price Case – 100% Interests – Offshore

15 Summary of Capital Expenditures by Field – Forecast Price Case – Net to Coastal Energy – Offshore

16 Comparison of Before and After Income Tax Net Revenues – Forecast Price Case – Offshore

16A December 31, 2010 Effective Date and Prices

16B April 1, 2011 Effective Date and Prices

17 AIF – Offshore Remaining Reserves Data – Forecast Prices and Costs

List of Tables Page Two 18 AIF – Offshore Net Present Value of Future Net Revenues – Forecast Prices and Costs

19 AIF - Offshore Future Net Revenue by Production Group – Forecast Prices and Costs

20 AIF - Offshore Future Net Revenues – Forecast Prices and Costs

21 AIF - Summary of Offshore Pricing and Inflation Rate Assumptions – Forecast Prices and Costs

22 AIF - Offshore Reconciliation of Net Reserves – Forecast Prices and Costs

List of Appendices A Glossary of Technical Terms

B Conversion Factors and Abbreviations

C Certificates of Qualification

D Canadian Form 51-101 F2

E Definitions of Reserves and Resources

Society of Petroleum Engineers (SPE) Petroleum Resources Management System (“SPE-PRMS”) Guide for Nom-Technical Users, March 2007 (see complete PRMS at SPE website as referenced in Appendix E)

Reserve Definitions, Canadian Securities Administrators National Instrument 51-101

F December 31, 2010 – Detailed Cash Flow Projections – Forecast Price Case – Net to Coastal Energy – Offshore Property Evaluation (Proved + Probable + Possible) – Table 1.1 Data

One-Line Cash Flow Report

Summary by Reserve Class

Detailed Cash Flow Report


1 Houston Center 1221 McKinney, Suite 3700

Houston, Texas 77010

PHONE (713) 209-1100 FAX (713) 752-0828

April 11, 2011

Coastal Energy Company Board of Directors Attention: Mr. Randy L. Bartley, CEO Walker House, 87 Mary Street PO Box 908GT George Town, Grand Caymans KY1-9001 Cayman Islands Re: SPECIAL PRICING REPORT Coastal Energy Company Thailand Offshore Property Evaluation As of December 31, 2010 and As of April 1, 2011 Gentlemen: At the request of Coastal Energy Company (“Coastal Energy”) and with approval from the Canadian reporting authorities, this report contains two separate effective dates, each with a different price forecast schedule. Pursuant to your request, we have evaluated certain oil interests owned by Coastal Energy. The interests evaluated in this report are located offshore Thailand in the Gulf of Thailand. The reserves and resources shown herein have been prepared with consideration for our understanding of National Instrument (“NI”) 51-101 (Disclosure of Oil and Gas 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 Investment Market (“AIM”) of the London Stock Exchange. December 31, 2010 Effective Date – Conclusions for the offshore oil reserve assets follow: Table 1.1 – Net to Coastal Energy – Offshore Property Evaluation – as of December 31, 2010* Estimated Future Reserves Future Net Revenue (“FNR”) Discounted at: Gross Oil Gross Gas Net Oil Net Gas 0% 5% 10% 15% 20% Forecast Price Case (Appendix F) (Mbbl) (MMcf) (Mbbl) (MMcf) (M$) (M$) (M$) (M$) (M$)

Proved Developed Producing 9,552 0 8,880 0 364,417 341,353 319,288 298,778 280,023 Proved Developed Nonproducing 687 0 633 0 49,126 46,574 44,067 41,665 39,399 Proved Undeveloped 4,250 0 3,945 0 318,927 283,897 254,692 230,149 209,360 Subtotal Proved 14,489 0 13,458 0 732,470 671,825 618,046 570,592 528,782 Total Proved (1P) 14,489 0 13,458 0 732,470 671,825 618,046 570,592 528,782 Probable Nonproducing 3,197 0 2,851 0 234,151 205,022 180,126 158,796 140,471 Probable Undeveloped 9,457 0 8,446 0 510,535 446,029 391,309 344,786 305,115 Subtotal Probable 12,654 0 11,298 0 744,686 651,051 571,435 503,582 445,585 Total Proved + Probable (2P) 27,143 0 24,756 0 1,477,156 1,322,875 1,189,481 1,074,174 974,367 Possible Nonproducing 4,377 0 3,815 0 324,404 275,355 234,780 201,059 172,906 Possible Undeveloped 12,494 0 10,930 0 878,979 744,133 633,168 541,375 465,047 Subtotal Possible 16,871 0 14,746 0 1,203,383 1,019,488 867,947 742,434 637,954 Total Proved + Probable + Possible (3P) 44,014 0 39,501 0 2,680,540 2,342,363 2,057,428 1,816,608 1,612,321 *Numbers subject to rounding.

Coastal Energy Company Board of Directors April 11, 2011 Page Two

Huddleston & Co., Inc.

April 1, 2011 Effective Date – Conclusions for the offshore oil reserve assets follow: Table 1.2 – Net to Coastal Energy – Offshore Property Evaluation – as of April 1, 2011* Estimated Future Reserves Future Net Revenue (“FNR”) Discounted at: Gross Oil Gross Gas Net Oil Net Gas 0% 5% 10% 15% 20% Forecast Price Case (Mbbl) (MMcf) (Mbbl) (MMcf) (M$) (M$) (M$) (M$) (M$)

Proved Developed Producing 8,703 0 8,106 0 442,698 414,372 387,682 363,050 340,582 Proved Developed Nonproducing 643 0 593 0 59,501 56,938 54,411 51,979 49,673 Proved Undeveloped 4,027 0 3,741 0 370,795 335,261 305,312 279,881 258,125 Subtotal Proved 13,373 0 12,440 0 872,995 806,571 747,406 694,911 648,380 Total Proved (1P) 13,373 0 12,440 0 872,995 806,571 747,406 694,911 648,380 Probable Nonproducing 3,161 0 2,820 0 277,831 247,242 220,785 197,846 177,905 Probable Undeveloped 9,307 0 8,315 0 629,622 560,279 500,636 449,206 404,719 Subtotal Probable 12,467 0 11,134 0 907,454 807,522 721,420 647,052 582,624 Total Proved + Probable (2P) 25,840 0 23,574 0 1,780,449 1,614,093 1,468,826 1,341,963 1,231,004 Possible Nonproducing 4,377 0 3,815 0 371,635 320,479 277,575 241,428 210,837 Possible Undeveloped 12,494 0 10,930 0 1,009,535 868,785 751,324 652,790 569,713 Subtotal Possible 16,871 0 14,746 0 1,381,170 1,189,264 1,028,899 894,218 780,551 Total Proved + Probable + Possible (3P) 42,711 0 38,321 0 3,161,618 2,803,357 2,497,725 2,236,181 2,011,555 *Numbers subject to rounding.

The mixture of effective dates was done at the request of Coastal Energy and reflects the higher oil prices in effect on April 1, 2011, versus those in effect as of December 31, 2010.

The April 1, 2011 forecast pricing case was developed by simply MECHANICALLY UPDATING the Coastal Energy database that was prepared as of December 31, 2010. The mechanical updating procedure basically moved the effective date forward three months to April 1, 2011. The only other modification was the use of an updated April 1, 2011 oil price forecast. All other technical, engineering, geological, and other economic assumptions such as assigned reserve and resources volumes, the scheduling of those volumes, working and net revenue interests, monthly operating expenses, capital expenditures and the timing of those expenditures have not been updated as of April 1, 2011, except for the effects due to the mechanical updating procedures on the first three months of 2011.

Report Preparation

All projections of future net reserves and revenues from this point of the report forward only refer to the effective date of December 31, 2010.

This report contains projections of future net oil reserves and revenues for Proved, Probable, and Possible reserves owned by Coastal Energy for just their offshore oil properties. In the past, Huddleston has also evaluated net gas reserves and revenues for Proved, Probable, and Possible reserves owned by Coastal Energy for their onshore properties located in the Sinphuhorm Gas Field in Thailand. As of December 31, 2010, the evaluation of the onshore gas reserves has been prepared by another consulting company. This report does contain Contingent and Prospective resources volumes for one onshore license area outside of the Sinphuhorm Gas Field that Huddleston has evaluated in the past. Economic projections were not prepared for the Contingent and Prospective resource volumes; only their associated oil and gas volumes are presented herein.

At the request of Coastal Energy, the net reserves and revenues contained in this report have been prepared with forecast price assumptions only. Constant price case net reserves and revenues have not been included in this report.

Coastal Energy Company Board of Directors April 11, 2011 Page Three


The reserve volumes contained herein have not been adjusted for risk. The cash flow revenue projections have been prepared using unrisked reserve volumes as discussed in this report.

The projected reserves and revenues shown herein have been prepared in accordance with our understanding of the requirements of NI 51-101 and the Canadian Oil and Gas 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 and forecast prices and costs. Tables 17 through 22 in this report are intended to reflect the reporting requirements for oil and gas reserves pursuant to the Canadian Annual Information Form (“AIF”).

The projected reserves and revenues shown herein have also been prepared in accordance with our understanding of the requirements for a Competent Person’s 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 and forecast prices and costs. AIM guidelines also allow for the inclusion of Contingent and Prospective resource estimates.

As shown in Table 1 the Coastal Energy reserves have been presented in Proved (“1P”) and Proved + Probable (“2P”) formats using forecast economic assumptions as per TSX admission purposes. For the purposes of AIM admission, the Coastal Energy reserves have been presented in Proved + Probable + Possible (“3P”) formats, again using forecast economic assumptions. Detailed cash flow projections can be found in Appendix F. Also, after income tax cases have been prepared. Furthermore, for AIM admission purposes, both Contingent and Prospective resource volumes have been prepared. Economic projections were not prepared for the Contingent and Prospective resources; only their associated oil and gas volumes are presented herein.

The Society of Petroleum Engineers (“SPE”) approved updated revisions to its rules governing oil and gas reserves reporting in March 2007 with the adoption of the Petroleum Resources Management System (“PRMS”). The SPE-PRMS document was developed in collaboration with the World Petroleum Congress (“WPC”), the American Association of Petroleum Geologists (“AAPG”), and the Society of Petroleum Evaluation Engineers (“SPEE”). The SPE has also promulgated Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information that specifies requirements for the qualifications and independence of reserve estimators and auditors and accepted methods for the estimation of future reserves.

The estimated reserves and resources shown herein have been prepared with consideration for SPE, WPC, AAPG, and SPEE reserve classification definitions which comply with reserve and resource definitions as adopted by the Canadian Institute of Mining, Metallurgy & Petroleum (“CIM”) (Petroleum Society).

Reserve and resource definitions from the March 2007 SPE-PRMS document and reserve definitions from the Canadian Securities Administration NI 51-101 are included in Appendix E.

All cash flow data in this report has been expressed in United States (“US”) dollars.

Review of 2010 Offshore Activity

As of December 31, 2010, approximately 4.917 million barrels of gross oil have been produced from the wells in the Songkhla A and C Fields since late 2008. Coastal Energy estimated that approximately 2.802 million barrels of gross oil were produced in 2010, of which about 2.547 million barrels represented net sales volumes to Coastal Energy. The overall water-cut for the 2010 production was approximately

Coastal Energy Company Board of Directors April 11, 2011 Page Four


45.6% and the average gas-oil ratio was 147.5 standard cubic feet of gas per barrel of oil. All of the gas produced offshore has been used for fuel on the platforms. None of the produced gas has been sold. The produced water has been re-injected back into the producing formations to aid in the natural water drive in the formations. Songkhla A Field has produced about 4.401 million barrels of gross oil since coming on line in November 2008 with the majority of that, about 4.360 million barrels coming from the Main Oligocene fault block. The Eocene has produced about 41,000 barrels from two wells that are currently shut-in at Songkhla A Field. The Songkhla C Field has produced about 516,000 barrels of gross oil since coming on line in July 2010. Figure 5 and Table 7 illustrate the historical oil production volumes for the two fields. The Oligocene crude is 30° API oil with a pour point of 109°F and contains 33.8% paraffin, a maximum of 6% CO2, 10 ppm of H2S, and a gas-oil ratio (“GOR”) of about 140 scf per barrel. Oil is pumped from all wells using high-volume electric submersible pumps (“ESP”) and passes through surface production facilities and then into floating production tankers stationed near the platforms.

Songkhla A Field

In 2010 Coastal Energy installed larger pumps in the existing producing wells (SA01, SA03, SA04, and SA08) in the Main Oligocene fault block and upgraded the platform facilities in the field. There were no wells drilled into the Main Oligocene fault block in 2010.

Coastal Energy drilled four new wells just east of the Main fault block in 2010, which brings the total well count to twelve at Songkhla A Field. The 2010 drilling operations resulted in three new Oligocene fault block discoveries and one new Eocene fault block discovery. The SA09 well discovered a new Oligocene fault block (denoted as “SA09 Fault Block” in this report). The well also penetrated an existing Eocene fault block (denoted as “Fault Block A” in this report) that had previously been produced by the SA07 well. The Oligocene and Eocene formations were commingled and began producing in November 2010 from the SA09 wellbore. The SA11 well discovered both a new Oligocene fault block (denoted as “SA11 Fault Block” in this report) and a new Eocene fault block (denoted as “Fault Block B” in this report) in the field. The well began producing from the Eocene formation in December 2010 and will be commingled with the Oligocene in 2011. The SA12 well was drilled between the Songkhla Main field and the SA09 well and encountered water in the Oligocene formation. The well was then sidetracked as the SA12 ST and discovered a new Oligocene fault block (denoted as “SA12 ST Fault Block” in this report). The SA12 ST well was logged and completed in the Oligocene formation in late 2010 and began producing in mid-January 2011.

Songkhla C Field

Coastal Energy drilled eleven wells in the Songkhla C Field, previously called Bua Ban, during 2010. Three wells, SC05, SC06, and SC10 were drilled into a thicker Oligocene wedge formation located in the northwest portion of the field. These three wells began producing from the Oligocene formation in July 2010. Three other wells, the SC01, SC02, and SC03, were drilled into a thinner Oligocene section in the Main portion of the field just east of the wedge area and began producing from the Oligocene formation in July 2010. Two other wells in the Main portion of the field, the SC08 and SC09, will be converted to water injection wells because of their locations along the edge of the field. The SC11 well discovered a new Miocene sand at a depth of 4,396 feet true vertical depth (“TVD”) that lies above the Oligocene. This well was completed in the Miocene and began producing in October 2010. The SC04 and SC07 wells discovered a new Eocene formation that lies below the Oligocene. The SC04 began producing from the Eocene in August 2010 but was shut-in a month later and is scheduled for a fracture stimulation treatment in both the Eocene and Oligocene formations in early 2011. The SC07 well will also be fracture treated in just the Eocene formation in early 2011.

Coastal Energy Company Board of Directors April 11, 2011 Page Five


The SC09 well was drilled low on the Songkhla C structure and discovered a Lower Oligocene oil shale formation. A 60-foot core sample was taken in the shale section and analyzed for potential oil production. As a result of the core analysis Coastal Energy developed a plan to test a sand lens within the shale formation with a horizontal well. As a result of the core analysis of the sand lens Prospective resource volumes were added to the report this year for the Lower Oligocene oil shale formation at Songkhla C Field (see Table 4B).

Other Offshore Exploratory Areas

Coastal Energy drilled several exploratory wells during 2010 in the Songkhla B and Benjarong prospect areas. These prospects had been identified as containing Prospective and Contingent resources, respectively, in last year’s report.

Two wells, the B-1 and B-2, were drilled at Songkhla B and tested an Eocene/Oligocene structure located approximately 2.8 miles southwest of Songkhla A Field. The Songkhla B-1 was drilled to a depth of 8,912 feet TVD in the Eocene. The trap was breached and only logged about ten feet of net Lower Oligocene pay. The Eocene formation had numerous shows but was tight. The Songkhla B-2 was drilled to a depth of 8,823 feet TVD on a separate portion of the overall B structure and encountered seven feet of net Lower Oligocene pay. The B-2 was sidetracked down-dip looking for thickening sands off-structure but only confirmed another five feet of net Lower Oligocene pay (12 feet total). The results were considered too small for a stand-alone development, so the wells were plugged and abandoned. As a result of the drilling activity at the Songkhla B prospect, the Prospective resource volumes attributable to the Lower Oligocene have been dropped from this report as of December 31, 2010. Coastal Energy drilled three wells in 2010 to test the Benjarong prospect. The Benjarong A-01 well was drilled to evaluate Premier's 1991 Benjarong 1 well. The A-01 well was drilled to a depth of 10,565 feet TVD and encountered eight feet of net oil pay in the Lower Oligocene formation and eight feet of net oil pay in the Eocene formation. The well was then plugged back and sidetracked as the Benjarong A-01 ST1 well. The sidetrack was drilled to a depth of 10,352 feet TVD and logged six feet of net Eocene pay with 10% porosity. Coastal Energy drilled a third well, the Benjarong A-02, to test the Benjarong East prospect which was a large separate structure located approximately 2.2 miles northeast of the main Benjarong feature. The A-02 well was drilled to a depth of 11,127 feet TVD and encountered 30.5 feet of net Eocene pay with an average porosity of 15%. The A-01 ST1 well and the A-02 well were suspended in 2010 and subsequently both wells were fracture treated in the Eocene formation in early 2011. As of the date of this report, the sidetracked well had recovered a total of about 552 barrels of oil and 1,456 barrels of water. The A-02 well is still cleaning up and unloading fracture fluids. In light of the limited flow back performance of the two Benjarong wells from the Eocene formation, the Eocene resource volumes assigned to the Benjarong prospect will remain in the Contingent category pending further performance evaluations by Coastal Energy. Onshore, no wells were drilled during 2010 in either the Contingent or Prospective resource areas that have been evaluated in this report.

Review of Assets

A summary of the Coastal Energy licenses and working interests in Thailand appears in Table 2. The reserve and resource assets are located in both onshore and offshore licensed areas (Figure 1). The Coastal Energy offshore assets are located in Blocks G5/43 and G5/50 in the Songkhla Basin in the southern Gulf of Thailand (Figure 2). Coastal Energy operates and owns a 100% working interest position in both offshore blocks. Two offshore fields, the Songkhla A Field and the Songkhla C Field are currently producing in Block G5/43. Both fields are operated by Coastal Energy. The Songkhla A Field is located approximately 15 miles offshore in about 78 feet of water and began producing in late 2008. The Songkhla C Field is located approximately 10 miles offshore in about 60 feet of water and began

Coastal Energy Company Board of Directors April 11, 2011 Page Six


producing in July 2010. Several other prospects containing Contingent and Prospective resources in Blocks G5/43 and G5/50 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.

The Coastal Energy onshore gas assets are classified in this report as either Contingent or Prospective resources. There have been no Proved, Probable, or Possible reserve volumes assigned to the onshore asset areas in this report. The onshore resource assets are located in Block L27/43. This onshore license area, shown in Figure 3, is operated by APICO LLC (“APICO”) and is in the exploration phase of development. Coastal Energy owns 36.1% of APICO and is the largest shareholder in the company.

Geologic Description

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 4.

The Songkhla A Field was discovered in 1988 by the drilling of the Songkhla 1 well by Premier Oil Pacific Limited. Since late 2008 Coastal Energy has drilled twelve wells at Songkhla A Field and is currently producing oil from four Oligocene fault blocks and two Eocene fault blocks.

The Songkhla C 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 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 Songkhla C 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. The field was discovered with the drilling of the Bua Ban 1 well in 1990. In 2005 three more wells were drilled, the Bua Ban 2, the Bua Ban 2A, and the Bua Ban 3. The three wells helped to define the productive limits of the field. In 2010 Coastal Energy drilled eleven wells in the field. Three formations, the Miocene (located above the Oligocene), the Oligocene, and the Eocene (located below the Oligocene), were drilled, tested, and brought on line between July 2010 and October 2010.

Onshore Summary

Four wells have been drilled on the Dong Mun structure in Block L27/43. The Dong Mun 1 well was drilled and tested by Esso in 1990. The Dong Mun 2 well was also drilled in 1990 but was suspended and never tested. The Dong Mun 3 well was drilled in November 2007 and suspended in February 2008, with gas shows in the Jurassic and Triassic tight sands. The first two wells also had significant gas shows while drilling through the upper Phu Kheng sandstone series formations. The Dong Mun 1 well was extensively production tested in the deeper carbonates of the Pha Nok Khao formation.

Coastal Energy participated in drilling a fourth well on the Dong Mun structure, the Phu Kheng 1, in August 2009. The well was drilled to a total depth of 7,891 feet and tested the two shallower intervals of the Phu Kradung sandstone and one deeper zone in the Nam Phong sandstones. All three zones had good gas shows during drilling and logging operations; however, subsequent fracture stimulation treatments and testing of the Nam Phong sandstones failed as a result of equipment sealing problems. Work on this well was suspended in 2009 by the operator pending further testing of the well.

Coastal Energy Company Board of Directors April 11, 2011 Page Seven


The Southeast Dong Mun gas prospect is located in Block L27/43. This prospect was set up by seismic lines acquired in early 2006 by APICO and stratigraphic correlations with the wells drilled in the Dong Mun gas structure. This prospect has not been drilled yet.

Reserve and Resource Estimates

Reserve Estimates

As of December 31, 2010, Huddleston has assigned oil reserves to two offshore oil fields in Block G5/43, the Songkhla A Field and the Songkhla C Field. The offshore fields have been assigned Proved Developed Producing, Proved Developed Nonproducing, Proved Undeveloped, Probable Nonproducing, Probable Undeveloped, Possible Nonproducing, and Possible Undeveloped oil reserves.

The Proved Developed Producing reserve assignment were based on the extrapolation of historical production and sales data where there was sufficient data to indicate a performance trend. Projections for producing wells with limited production histories and Nonproducing and Undeveloped reserves were based on volumetric estimates and analogy to other wells producing from similar formations in the two fields.

Some Probable and Possible Nonproducing and Undeveloped reserve assignments appear as incremental recoverable volumes. These volumes will be recovered by one or more wells that are currently producing from the same formation and fault block or an undeveloped well that has been scheduled to be drilled into the same formation and fault block in the future. These incremental assignments were based on higher recovery factors and 2P and 3P volumetric calculations.

Reserve assignments prepared on the basis of volumetric calculations and analogy will be subject to a significantly greater degree of variation than those calculated on the basis of sustained performance history.

Table 3 shows that the total remaining recoverable 3P gross offshore oil volume is approximately 44.014 million barrels or about 39.501 million barrels net to Coastal Energy as of December 31, 2010. The remaining recoverable 1P or Proved gross oil volume is about 14.489 million barrels (or 13.458 million barrels net to Coastal Energy) and the remaining recoverable 2P or Proved + Probable gross oil volume is about 27.143 million barrels (or 24.756 million barrels net to Coastal Energy).

The gross and net remaining 3P oil reserve assignments for the wells and formations in Songkhla A and C Fields appears in Tables 6A through 6K. Each table shows the estimated gross and net remaining oil reserve volume by field, formation, fault block, reserve class, reserve type, and then by well.

The gross ultimate oil reserve and resource volumes for the various offshore oil formations and fields appear in Tables 4A through 4F. The oil volume assignments in these tables were based on volumetric calculations. The tables present the various parameters that were used in the volumetric calculations such as drainage area, net feet of pay, porosity, water saturation, and recovery factor by field, formation and reserve class.

Coastal Energy uses all of the offshore produced gas for fuel on the platforms. No future reserve or revenue value has been assigned any of the offshore gas volumes in this report.

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.

Coastal Energy Company Board of Directors April 11, 2011 Page Eight


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 8 for various license blocks and associated formations. Contingent resources were assigned to four offshore oil areas in Block G5/43 and to two onshore gas areas located in one onshore license area, Blocks L27/43.

Contingent resources were assigned to the Eocene and Oligocene formations at both Songkhla A and Songkhla C Fields as of December 31, 2010, because of development activities by Coastal Energy in the two fields during 2010. Coastal Energy plans further development in the various fault blocks and formations in both fields over the next few years.

Two additional offshore prospect areas; the Eocene formation at the Benjarong Oil Prospect and the Lower Oligocene formation at the Songkhla Southwest Oil Prospect were also assigned Contingent oil resources. As was discussed earlier, Coastal Energy drilled and fracture treated two Eocene wells at Benjarong in 2010 and as of the date of this report, both wells are cleaning up from the treatments and are currently being evaluated by Coastal Energy.

The Songkhla Southwest 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.

Coastal Energy supplied core data, well log interpretations, geologic maps, and seismic cross-sections for the Benjarong and the Songkhla Southwest prospect areas. The maps were planimetered to develop low, best, and high estimates for the Contingent oil resource assignments. The offshore Contingent oil resource assignments were based on volumetric calculations with consideration for analogy to the producing offshore Songkhla A and C Fields. Summaries of the volumetric parameters for the offshore oil formations appear in Tables 4A through 4F.

Contingent gas resources were assigned to the Pha Nok Khao and Phu Kheng formations in the Dong Mun Gas Field in the onshore license Block 27/43. The Pha Nok Khao formation in the Dong Mun gas prospect of Block L27/43 was drilled and tested by Esso in 1990. The Dong Mun 1 well tested 0.26 to 23.6 MMcf of gas per day in 1990 from the Pha Nok Khao carbonate formation. The Dong Mun 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. As was mentioned earlier, the Dong Mun 3 well was drilled in November 2007 and suspended in February 2008. 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 lack of a gas sales contract.

Coastal Energy participated in drilling a fourth well on the Dong Mun structure in Block L27/43, the Phu Kheng 1. The well was drilled to a total depth of 7,891 feet and tested the two shallower intervals of the Phu Kradung sandstone and one deeper zone in the Nam Phong sandstones in August 2009. All three zones had good gas shows during drilling and logging operations; however, subsequent fracture

Coastal Energy Company Board of Directors April 11, 2011 Page Nine


stimulation and testing of the Nam Phong sandstones failed as a result of sealing problems. The operator is currently waiting on a hydraulic workover unit to further test the well. The resource volumes for this field and formation were classified as Contingent because of the 2009 gas shows.

The onshore Contingent gas resource assignments were based on engineering and geological data supplied by APICO. The subsurface maps were planimetered to develop low, best, and high estimates for the Contingent gas resource assignments. The onshore Contingent gas resource assignments were based on volumetric calculations with consideration for analogy to the producing onshore Sinphuhorm Gas Field. Summaries of the volumetric parameters for the onshore gas formations appear in Table 5.

Prospective Resources – For AIM exchange purposes, the estimates for Prospective resources are summarized in Table 9 for various license blocks and associated formations. Prospective resources were assigned to several oil prospects located in two offshore license areas, Blocks G5/43 and G5/50, and to one gas prospect located in onshore license area Block L27/43.

The G5/43 offshore block contained numerous oil prospects in the Miocene, Oligocene, and Eocene formations. The oil prospects were developed by Coastal Energy as a result of the drilling operations at Songkhla C during 2010 together with updated interpretations of seismic data covering the Songkhla basin in the Gulf of Thailand. The prospects lie on strike with both the Songkhla A and Songkhla C Fields.

Coastal Energy supplied geologic maps and seismic cross-sections for the offshore oil prospect areas. The maps were planimetered to develop low, best, and high estimates for the offshore Prospective oil resource assignments. The offshore Prospective oil resource assignments in the Oligocene formations were based on volumetric calculations with consideration for analogy to the producing offshore Songkhla A and C Fields. Summaries of the volumetric parameters for the offshore oil formations appear in Tables 4A through 4F. The oil volumes for the offshore prospects were classified as Prospective because none of them have been drilled to date, but represent potentially recoverable volumes from undiscovered accumulations.

An onshore prospect, located in Block L27/43, was assigned Prospective gas resource volumes. The Pha Nok Khao formation in the Southeast Dong Mun gas prospect was set up by seismic lines acquired in early 2006 by APICO and stratigraphic correlations with the wells drilled in the Dong Mun gas prospect. The gas volumes for the Pha Nok Khao formation were classified as Prospective because of the lack of drilling activity on the prospect.

The onshore Prospective gas resource assignments were based on engineering and geological data supplied by APICO. The subsurface maps were planimetered to develop low, best, and high estimates for the Prospective gas resource assignments. The onshore Prospective gas resource assignments were based on volumetric calculations with consideration for analogy to the producing Pha Nok Khao formation at the offset onshore Sinphuhorm Gas Field. Summaries of the volumetric parameters for the onshore gas formations appear in Table 5.

The Contingent and Prospective resource volumes contained in this report have no economic value attributable to them.

Economic Analysis

Forecast Price Cases

At the request of Coastal Energy this report version contains future net reserves and revenue projections that have been generated using two different forecast price cases and two different effective dates. One uses prices and an effective date of December 31, 2010 (Appendix F) and the other uses prices and an

Coastal Energy Company Board of Directors April 11, 2011 Page Ten


effective date of April 1, 2011. Reserves and revenues based on constant prices have not been included in this report.

December 31, 2010 Effective Date – Projected prices for this forecasted price case were based on a projection of Brent crude oil as shown in Table 10A. The Brent crude oil price projection as of January 1, 2011 was taken from the Gilbert Lausten Jung (“GLJ”) Petroleum Consultants website (www.gljpc.com). GLJ projected prices through 2020, then applied a 2% per year escalation for the life of the properties. It should be noted, however, that the Huddleston-projected oil reserves are projected to deplete at the two offshore oil fields during 2018. Price adjustments for the forecast price case were determined for the oil reserves using data supplied by Coastal Energy. Table 10A summarizes the forecast price assumptions that were used to generate the future revenues contained in this report.

The forecasted prices for the offshore crude oil were determined by first calculating the differential between posted Brent crude prices versus posted Dubai crude oil prices for 2010. The calculated 2010 differential of -$1.49 per barrel was then applied to the starting January 1, 2010 GLJ price for Brent of $88.50 per barrel to yield a price of $87.01 per barrel. Additional purchaser discounts were then applied which further reduced the starting January 1, 2011 forecasted offshore oil price to $82.76 per barrel. The Dubai differential and purchaser’s discount were then applied to the January 1, 2011 GLJ Brent price projection to determine the offshore forecasted oil prices for the next ten years, throughout the life of the assigned offshore oil reserves. The highest price for the offshore crude was $95.50 per barrel in 2018 and the weighted average forecasted price for the offshore oil was $84.77 per barrel (see Appendix F).

Graphical summaries of the estimated future net production for the offshore properties are shown in Figure 6 for the December 31, 2010 effective date.

April 1, 2011 Effective Date – Projected prices for this forecasted price case were based on a projection of Brent crude oil as shown in Table 10B. The Brent crude oil price projection as of April 1, 2011 was taken from the Gilbert Lausten Jung (“GLJ”) Petroleum Consultants website (www.gljpc.com). GLJ projected prices through 2020, then applied a 2% per year escalation for the life of the properties. It should be noted, however, that the Huddleston-projected oil reserves are projected to deplete at the two offshore oil fields during 2018. Price adjustments for the forecast price case were determined for the oil reserves using data supplied by Coastal Energy. Table 10B summarizes the forecast price assumptions that were used to generate the future revenues contained in this report.

The forecasted prices for the offshore crude oil were determined by first calculating the differential between posted Brent crude prices versus posted Dubai crude oil prices for 2010. The calculated 2010 differential of -$1.49 per barrel was then applied to the starting April 1, 2011 GLJ price for Brent of $115.00 per barrel to yield a price of $113.51 per barrel. Additional purchaser discounts were then applied which further reduced the starting April 1, 2011 forecasted offshore oil price to $109.26 per barrel. The Dubai differential and purchaser’s discount were then applied to the April 1, 2011 GLJ Brent price projection to determine the offshore forecasted oil prices for the next ten years, throughout the life of the assigned offshore oil reserves. The highest price for the offshore crude was $109.26 per barrel in 2011 and the weighted average forecasted price for the offshore oil was $99.23 per barrel.

Operating Expenses

The monthly lease operating expenses for the offshore oil fields were supplied by Coastal Energy.

Tables 11 and 12 summarize the annual projected fixed operating expenses for the forecast price case by reserve category for the 100% gross ownership position and the Coastal Energy net ownership position, respectively. The gross fixed operating expenses for the offshore Songkhla A Field was estimated to be $36,500,000 per year or about $3,041,667 per month. The gross fixed operating expenses for the offshore Songkhla C Field were estimated to be $18,200,000 per year or about $1,516,667 per month.

Coastal Energy Company Board of Directors April 11, 2011 Page Eleven


Huddleston allocated the fixed operating expenses on a reserve category basis in the cash flow model. As is shown in Tables 11 and 12, the Proved reserve categories were burdened with a larger proportional share of allocated fixed operating expenses, followed by Probable, then Possible reserve categories.

Fixed 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 for the offshore oil fields were supplied by Coastal Energy. 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.

Table 13 summarizes the annual projected capital expenditures for the forecast price case by reserve category for the 100% gross ownership position. Tables 14 and 15 summarize the annual projected capital expenditures for the forecast price case by field, then by reserve category, for the 100% gross ownership position and the Coastal Energy net ownership position, respectively.

Coastal Energy plans to drill additional oil production wells in both the Eocene and the Oligocene fault blocks at Songkhla A Field beginning in early 2011.

At Songkhla C Field Coastal Energy plans to fracture treat the Eocene wells in early 2011 and drill vertical and horizontal oil production and water injection wells in both the Eocene and Oligocene formations beginning in 2011.

Abandonment expenses, both offshore and onshore, have been assigned to the producing and injection wells and field facilities in the year after the last production well depletes.

Capital expenditures for the forecast price case were immediately escalated at 2% per year for the life of the properties.

Income Tax Considerations

Tables 16A and 16B summarize the before and after tax revenues attributable to the offshore reserves for the December 31, 2010 and the April 1, 2011 forecast price cases, respectively. The net revenues are reported before and after income taxes and have been discounted using rates of 0%, 5%, 10%, 15%, and 20%. The tax rates for the 1P, 2P and 3P reserve cases were supplied by Coastal Energy and include the effects of the Thai Petroleum Income Tax and Special Remuneratory Benefit (where applicable) for each production scenario.

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 and resource 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 volumes.

The estimated reserve and resource volumes shown herein are substantially based on volumetric calculations and may be subject to a significant level of revision as additional drilling operations are

Coastal Energy Company Board of Directors April 11, 2011 Page Twelve


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 Nonproducing, 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 reserve and resource volumes shown herein may be affected by a variety of factors including the availability of capital, the results of previous operations, the timing of facilities construction, market conditions, fluctuations in foreign currency exchange rates, and unforeseen political risks.

THE ESTIMATED REVENUES AND PRESENT VALUE OF THESE REVENUES FOR EITHER EFFECTIVE DATE OR EITHER PRICING FORECAST 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, lease operating expenses, capital expenditures, 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,

John P. Krawtz, P.E. Texas Registered Engineering Firm F-1024

JPK:klh

FIGURES 1 – 6

Coastal Energy Thailand AssetsFIGURE 1

Map of Thailand Onshore and Offshore License Areas

Source: Coastal Energy Company

Coastal Energy Thailand AssetsFIGURE 2

Map of Thailand Offshore Fields and License Areas

Source: Coastal Energy Company

FIGURE 3Map of Thailand Onshore License Area and Prospect Areas

SinphuhormGas Field

Phu Kheng

Dong Mun

L27/43 SE Dong Mun

Nam PhongGas Field andPower Plant

K 1000

Source: APICO, LLC

Km 1000

FIGURE 4Schematic Cross Section of Songkhla Basin Area

W EBua Ban-1 and Benjarong-1Oil in Lw Oligocene and Eocene

Songkhla-1 and Songkhla SW-1Oil in Lw Oligocene and Eocene

Western Fault Terrace Basin Centre

Oil in Lw Oligocene and Eocene O O goce e a d oce eEastern flank

untested fan playsBasin centre

untested stratigraphic plays

1

Miocene

1

Up Oligocene

0 5K

2

TWTEocene Lw Oligocene

p g

Fluvial sandstones Lacustrine source rocks Fluvial shales

0 5Km 3

Source: Coastal Energy Company/Auldana Advisors

Fan sandstones Lacustrine seal shales Basement & PreT

FIGURE 5

Songkhla C Field

Songkhla A Field

10,000

100,000

bbl/d

SONGKHLA A & C FIELDS - OFFSHORE THAILANDHISTORICAL OIL PRODUCTION RATES

Songkhla C Field

Songkhla A Field

Total Daily Gross Oil Production

Huddleston & Co., Inc.Texas Registered Engineering Firm F-1024a

100

1,000

Nov-0

8

Dec-0

8

Jan-

09

Feb-

09

Mar-0

9

Apr-0

9

May-0

9

Jun-

09

Jul-0

9

Aug-

09

Sep-

09

Oct-0

9

Nov-0

9

Dec-0

9

Jan-

10

Feb-

10

Mar-1

0

Apr-1

0

May-1

0

Jun-

10

Jul-1

0

Aug-

10

Sep-

10

Oct-1

0

Nov-1

0

Dec-1

0

DATE

FORECAST PRICE CASE

FIGURE 6Coastal Energy Company - Thailand Development

Graphical Summaries of Estimated Future Net Oil Production - Offshore Properties

As of December 31, 2010

100

1,000

10,000

100,000

11 12 13 14 15 16 17 18 19 20

RA

TE, B

O/D

AY

YEAR

TOTAL - SONGKHLA A & SONGKHLA C FIELDS

PROVED

PROBABLE

POSSIBLE


100

1,000

10,000

100,000

11 12 13 14 15 16 17 18 19 20

RA

TE, B

O/D

AY

YEAR

SONGKHLA A FIELD

PROVED

PROBABLE

POSSIBLE

100

1,000

10,000

100,000

11 12 13 14 15 16 17 18 19 20

RA

TE, B

O/D

AY

YEAR

SONGKHLA C FIELD

PROVED

PROBABLE

POSSIBLE


TABLES 2 – 22

LicenseNumber Operator

Coastal Interest

(%)Status

LicenseExpiration

Date

LicenseArea (Km2)

Comments

G5/43 Offshore Thailand

Petroleum Concession Agreement (PCA) No. 7/2546/64

NuCoastal (Thailand)

Limited

100% Production and

Under Development

July 16, 2029 5,021 Songkhla A Field began producing in November 2008. Songkhla C (Bua Ban) Field began producing in July 2010

G5/50 Offshore Thailand

Petroleum Concession Agreement (PCA) No. 9/2550/85

NuCoastal (Thailand)

Limited

100% Exploration December 18, 2013 554 Located in the Ko Kra Basin within the northern boundaries of Block G5/43

L 27/43 Onshore Thailand

9/2546/63 APICO 36.1% Exploration September 24, 2012 3,948 Located southeast of the producing onshore Sinphuhorm Gas Field

Note: Coastal Energy relinquished their ownership in onshore Block L13/48 on December 7, 2010.

Asset

TABLE 2SUMMARY OF COASTAL ENERGY LICENSES AND WORKING INTERESTS - THAILAND



License Area ProvedProved

+Probable

Proved +

Probable +

Possible

ProvedProved

+Probable

Proved +

Probable +

Possible

ProvedProved

+Probable

Proved +

Probable +

Possible

Operator

Oil (Mbbl) Offshore Block G5/43:

Songkhla A Field - Eocene 513 4,121 8,749 513 4,121 8,749 471 3,699 7,747 NuCoastal Songkhla A Field - Oligocene 12,093 17,278 23,575 12,093 17,278 23,575 11,250 15,878 21,380 NuCoastalSubtotal Songkhla A Field 12,606 21,399 32,324 12,606 21,399 32,324 11,720 19,577 29,127

Songkhla C Field - Eocene 58 1,258 1,716 58 1,258 1,716 53 1,118 1,514 NuCoastal Songkhla C Field - Miocene 106 381 581 106 381 581 97 341 514 NuCoastal Songkhla C Field - Oligocene Main 119 2,275 6,423 119 2,275 6,423 110 2,039 5,679 NuCoastal Songkhla C Field - Oligocene Wedge 1,600 1,830 2,970 1,600 1,830 2,970 1,478 1,680 2,667 NuCoastalSubtotal Songkhla C Field 1,883 5,744 11,690 1,883 5,744 11,690 1,737 5,178 10,374

Subtotal Offshore Block G5/43 14,489 27,143 44,014 14,489 27,143 44,014 13,458 24,756 39,501

Total for Oil (Mbbl) 14,489 27,143 44,014 14,489 27,143 44,014 13,458 24,756 39,501

Source: Huddleston & Co., Inc.

TABLE 3

SUMMARY OF REMAINING RESERVESCoastal Energy Gross , Working, and Net Interest Remaining Reserves


100% Gross Working Interest Net to Coastal Energy


Net Water Oil Oil In-Place UltimateLicense Fault Depth Estimate Reserve Reserve Primary Area Pay Porosity Sat FVF Reserves Rec Recoverable Oil

Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla A Eocene A 7400 Low 1P PDP,PDNP,PUD Oil 450 64.5 18.4% 39.0% 1.14 22,180 1.5% 338

7400 Best 2P Undeveloped Oil 450 64.5 18.4% 39.0% 1.14 22,180 12.3% 2,7387400 High 3P Undeveloped Oil 450 64.5 18.4% 39.0% 1.14 22,180 30% 6,654

Block G5/43 Offshore Songkhla A Eocene B 7300 Low 1P PDNP, PUD Oil 190 49.0 18.4% 39.0% 1.14 7,116 3.0% 2157300 Best 2P Undeveloped Oil 190 49.0 18.4% 39.0% 1.14 7,116 20% 1,4237300 High 3P Undeveloped Oil 190 49.0 18.4% 39.0% 1.14 7,116 30% 2,135

Block G5/43 Offshore Songkhla A Eocene C 7350 Low Contingent --- Oil 39 17.8 18.4% 39.0% 1.14 531 10% 537350 Best Contingent --- Oil 39 17.8 18.4% 39.0% 1.14 531 20% 1067350 High Contingent --- Oil 39 17.8 18.4% 39.0% 1.14 531 30% 159

Block G5/43 Offshore Songkhla A Oligocene Main 7300 Low 1P PDP, PDNP Oil 520 89.7 19.0% 30.0% 1.18 40,794 24.3% 9,9107300 Best 2P Undeveloped Oil 520 89.7 19.0% 30.0% 1.18 40,794 30% 12,2387300 High 3P Undeveloped Oil 520 89.7 19.0% 30.0% 1.18 40,794 40% 16,318

Block G5/43 Offshore Songkhla A Oligocene SA09 7300 Low 1P PDP, PUD Oil 272 73.1 19.0% 44.6% 1.14 14,306 29.2% 4,1847300 Best 2P Undeveloped Oil 272 73.1 19.0% 44.6% 1.14 14,306 38.3% 5,4847300 High 3P Undeveloped Oil 272 73.1 19.0% 44.6% 1.14 14,306 40% 5,722

Block G5/43 Offshore Songkhla A Oligocene SA12 ST 7000 Low 1P PDP, PUD Oil 315 81.8 20.5% 47.9% 1.14 18,817 12.8% 2,4007000 Best 2P Undeveloped Oil 315 81.8 20.5% 47.9% 1.14 18,817 20% 3,7637000 High 3P Undeveloped Oil 315 81.8 20.5% 47.9% 1.14 18,817 30% 5,645

Block G5/43 Offshore Songkhla A Oligocene SA11 7100 Low 1P Undeveloped Oil 59 23.9 18.0% 44.0% 1.14 971 0% 07100 Best 2P Undeveloped Oil 59 23.9 18.0% 44.0% 1.14 971 20% 1947100 High 3P Undeveloped Oil 59 23.9 18.0% 44.0% 1.14 971 30% 291

Block G5/43 Offshore Songkhla A Oligocene SA11 7100 Low Contingent --- Oil 1,357 50.0 18.0% 44.0% 1.14 46,748 10% 4,6757100 Best Contingent --- Oil 1,357 50.0 18.0% 44.0% 1.14 46,748 20% 9,3507100 High Contingent --- Oil 1,357 50.0 18.0% 44.0% 1.14 46,748 30% 14,024


Note: Offshore gas volumes will be used for lease purposes and do not contribute to reported reserve volumes, resource volumes, or revenues in this report

TABLE 4A

SUMMARY OF VOLUMETRIC PARAMETERS for OFFSHORE OIL FORMATIONS --- SONGKHLA A OIL FIELD


Huddleston & Co., Inc.Texas Registered Engineering Firm F‐1024a


Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla C Eocene Main 7950 Low 1P PDNP Oil 40 100.0 8.0% 40.0% 1.30 1,145 5.2% 59

(Bua Ban) 7950 Best 2P Prob NP Oil 240 100.0 8.0% 40.0% 1.30 4,583 18.3% 1,2597950 High 3P Poss NP Oil 240 100.0 8.0% 40.0% 1.30 4,583 25% 1,717

Block G5/43 Offshore Songkhla C Eocene Main 7950 Low Contingent --- Oil 2,580 100.0 8.0% 40.0% 1.30 76,195 10% 7,390 (Bua Ban) 7950 Best Contingent --- Oil 2,580 100.0 8.0% 40.0% 1.30 76,195 20% 14,781

7950 High Contingent --- Oil 2,580 100.0 8.0% 40.0% 1.30 76,195 30% 22,171

Block G5/43 Offshore Songkhla C Miocene C11 Area 3400 Low 1P PDP Oil 52.8 35.0 27.0% 40.0% 1.30 2,004 6.3% 126 (Bua Ban) M100 & 3400 Best 2P Incremental Oil 52.8 35.0 27.0% 40.0% 1.30 2,004 20% 401

Combined 3400 High 3P Incremental Oil 52.8 35.0 27.0% 40.0% 1.30 2,004 30% 601

Block G5/43 Offshore Songkhla C Miocene C03 Area 3600 Low Contingent --- Oil 10.1 25.0 27.0% 40.0% 1.30 244 10% 24 (Bua Ban) M500 Only 3600 Best Contingent --- Oil 10.1 25.0 27.0% 40.0% 1.30 244 20% 49

3600 High Contingent --- Oil 10.1 25.0 27.0% 40.0% 1.30 244 30% 73

Block G5/43 Offshore Songkhla C Oligocene Wedge 6875 Low 1P PDP,PDNP Oil 353 65.7 12.6% 39.6% 1.20 11,405 18% 2,051 (Bua Ban) 6875 Best 2P Undeveloped Oil 353 65.7 12.6% 39.6% 1.20 11,405 20% 2,281

6875 High 3P Undeveloped Oil 353 65.7 12.6% 39.6% 1.20 11,405 30% 3,421

Block G5/43 Offshore Songkhla C Oligocene Main Area 8000 Low 1P PDP,PDNP Oil 1,681 26.0 12.6% 39.6% 1.20 21,545 0.7% 161 (Bua Ban) 8000 Best 2P Undeveloped Oil 1,681 26.0 12.6% 39.6% 1.20 21,545 10.7% 2,315

8000 High 3P Undeveloped Oil 1,681 26.0 12.6% 39.6% 1.20 21,545 30% 6,464

Block G5/43 Offshore Songkhla C Oligocene Main 8000 Low Prospective --- Oil n/a 6.0 5.0% n/a n/a n/a n/a 300 (Bua Ban) Shale 8000 Best Prospective --- Oil n/a 6.0 5.0% n/a n/a n/a n/a 600

8000 Best Prospective --- Oil n/a 6.0 5.0% n/a n/a n/a n/a 1,200




TABLE 4B

SUMMARY OF VOLUMETRIC PARAMETERS for OFFSHORE OIL FORMATIONS --- SONGKHLA C (BUA BAN) OIL FIELD



Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla Oligocene 7500 Low Contingent --- Oil 923 22 7% 45% 1.20 4,985 10% 499

Southwest 7500 Best Contingent --- Oil 923 29 9% 35% 1.20 10,123 15% 1,5197500 High Contingent --- Oil 923 36 11% 25% 1.20 17,821 20% 3,564

Block G5/43 Offshore Benjarong Eocene 10300 Low Contingent --- Oil 3,090 45 8% 45% 1.40 34,130 10% 3,41310300 Best Contingent --- Oil 3,090 45 10% 35% 1.40 50,419 15% 7,56310300 High Contingent --- Oil 3,090 45 15% 25% 1.40 87,263 20% 17,453

Block G5/43 Offshore Songkhla B Miocene M500 3500 Low Prospective --- Oil 1,328 40 25% 40% 1.30 47,551 10% 4,7553500 Best Prospective --- Oil 1,328 40 25% 40% 1.30 47,551 15% 7,1333500 High Prospective --- Oil 1,328 40 25% 40% 1.30 47,551 30% 14,265

Miocene M500 3500 Low Prospective --- Oil 180 25 25% 40% 1.30 4,028 10% 4033500 Best Prospective --- Oil 180 25 25% 40% 1.30 4,028 15% 6043500 High Prospective --- Oil 180 25 25% 40% 1.30 4,028 30% 1,208

Miocene M100 2630 Low Prospective --- Oil 1,168 40 25% 40% 1.30 41,822 10% 4,1822630 Best Prospective --- Oil 1,168 40 25% 40% 1.30 41,822 15% 6,2732630 High Prospective --- Oil 1,168 40 25% 40% 1.30 41,822 30% 12,546

Miocene M100 2630 Low Prospective --- Oil 95 25 25% 40% 1.30 2,126 10% 2132630 Best Prospective --- Oil 95 25 25% 40% 1.30 2,126 15% 3192630 High Prospective --- Oil 95 25 25% 40% 1.30 2,126 30% 638

Block G5/43 Offshore Songkhla C Miocene M500 2600 Low Prospective --- Oil 356 40 25% 40% 1.30 12,747 10% 1,2752600 Best Prospective --- Oil 356 40 25% 40% 1.30 12,747 15% 1,9122600 High Prospective --- Oil 356 40 25% 40% 1.30 12,747 30% 3,824

Miocene M100 2400 Low Prospective --- Oil 545 40 25% 40% 1.30 19,514 10% 1,9512400 Best Prospective --- Oil 545 40 25% 40% 1.30 19,514 15% 2,9272400 High Prospective --- Oil 545 40 25% 40% 1.30 19,514 30% 5,854

Block G5/43 Offshore Songkhla D Miocene M500 3175 Low Prospective --- Oil 457 40 25% 40% 1.30 16,363 10% 1,6363175 Best Prospective --- Oil 457 40 25% 40% 1.30 16,363 15% 2,4553175 High Prospective --- Oil 457 40 25% 40% 1.30 16,363 30% 4,909


Block G5/43 Offshore Songkhla E Miocene M500 3370 Low Prospective --- Oil 217 40 25% 40% 1.30 7,770 10% 7773370 Best Prospective --- Oil 217 40 25% 40% 1.30 7,770 15% 1,1653370 High Prospective --- Oil 217 40 25% 40% 1.30 7,770 30% 2,331





TABLE 4C

SUMMARY OF VOLUMETRIC PARAMETERS for OFFSHORE OIL FORMATIONS --- OTHER OIL FIELDS



Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla F Miocene M500 3280 Low Prospective --- Oil 104 40 25% 40% 1.30 3,724 10% 372

3280 Best Prospective --- Oil 104 40 25% 40% 1.30 3,724 15% 5593280 High Prospective --- Oil 104 40 25% 40% 1.30 3,724 30% 1,117


Block G5/43 Offshore Songkhla G Miocene M500 3370 Low Prospective --- Oil 193 40 25% 40% 1.30 6,911 10% 6913370 Best Prospective --- Oil 193 40 25% 40% 1.30 6,911 15% 1,0373370 High Prospective --- Oil 193 40 25% 40% 1.30 6,911 30% 2,073


Block G5/43 Offshore Songkhla H Miocene 3370 Low Prospective --- Oil 154 30 25% 40% 1.30 4,136 10% 4143370 Best Prospective --- Oil 154 30 25% 40% 1.30 4,136 15% 6203370 High Prospective --- Oil 154 30 25% 40% 1.30 4,136 30% 1,241

Block G5/43 Offshore Songkhla I Miocene 3340 Low Prospective --- Oil 365 40 25% 40% 1.30 13,069 10% 1,3073340 Best Prospective --- Oil 365 40 25% 40% 1.30 13,069 15% 1,9603340 High Prospective --- Oil 365 40 25% 40% 1.30 13,069 30% 3,921

Block G5/43 Offshore Songkhla J Miocene M500 2840 Low Prospective --- Oil 166 40 25% 40% 1.30 5,944 10% 5942840 Best Prospective --- Oil 166 40 25% 40% 1.30 5,944 15% 8922840 High Prospective --- Oil 166 40 25% 40% 1.30 5,944 30% 1,783

Miocene M100 2510 Low Prospective --- Oil 56 40 25% 40% 1.30 2,005 10% 2012510 Best Prospective --- Oil 56 40 25% 40% 1.30 2,005 15% 3012510 High Prospective --- Oil 56 40 25% 40% 1.30 2,005 30% 602


Block G5/43 Offshore Songkhla K Miocene M100 2775 Low Prospective --- Oil 207 40 25% 40% 1.30 7,412 10% 7412775 Best Prospective --- Oil 207 40 25% 40% 1.30 7,412 15% 1,1122775 High Prospective --- Oil 207 40 25% 40% 1.30 7,412 30% 2,224

Block G5/43 Offshore Songkhla L Miocene M100 2640 Low Prospective --- Oil 97 40 25% 40% 1.30 3,473 10% 3472640 Best Prospective --- Oil 97 40 25% 40% 1.30 3,473 15% 5212640 High Prospective --- Oil 97 40 25% 40% 1.30 3,473 30% 1,042

Block G5/43 Offshore Songkhla M Miocene M100 2640 Low Prospective --- Oil 137 40 25% 40% 1.30 4,905 10% 4912640 Best Prospective --- Oil 137 40 25% 40% 1.30 4,905 15% 7362640 High Prospective --- Oil 137 40 25% 40% 1.30 4,905 30% 1,472



TABLE 4D





Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla D Oliogocene 7080 Low Prospective --- Oil 561 50 15% 40% 1.30 15,065 10% 1,507

Bua Ban 7080 Best Prospective --- Oil 561 50 15% 40% 1.30 15,065 20% 3,013 North A 7080 High Prospective --- Oil 561 50 15% 40% 1.30 15,065 30% 4,520

Block G5/43 Offshore Songkhla E Oliogocene 6200 Low Prospective --- Oil 634 50 15% 40% 1.30 17,026 10% 1,703 Bua Ban 6200 Best Prospective --- Oil 634 50 15% 40% 1.30 17,026 20% 3,405 North B 6200 High Prospective --- Oil 634 50 15% 40% 1.30 17,026 30% 5,108

Block G5/43 Offshore Bua Ban Oliogocene 5100 Low Prospective --- Oil 1,345 50 15% 40% 1.30 36,119 10% 3,612 North C 5100 Best Prospective --- Oil 1,345 50 15% 40% 1.30 36,119 20% 7,224

5100 High Prospective --- Oil 1,345 50 15% 40% 1.30 36,119 30% 10,836

Block G5/43 Offshore Bua Ban Oliogocene 6470 Low Prospective --- Oil 175 50 15% 40% 1.30 4,700 10% 470 North D 6470 Best Prospective --- Oil 175 50 15% 40% 1.30 4,700 20% 940

6470 High Prospective --- Oil 175 50 15% 40% 1.30 4,700 30% 1,410

Block G5/43 Offshore Bua Ban Oliogocene 7080 Low Prospective --- Oil 38 50 15% 40% 1.30 1,020 10% 102 North D 7080 Best Prospective --- Oil 38 50 15% 40% 1.30 1,020 20% 204 Extension 7080 High Prospective --- Oil 38 50 15% 40% 1.30 1,020 30% 306

Block G5/43 Offshore Bua Ban Oliogocene 5500 Low Prospective --- Oil 280 50 15% 40% 1.30 7,519 10% 752 North E 5500 Best Prospective --- Oil 280 50 15% 40% 1.30 7,519 20% 1,504


Block G5/50 Offshore Central A Oliogocene 7500 Low Prospective --- Oil 198 15 12% 40% 1.20 1,382 10% 1387500 Best Prospective --- Oil 504 33 18% 30% 1.20 13,548 20% 2,7107500 High Prospective --- Oil 875 55 22% 20% 1.20 54,759 30% 16,428

Block G5/50 Offshore Central B Oliogocene 7500 Low Prospective --- Oil 239 8 12% 40% 1.20 890 10% 897500 Best Prospective --- Oil 791 20 18% 30% 1.20 12,887 20% 2,5777500 High Prospective --- Oil 1,085 35 22% 20% 1.20 43,209 30% 12,963

Block G5/50 Offshore Central C Oliogocene 7500 Low Prospective --- Oil 116 8 12% 40% 1.20 432 10% 437500 Best Prospective --- Oil 251 15 18% 30% 1.20 3,067 20% 6137500 High Prospective --- Oil 661 32 22% 20% 1.20 24,068 30% 7,220

Block G5/50 Offshore Central D Oliogocene 7500 Low Prospective --- Oil 115 13 12% 40% 1.20 696 10% 707500 Best Prospective --- Oil 232 29 18% 30% 1.20 5,481 20% 1,0967500 High Prospective --- Oil 397 52 22% 20% 1.20 23,490 30% 7,047

Block G5/50 Offshore Central E Oliogocene 7500 Low Prospective --- Oil 37 12 12% 40% 1.20 207 10% 217500 Best Prospective --- Oil 128 27 18% 30% 1.20 2,815 20% 5637500 High Prospective --- Oil 211 50 22% 20% 1.20 12,004 30% 3,601



TABLE 4E





Area Location Field Formation Block (ft) Type Class Type Product (ac) (ft) (%) (%) (rb/stb) (Mbbl) Factor (Mbbl)Block G5/43 Offshore Songkhla D Eocene 7950 Low Prospective --- Oil 645 100 15% 40% 1.10 40,941 5% 2,047

7950 Best Prospective --- Oil 645 100 15% 40% 1.10 40,941 10% 4,0947950 High Prospective --- Oil 645 100 15% 40% 1.10 40,941 30% 12,282

Block G5/43 Offshore Songkhla E Eocene 7800 Low Prospective --- Oil 554 100 17% 40% 1.10 39,854 5% 1,9937800 Best Prospective --- Oil 554 100 17% 40% 1.10 39,854 10% 3,9857800 High Prospective --- Oil 554 100 17% 40% 1.10 39,854 30% 11,956

Block G5/43 Offshore Bua Ban Eocene 5800 Low Prospective --- Oil 1,509 100 18% 40% 1.10 114,940 10% 11,494 Terrace C 5800 Best Prospective --- Oil 1,509 100 18% 40% 1.10 114,940 20% 22,988


Block G5/43 Offshore Bua Ban Eocene 5550 Low Prospective --- Oil 512 100 18% 40% 1.10 38,999 10% 3,900 Terrace E 5550 Best Prospective --- Oil 512 100 18% 40% 1.10 38,999 20% 7,800


Block G5/43 Offshore Bua Ban Eocene 5700 Low Prospective --- Oil 749 100 18% 40% 1.10 57,051 10% 5,705 Terrace F 5700 Best Prospective --- Oil 749 100 18% 40% 1.10 57,051 20% 11,410


Block G5/43 Offshore Bua Ban Eocene 5775 Low Prospective --- Oil 432 100 18% 40% 1.10 32,905 10% 3,291 Terrace G 5775 Best Prospective --- Oil 432 100 18% 40% 1.10 32,905 20% 6,581


Block G5/43 Offshore Benjarong Eocene 4500 Low Prospective --- Oil 1,370 100 20% 40% 1.10 115,947 10% 11,595 South 4500 Best Prospective --- Oil 1,370 100 20% 40% 1.10 115,947 20% 23,189




TABLE 4F




Reserve or Net Water CondensateLicense Depth Estimate Resource Reserve Primary Acres Pay Porosity Sat Temp Pressure Gas Yield GOR Oil/Cond Gas Rec Oil/Cond Gas

Area Location Field Formation (ft) / (m) Type Class Type Product (ac) (ft) (%) (%) (oF) (psi) z-Factor (bbl/MMcf) (scf/bbl) (Mbbl) (Bcf) Factor (Mbbl) (Bcf)

L27/43 Onshore Dong Mun Pha Nok Khao 9000ft/2743m Low Contingent --- Gas 2,133 239.9 3.0% 25% 192.4 5,993 1.0832 0 n/a 0 150.9 50% 0 75.49180ft/2798m Best Contingent --- Gas 2,807 291.2 3.0% 25% 192.4 5,993 1.0832 0 n/a 0 241.1 60% 0 144.79360ft/2853m High Contingent --- Gas 6,937 277.7 3.0% 25% 192.4 5,993 1.0832 0 n/a 0 568.3 75% 0 426.3

L27/43 Onshore Dong Mun Phu Kheng: 1800ft/549m Low Contingent --- Gas 115,858 67.6 3.0% 40% 192.4 4,195 0.904 0 n/a 0 1,700.0 50% 0 850.0 3 Sandstone to Best Contingent --- Gas 115,858 67.6 4.0% 40% 192.4 4,195 0.904 0 n/a 0 2,266.7 60% 0 1,360.0 Reservoirs 7700ft/2347m High Contingent --- Gas 115,858 67.6 5.0% 40% 192.4 4,195 0.904 0 n/a 0 2,833.4 75% 0 2,125.1

L27/43 Onshore SE Dong Mun Pha Nok Khao 9000ft/2742m Low Prospective --- Gas 2,436 62 3.0% 25% 192.4 5,000 1.006 0 n/a 0 40.1 50% 0 20.09000ft/2742m Best Prospective --- Gas 4,935 97.9 3.0% 25% 192.4 5,000 1.006 0 n/a 0 128.1 60% 0 76.99000ft/2742m High Prospective --- Gas 11,911 137.2 4.0% 25% 192.4 5,000 1.006 0 n/a 0 577.7 75% 0 433.2


TABLE 5

SUMMARY OF VOLUMETRIC PARAMETERS for ONSHORE GAS FORMATIONS


In-Place Reserves Recoverable Reserves


Number Ultimateof Recovery

Reserve Reserve Producing Factor Gross NetClass Type Wells (%) (bbl) (bbl) Comment

Developed Producing 1 0 0 SA09 well - commingled with Oligocene

Proved Nonproducing 0 1.5% 0 0 SA07 well - shut-in for sidetrack operations in 2011

Undeveloped 2 300,000 274,940 Drill 2 PUD wells - SA07 ST & SA0A Loc

1P 300,000 274,940 Proved

Probable Undeveloped 8 12.3% 2,400,000 2,148,210

Drill 8 Prob Und wells - SA0E Loc, SA0F Loc, & 6 other wells at 300,000 BO per well based on higher recovery factor & 2P volumetrics

2P 2,700,000 2,423,150 Proved + Probable

Possible Undeveloped 11 30% 3,916,000 3,428,110

Drill 3 Poss Und wells at 300,000 BO per well plus an additional Poss incremental recovery of 3,016,000 BO based on 30% recovery factor & 3P volumetrics

3P 6,616,000 5,851,260 Proved + Probable + Possible

As of December 31, 2010 - Total Remaining 3P Reserves 6,616,000 5,851,260

+ Cumulative Production through December 31, 2010 38,790

= Total Ultimate 3P Reserves 6,654,790


TABLE 6A

SUMMARY OF REMAINING RESERVE ASSIGNMENTS

Offshore Block G5/43 -- Songkhla A Field -- Eocene Formation -- Fault Block AAs of December 31, 2010

Estimated Remaining Reserves




Nonproducing 1 63,410 58,190 SA11 well - waiting on frac in early 2011Proved 3.0%

Undeveloped 1 150,000 137,470 Drill 1 PUD well - SA0C Loc

1P 213,410 195,660 Proved

Probable Undeveloped 4 20% 1,208,000 1,080,370 Drill 4 Prob Und wells at 302,000 BO per well based on 20% recovery factor & 2P volumetrics


Possible Undeveloped 2 30% 712,000 619,910 Drill 2 Poss Und wells at 356,000 BO per well based on 30% recovery factor & 3P volumetrics






TABLE 6B


Offshore Block G5/43 -- Songkhla A Field -- Eocene Formation -- Fault Block BAs of December 31, 2010





Developed Producing 4 5,590,830 5,207,550 SA01, SA03, SA04, & SA08 wells - PDP

Proved 24.3%

Nonproducing 1 0 0 SA02 well - shut-in 10/09

1P 5,590,830 5,207,550 Proved

Probable Nonproducing 4 30% 2,328,000 2,082,100

Prob incremental recovery assigned to 4 producing wells based on 30% recovery factor & 2P volumetrics


Possible Nonproducing 4 40% 4,080,000 3,559,250

Poss incremental recovery assigned to 4 producing wells based on 40% recovery factor & 3P volumetrics



+ Cumulative Production through December 31, 2010 4,320,240



TABLE 6C


Offshore Block G5/43 -- Songkhla A Field -- Oligocene Formation -- Main Fault BlockAs of December 31, 2010





Developed Producing 1 1,544,300 1,435,330 SA09 well - commingled with Eocene

Proved 29.2%

Undeveloped 2 2,600,000 2,414,980 Drill 2 PUD wells - SA07 ST & SA0A Loc

1P 4,144,300 3,850,310 Proved

Probable Undeveloped 1 38.3% 1,300,000 1,158,800 Drill 1 Prob Und well - SA0B Loc based on analogy & 2P volumetrics


Possible Undeveloped 4 40% 238,000 204,540

Poss incremental recovery assigned to 4 existing wells based on 40% recovery factor & 3P volumetrics






TABLE 6D


Offshore Block G5/43 -- Songkhla A Field -- Oligocene Formation -- SA09 Fault BlockAs of December 31, 2010





Proved 0 0% 0 0 SA11 well - not producing as of 12/31/2010

1P 0 0 Proved

Probable Nonproducing 1 20% 194,000 171,060 SA11 - Prob incremental recovery based on 20% recovery factor & 2P volumetrics

2P Nonproducing 194,000 171,060 Proved + Probable

Possible Nonproducing 1 30% 97,000 83,240 SA11 - Poss incremental recovery based on 30% recovery factor & 3P volumetrics

3P Nonproducing 291,000 254,300 Proved + Probable + Possible

As of December 31, 2010 - Total Remaining 3P Reserves 291,000 254,300

+ Cumulative Production through December 31, 2010 0

= Total Ultimate 3P Reserves 291,000


TABLE 6E


Offshore Block G5/43 -- Songkhla A Field -- Oligocene Formation -- SA11 Fault BlockAs of December 31, 2010





Developed Producing 1 1,157,660 1,074,460 SA12 ST well - online 1/18/2011

Proved 12.5%

Undeveloped 1 1,200,000 1,117,570 Drill 1 PUD well - SA0C Loc

1P 2,357,660 2,192,030 Proved

Probable Undeveloped 1 20% 1,363,000 1,216,130 Drill 1 Prob Und well - SA0D Loc based on analogy, 20% recovery factor & 2P volumetrics


Possible Undeveloped 3 30% 1,882,000 1,654,680

Poss incremental recovery assigned to 3 existing wells based on 30% recovery factor & 3P volumetrics



+ Cumulative Production through December 31, 2010 0



TABLE 6F


Offshore Block G5/43 -- Songkhla A Field -- Oligocene Formation -- SA12 ST Fault BlockAs of December 31, 2010





Proved Nonproducing 1 5.2% 57,820 53,080 SC04 well - waiting on Eocene frac

1P 57,820 53,080 Proved

Nonproducing 2 400,000 354,060 SC04 & SC07 wells - waiting on Eocene fracProbable 18.3%

Undeveloped 4 800,000 711,220 Drill 4 Prob Und wells - 2 vertical & 2 horizontal


Possible Undeveloped 2 25% 458,000 395,760

Poss incremental recovery for 2 horizontal ( Horz #4 & Horz #5) wells based on 25% recovery factor and 3P volumetrics






TABLE 6G


Offshore Block G5/43 -- Songkhla C (Bua Ban) Field -- Eocene Formation -- Main Fault BlockAs of December 31, 2010





Proved Developed Producing 1 6.3% 105,530 97,020 SC11 well - PDP in Miocene

1P 105,530 97,020 Proved

Probable Nonproducing 1 20% 275,000 244,200 SC11 well - Prob incremental recovery based on 20% recovery factor and 2P volumetrics

2P 380,530 341,220 Proved + Probable

Possible Nonproducing 1 30% 200,000 172,710 SC11 well - Poss incremental recovery based on 30% recovery factor and 3P volumetrics

3P 580,530 513,930 Proved + Probable + Possible

As of December 31, 2010 - Total Remaining 3P Reserves 580,530 513,930


= Total Ultimate 3P Reserves 600,630


TABLE 6H


Offshore Block G5/43 -- Songkhla C (Bua Ban) Field -- Miocene Formation -- Main Fault BlockAs of December 31, 2010





Developed Producing 1 53,890 49,450 SC03Proved 0.7%

Nonproducing 2 65,520 60,100 SC01 & SC02

1P 119,410 109,550 Proved

Probable Undeveloped 4 10.7% 2,156,000 1,929,410

Drill 4 Prob Und wells at 539,000 BO per well - 2 vertical wells (G01 & G04) and 2 horizontal wells (Horz #2 & Horz #3) based on higher recovery factor & 2P volumetrics


Possible Undeveloped 7 30% 4,148,000 3,640,460 Poss incremental recovery for 7 wells based on 30% recovery factor & 3P volumetrics






TABLE 6I


Offshore Block G5/43 -- Songkhla C (Bua Ban) Field -- Oligocene Formation -- Main Fault BlockAs of December 31, 2010





Developed Producing 3 1,100,070 1,016,140 SC05, SC06, & SC10 wells - PDPProved 18.0%

Nonproducing 1 500,000 461,550 SC05 well - plan to treat & re-perf well

1P 1,600,070 1,477,690 Proved

Probable Undeveloped 1 20% 230,000 202,140 Drill 1 horizontal well - Horz #1 based on analogy to vertical wells, 20% recovery factor & 2P volumetrics


Possible Undeveloped 1 30% 1,140,000 987,130 Poss incremental recovery for Horz #1 well based on 30% recovery factor & 3P volumetrics






TABLE 6J


Offshore Block G5/43 -- Songkhla C (Bua Ban) Field -- Oligocene Formation -- Wedge Fault BlockAs of December 31, 2010





Developed Producing 12 9,552,280 8,879,950

Proved Nonproducing 6 686,750 632,920

Undeveloped 6 4,250,000 3,944,960

Subtotal Proved 24 14,489,030 13,457,830

1P 14,489,030 13,457,830 Proved

Nonproducing 8 3,197,000 2,851,420

Probable Undeveloped 23 9,457,000 8,446,280

Subtotal Probable 31 12,654,000 11,297,700


Nonproducing 6 4,377,000 3,815,200

Possible Undeveloped 1 12,494,000 10,930,590

Subtotal Possible 7 16,871,000 14,745,790



+ Cumulative Production through December 31, 2010 4,916,880



TABLE 6K


Offshore Block G5/43 -- Total AssignmentsAs of December 31, 2010



Cumulative Cumulative Cumulative Month (bbl/d) (bbl/month) (bbl) (bbl/d) (bbl/month) (bbl) (bbl/d) (bbl/month) (bbl)

Nov-08 3,417 102,510 102,510 0 0 0 3,417 102,510 102,510Dec-08 2,333 72,323 174,833 0 0 0 2,333 72,323 174,833Jan-09 0 0 174,833 0 0 0 0 0 174,833Feb-09 5,807 162,594 337,427 0 0 0 5,807 162,594 337,427Mar-09 9,366 290,346 627,773 0 0 0 9,366 290,346 627,773Apr-09 8,347 250,410 878,183 0 0 0 8,347 250,410 878,183May-09 6,595 204,446 1,082,629 0 0 0 6,595 204,446 1,082,629Jun-09 4,896 146,880 1,229,509 0 0 0 4,896 146,880 1,229,509Jul-09 4,129 127,999 1,357,508 0 0 0 4,129 127,999 1,357,508Aug-09 3,766 116,746 1,474,254 0 0 0 3,766 116,746 1,474,254Sep-09 2,134 64,020 1,538,274 0 0 0 2,134 64,020 1,538,274Oct-09 4,584 142,104 1,680,378 0 0 0 4,584 142,104 1,680,378Nov-09 7,157 214,710 1,895,088 0 0 0 7,157 214,710 1,895,088Dec-09 4,840 150,035 2,045,123 0 0 0 4,840 150,035 2,045,123Jan-10 6,230 193,117 2,238,240 0 0 0 6,230 193,117 2,238,240Feb-10 6,327 196,148 2,434,388 0 0 0 6,327 196,148 2,434,388Mar-10 7,962 246,835 2,681,223 0 0 0 7,962 246,835 2,681,223Apr-10 8,676 268,956 2,950,179 0 0 0 8,676 268,956 2,950,179May-10 7,793 241,586 3,191,765 0 0 0 7,793 241,586 3,191,765Jun-10 6,762 209,615 3,401,380 0 0 0 6,762 209,615 3,401,380Jul-10 7,206 223,387 3,624,767 1,927 59,742 59,742 9,133 283,129 3,684,509Aug-10 7,477 231,795 3,856,562 3,612 111,975 171,717 11,089 343,770 4,028,279Sep-10 5,858 181,601 4,038,163 3,798 117,732 289,449 9,656 299,333 4,327,612Oct-10 3,927 121,722 4,159,885 3,713 115,090 404,539 7,639 236,812 4,564,424Nov-10 2,749 85,212 4,245,097 1,389 43,053 447,592 4,138 128,265 4,692,689Dec-10 5,027 155,822 4,400,919 2,205 68,368 515,960 7,232 224,190 4,916,879TOTALS 4,400,919 515,960 4,916,879

Total Offshore Oil Production

TABLE 7

SONGKHLA A and SONGKHLA C FIELDS --- OFFSHORE THAILAND

Gross Historical Oil Production through December 31, 2010

Songkhla A Field Songkhla C Field


Coastal Geologic

License Area Prospect - Reservoir, Fault Block

Low Estimate

Best Estimate

High Estimate

Energy Net Revenue Interest

Low Estimate

Best Estimate

High Estimate

Risk Factor1

Low Estimate

Best Estimate

High Estimate Operator

Oil (Mbbl) Offshore Block G5/43 Songkhla A - Eocene C FB 53.0 106.0 159.0 0.920000 48.8 97.5 146.3 50% 24.4 48.8 73.1 NuCoastal Songkhla A - Oligocene SA11 FB 4,675.0 9,350.0 14,024.0 0.920000 4,301.0 8,602.0 12,902.1 50% 2,150.5 4,301.0 6,451.0 NuCoastalSubtotal Songkhla A Field 4,728.0 9,456.0 14,183.0 4,349.8 8,699.5 13,048.4 2,174.9 4,349.8 6,524.2

Songkhla C - Eocene Main FB 7,390.0 14,781.0 22,171.0 0.920000 6,798.8 13,598.5 20,397.3 30% 2,039.6 4,079.6 6,119.2 NuCoastal Songkhla C - Miocene C03 Area 24.0 49.0 73.0 0.920000 22.1 45.1 67.2 100% 22.1 45.1 67.2 NuCoastalSubtotal Songkhla C Field 7,414.0 14,830.0 22,244.0 6,820.9 13,643.6 20,464.5 2,061.7 4,124.6 6,186.4

Songkhla Southwest - Oligocene 499.0 1,519.0 3,564.0 0.937500 467.8 1,424.1 3,341.3 30% 140.3 427.2 1,002.4 NuCoastal Benjarong - Eocene 3,413.0 7,563.0 17,453.0 0.900000 3,071.7 6,806.7 15,707.7 30% 921.5 2,042.0 4,712.3 NuCoastal

Subtotal Offshore Block G5/43 16,054.0 33,368.0 57,444.0 14,710.2 30,573.9 52,561.8 5,298.5 10,943.6 18,425.2

Total for Oil 16,054.0 33,368.0 57,444.0 14,710.2 30,573.9 52,561.8 5,298.5 10,943.6 18,425.2

Gas (Bcf) Onshore Block L27/43 Dong Mun (PNK) 2 75.4 144.7 426.3 0.315875 23.8 45.7 134.7 30% 7.1 13.7 40.4 APICO Dong Mun (Phu Kheng) 3 850.0 1,360.0 2,125.1 0.315875 268.5 429.6 671.3 30% 80.5 128.9 201.4 APICOSubtotal Onshore Block L27/43 925.4 1,504.7 2,551.4 292.3 475.3 805.9 87.7 142.6 241.8

Total for Gas 925.4 1,504.7 2,551.4 292.3 475.3 805.9 87.7 142.6 241.8

Total MBOE 4 170,287.3 284,151.3 482,677.3 63,428.6 109,790.1 186,882.4 19,914.0 34,708.5 58,721.4


Notes: 1. Geologic Risk Factor for Contingent Resources means the estimated chance or probability that the volumes will be commercially extracted. 2. PNK = Pha Nok Khao formation 3. Dong Mun (Phu Kheng) drilled and tested by Phu Kheng 1 well in 2009 4. BOE = Barrel Oil Equivalents at 6 Mcf per barrel (MBOE = 1,000 BOE)

TABLE 8

SUMMARY OF CONTINGENT RESOURCESGross Resource Volumes and Coastal Energy Net Resource Volumes


Gross Net to Coastal Energy Net to Coastal Energy - Risked


Coastal Geologic

License Area Prospect - Reservoir, Fault Block

Low Estimate

Best Estimate

High Estimate

Energy Net Revenue Interest

Low Estimate

Best Estimate

High Estimate

Risk Factor1

Low Estimate

Best Estimate

High Estimate Operator

Oil (Mbbl) Offshore Block G5/43 Songkhla B - Miocene M500 4,755.0 7,133.0 14,265.0 0.900000 4,279.5 6,419.7 12,838.5 40% 1,711.8 2,567.9 5,135.4 NuCoastal Songkhla B - Miocene M500 3-way 403.0 604.0 1,208.0 0.900000 362.7 543.6 1,087.2 40% 145.1 217.4 434.9 NuCoastal Songkhla B - Miocene M100 4,182.0 6,273.0 12,546.0 0.900000 3,763.8 5,645.7 11,291.4 40% 1,505.5 2,258.3 4,516.6 NuCoastal Songkhla B - Miocene M100 3-way 213.0 319.0 638.0 0.900000 191.7 287.1 574.2 40% 76.7 114.8 229.7 NuCoastal Songkhla C - Miocene M500 1,275.0 1,912.0 3,824.0 0.900000 1,147.5 1,720.8 3,441.6 65% 745.9 1,118.5 2,237.0 NuCoastal Songkhla C - Miocene M100 1,951.0 2,927.0 5,854.0 0.900000 1,755.9 2,634.3 5,268.6 65% 1,141.3 1,712.3 3,424.6 NuCoastal Songkhla D - Miocene M500 1,636.0 2,455.0 4,909.0 0.900000 1,472.4 2,209.5 4,418.1 65% 957.1 1,436.2 2,871.8 NuCoastal Songkhla D - Miocene M100 602.0 902.0 1,805.0 0.900000 541.8 811.8 1,624.5 65% 352.2 527.7 1,055.9 NuCoastal Songkhla E - Miocene M500 777.0 1,165.0 2,331.0 0.900000 699.3 1,048.5 2,097.9 65% 454.5 681.5 1,363.6 NuCoastal Songkhla E - Miocene M100 548.0 822.0 1,644.0 0.900000 493.2 739.8 1,479.6 65% 320.6 480.9 961.7 NuCoastal Songkhla F - Miocene M500 372.0 559.0 1,117.0 0.900000 334.8 503.1 1,005.3 65% 217.6 327.0 653.4 NuCoastal Songkhla F - Miocene M100 408.0 612.0 1,225.0 0.900000 367.2 550.8 1,102.5 65% 238.7 358.0 716.6 NuCoastal Songkhla G - Miocene M500 691.0 1,037.0 2,073.0 0.900000 621.9 933.3 1,865.7 65% 404.2 606.6 1,212.7 NuCoastal Songkhla G - Miocene M100 605.0 908.0 1,815.0 0.900000 544.5 817.2 1,633.5 65% 353.9 531.2 1,061.8 NuCoastal Songkhla H - Miocene 414.0 620.0 1,241.0 0.900000 372.6 558.0 1,116.9 65% 242.2 362.7 726.0 NuCoastal Songkhla I - Miocene 1,307.0 1,960.0 3,921.0 0.900000 1,176.3 1,764.0 3,528.9 65% 764.6 1,146.6 2,293.8 NuCoastal Songkhla J - Miocene M500 594.0 892.0 1,783.0 0.900000 534.6 802.8 1,604.7 65% 347.5 521.8 1,043.1 NuCoastal Songkhla J - Miocene M100 A 201.0 301.0 602.0 0.900000 180.9 270.9 541.8 55% 99.5 149.0 298.0 NuCoastal Songkhla J - Miocene M100 B 438.0 655.0 1,311.0 0.900000 394.2 589.5 1,179.9 30% 118.3 176.9 354.0 NuCoastal Songkhla K - Miocene M100 741.0 1,112.0 2,224.0 0.900000 666.9 1,000.8 2,001.6 30% 200.1 300.2 600.5 NuCoastal Songkhla L - Miocene M100 347.0 521.0 1,042.0 0.900000 312.3 468.9 937.8 30% 93.7 140.7 281.3 NuCoastal Songkhla M - Miocene M100 491.0 736.0 1,472.0 0.900000 441.9 662.4 1,324.8 30% 132.6 198.7 397.4 NuCoastal Songkhla D - Oligocene 1,507.0 3,013.0 4,520.0 0.900000 1,356.3 2,711.7 4,068.0 60% 813.8 1,627.0 2,440.8 NuCoastal Songkhla E - Oligocene 1,703.0 3,405.0 5,108.0 0.900000 1,532.7 3,064.5 4,597.2 60% 919.6 1,838.7 2,758.3 NuCoastal Bua Ban North C - Oligocene 3,612.0 7,224.0 10,836.0 0.900000 3,250.8 6,501.6 9,752.4 45% 1,462.9 2,925.7 4,388.6 NuCoastal Bua Ban North D - Oligocene 470.0 940.0 1,410.0 0.900000 423.0 846.0 1,269.0 60% 253.8 507.6 761.4 NuCoastal Bua Ban North D Ext - Oligocene 102.0 204.0 306.0 0.900000 91.8 183.6 275.4 60% 55.1 110.2 165.2 NuCoastal Bua Ban North E - Oligocene 752.0 1,504.0 2,256.0 0.900000 676.8 1,353.6 2,030.4 45% 304.6 609.1 913.7 NuCoastal Songkhla D - Eocene 2,047.0 4,094.0 12,282.0 0.900000 1,842.3 3,684.6 11,053.8 65% 1,197.5 2,395.0 7,185.0 NuCoastal Songkhla E - Eocene 1,993.0 3,985.0 11,956.0 0.900000 1,793.7 3,586.5 10,760.4 65% 1,165.9 2,331.2 6,994.3 NuCoastal Bua Ban Terrace C - Eocene 11,494.0 22,988.0 34,482.0 0.900000 10,344.6 20,689.2 31,033.8 50% 5,172.3 10,344.6 15,516.9 NuCoastal Bua Ban Terrace E - Eocene 3,900.0 7,800.0 11,700.0 0.900000 3,510.0 7,020.0 10,530.0 50% 1,755.0 3,510.0 5,265.0 NuCoastal Bua Ban Terrace F - Eocene 5,705.0 11,410.0 17,115.0 0.900000 5,134.5 10,269.0 15,403.5 50% 2,567.3 5,134.5 7,701.8 NuCoastal Bua Ban Terrace G - Eocene 3,291.0 6,581.0 9,872.0 0.900000 2,961.9 5,922.9 8,884.8 50% 1,481.0 2,961.5 4,442.4 NuCoastal Benjarong South - Eocene 11,595.0 23,189.0 34,784.0 0.900000 10,435.5 20,870.1 31,305.6 50% 5,217.8 10,435.1 15,652.8 NuCoastal Songkhla C - Oligocene Shale 300.0 600.0 1,200.0 0.900000 270.0 540.0 1,080.0 10% 27.0 54.0 108.0 NuCoastal

Subtotal Offshore Block G5/43 71,422.0 131,362.0 226,677.0 64,279.8 118,225.8 204,009.3 33,016.8 60,719.1 106,163.9

Offshore Block G5/50 Central A - Oligocene 138.0 2,710.0 16,428.0 0.900000 124.2 2,439.0 14,785.2 30% 37.3 731.7 4,435.6 NuCoastal Central B - Oligocene 89.0 2,577.0 12,963.0 0.900000 80.1 2,319.3 11,666.7 30% 24.0 695.8 3,500.0 NuCoastal Central C - Oligocene 43.0 613.0 7,220.0 0.900000 38.7 551.7 6,498.0 30% 11.6 165.5 1,949.4 NuCoastal Central D - Oligocene 70.0 1,096.0 7,047.0 0.900000 63.0 986.4 6,342.3 30% 18.9 295.9 1,902.7 NuCoastal Central E - Oligocene 21.0 563.0 3,601.0 0.900000 18.9 506.7 3,240.9 30% 5.7 152.0 972.3 NuCoastal

Subtotal Offshore Block G5/50 361.0 7,559.0 47,259.0 324.9 6,803.1 42,533.1 97.5 2,040.9 12,759.9

Subtotal Offshore Blocks 71,783.0 138,921.0 273,936.0 64,604.7 125,028.9 246,542.4 33,114.3 62,760.0 118,923.8

Total for Oil 71,783.0 138,921.0 273,936.0 64,604.7 125,028.9 246,542.4 33,114.3 62,760.0 118,923.8

Gas (Bcf) Onshore Block L27/43 Se Dong Mun (PNK) 2 20.0 76.9 433.2 0.315875 6.3 24.3 136.8 2% 0.1 0.5 2.7 APICOSubtotal Onshore Block L27/43 20.0 76.9 433.2 6.3 24.3 136.8 0.1 0.5 2.7

Total for Gas 20.0 76.9 433.2 6.3 24.3 136.8 0.1 0.5 2.7

Total MBOE 3 75,116.3 151,737.7 346,136.0 65,657.6 129,077.4 269,348.6 33,135.3 62,841.0 119,380.0


Notes: 1. Geologic Risk Factor for Contingent Resources means the estimated chance or probability that the volumes will be commercially extracted. 2. PNK = Pha Nok Khao formation 3. BOE = Barrel Oil Equivalents at 6 Mcf per barrel (MBOE = 1,000 BOE)

TABLE 9

SUMMARY OF PROSPECTIVE RESOURCESGross Resource Volumes and Coastal Energy Net Resource Volumes


Gross Net to Coastal Energy Net to Coastal Energy - Risked


Estimated Discount ForecastDifferential Dubai off of Sales

WTI Brent To Brent Price Dubai PricePd Year ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl)1 2011 88.00 88.50 (1.49) 87.01 (4.25) 82.762 2012 89.00 88.25 (1.49) 86.76 (4.25) 82.513 2013 90.00 88.50 (1.49) 87.01 (4.25) 82.764 2014 92.00 90.50 (1.49) 89.01 (4.25) 84.765 2015 95.17 93.67 (1.49) 92.18 (4.25) 87.936 2016 97.55 96.05 (1.49) 94.56 (4.25) 90.317 2017 100.26 98.76 (1.49) 97.27 (4.25) 93.028 2018 102.74 101.24 (1.49) 99.75 (4.25) 95.509 2019 105.45 103.95 (1.49) 102.46 (4.25) 98.2110 2020 107.56 106.06 (1.49) 104.57 (4.25) 100.3211 202112 202213 202314 202415 2025

Note: Forecasted prices as of January 2011 through 2020 were taken from Gilbert Lausten Jung Petroleum Consultants website (www.gljpc.com)

TABLE 10A

FORECAST CASECrude Oil Price Assumptions and Calculations


Thailand Offshore

Note: Offshore crude oil price projections in the cash flow modelend in 2018 as oil reserves deplete

Crude Oil Price

Begin escalatingat 2% per year


Estimated Discount ForecastDifferential Dubai off of Sales

WTI Brent To Brent Price Dubai PricePd Year ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl) ($/bbl)1 2011 105.00 115.00 (1.49) 113.51 (4.25) 109.262 2012 102.00 108.50 (1.49) 107.01 (4.25) 102.763 2013 100.00 103.50 (1.49) 102.01 (4.25) 97.764 2014 100.00 102.50 (1.49) 101.01 (4.25) 96.765 2015 100.00 100.00 (1.49) 98.51 (4.25) 94.266 2016 100.00 100.00 (1.49) 98.51 (4.25) 94.267 2017 101.36 100.36 (1.49) 98.87 (4.25) 94.628 2018 103.38 102.38 (1.49) 100.89 (4.25) 96.649 2019 105.45 104.45 (1.49) 102.96 (4.25) 98.7110 2020 107.56 106.56 (1.49) 105.07 (4.25) 100.8211 202112 202213 202314 202415 2025

Note: Forecasted prices as of April 2011 through 2020 were taken from Gilbert Lausten Jung Petroleum Consultants website (www.gljpc.com)

Note: Offshore crude oil price projections in the cash flow modelend in 2018 as oil reserves deplete

Crude Oil Price

Begin escalatingat 2% per year

TABLE 10B

FORECAST CASECrude Oil Price Assumptions and Calculations

As of April 1, 2011

Thailand Offshore


1P 2P 3P

Fixed Variable Total Fixed Variable Total Fixed Variable Total Fixed Variable Total Fixed Variable TotalPd Year (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)1 2011 55,242 0 55,242 0 0 0 55,242 0 55,242 0 0 2,219 55,242 0 55,2422 2012 56,348 0 56,348 0 0 0 56,348 0 56,348 0 0 336 56,348 0 56,3483 2013 57,474 0 57,474 0 0 0 57,474 0 57,474 0 0 868 57,474 0 57,4744 2014 51,310 0 51,310 7,313 0 7,313 58,623 0 58,623 0 0 819 58,623 0 58,6235 2015 40,018 0 40,018 16,253 0 16,253 56,271 0 56,271 3,498 0 623 59,770 0 59,7706 2016 40,699 0 40,699 12,511 0 12,511 53,210 0 53,210 7,783 0 481 60,993 0 60,9937 2017 31,431 0 31,431 13,152 0 13,152 44,583 0 44,583 17,628 0 3,296 62,211 0 62,2118 2018 20,505 0 20,505 3,759 0 3,759 24,264 0 24,264 4,970 0 7,065 29,234 0 29,2349 2019 0 0 0 0 0 0 0 0 0 0 0 16,296 0 0 010 2020 0 0 0 0 0 0 0 0 0 0 0 12,062 0 0 0

Totals 353,027 0 353,027 52,988 0 52,988 406,015 0 406,015 33,879 0 44,065 439,894 0 439,894

TABLE 11

SUMMARY OF LEASE OPERATING EXPENSES

As of December 31, 2010Forecast Price Case --- 100% Interests --- Offshore Properties

PROVED + PROBABLE + POSSIBLEPROVED PROBABLE POSSIBLEPROVED + PROBABLE


1P 2P 3P

Fixed Variable Total Fixed Variable Total Fixed Variable Total Fixed Variable Total Fixed Variable TotalPd Year (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)1 2011 55,242 0 55,242 0 0 0 55,242 0 55,242 0 0 2,219 55,242 0 55,2422 2012 56,348 0 56,348 0 0 0 56,348 0 56,348 0 0 336 56,348 0 56,3483 2013 57,474 0 57,474 0 0 0 57,474 0 57,474 0 0 868 57,474 0 57,4744 2014 51,310 0 51,310 7,313 0 7,313 58,623 0 58,623 0 0 819 58,623 0 58,6235 2015 40,018 0 40,018 16,253 0 16,253 56,271 0 56,271 3,498 0 623 59,770 0 59,7706 2016 40,699 0 40,699 12,511 0 12,511 53,210 0 53,210 7,783 0 481 60,993 0 60,9937 2017 31,431 0 31,431 13,152 0 13,152 44,583 0 44,583 17,628 0 3,296 62,211 0 62,2118 2018 20,505 0 20,505 3,759 0 3,759 24,264 0 24,264 4,970 0 7,065 29,234 0 29,2349 2019 0 0 0 0 0 0 0 0 0 0 0 16,296 0 0 010 2020 0 0 0 0 0 0 0 0 0 0 0 12,062 0 0 0

Totals 353,027 0 353,027 52,988 0 52,988 406,015 0 406,015 33,879 0 44,065 439,894 0 439,894

TABLE 12

SUMMARY OF LEASE OPERATING EXPENSES

As of December 31, 2010Forecast Price Case --- Net to Coastal Energy --- Offshore Properties

PROVED + PROBABLE + POSSIBLEPROVED PROBABLE POSSIBLEPROVED + PROBABLE


1P 2P 3PProved

+Proved Probable

+ +Proved Probable Probable Possible Possible

Pd Year (M$) (M$) (M$) (M$) (M$)1 2011 18,576 75,793 94,369 0 94,3692 2012 0 66,956 66,956 10,816 77,7723 2013 0 0 0 7,283 7,2834 2014 0 0 0 0 05 2015 0 0 0 0 06 2016 0 0 0 0 07 2017 0 0 0 0 08 2018 0 0 0 0 09 2019 12,897 5,620 18,517 0 18,51710 2020 20,638 7,242 27,880 2,414 30,294

Totals 52,111 155,611 207,722 20,513 228,235

TABLE 13

SUMMARY OF CAPITAL EXPENDITURES BY RESERVE CLASSIFICATION


Forecast Price Case - 100% Interests - Offshore Properties

Reserve Classification


1P 2P 3P 1P 2P 3P 1P 2P 3PProved Proved Proved

+ + +Proved Probable Proved Probable Proved Probable

+ + + + + +Proved Probable Probable Possible Possible Proved Probable Probable Possible Possible Proved Probable Probable Possible Possible

Pd Year (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)1 2011 17,523 22,309 39,832 0 39,832 1,053 53,484 54,537 0 54,537 18,576 75,793 94,369 0 94,3692 2012 0 44,294 44,294 10,816 55,110 0 22,662 22,662 0 22,662 0 66,956 66,956 10,816 77,7723 2013 0 0 0 7,283 7,283 0 0 0 0 0 0 0 0 7,283 7,2834 2014 0 0 0 0 0 0 0 0 0 0 0 0 0 0 05 2015 0 0 0 0 0 0 0 0 0 0 0 0 0 0 06 2016 0 0 0 0 0 0 0 0 0 0 0 0 0 0 07 2017 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 2018 0 0 0 0 0 0 0 0 0 0 0 0 0 0 09 2019 0 0 0 0 0 12,897 5,620 18,517 0 18,517 12,897 5,620 18,517 0 18,51710 2020 20,638 7,242 27,880 2,414 30,294 0 0 0 0 0 20,638 7,242 27,880 2,414 30,294

Totals 38,161 73,845 112,005 20,513 132,518 13,950 81,766 95,717 0 95,717 52,111 155,611 207,722 20,513 228,235

TABLE 14SUMMARY OF CAPITAL EXPENDITURES BY FIELD

Forecast Price Case --- 100% Interests --- Offshore PropertiesAs of December 31, 2010

SONGKHLA A FIELD SONGKHLA C FIELD TOTAL -- ALL FIELDS


1P 2P 3P 1P 2P 3P 1P 2P 3PProved Proved Proved

+ + +Proved Probable Proved Probable Proved Probable

+ + + + + +Proved Probable Probable Possible Possible Proved Probable Probable Possible Possible Proved Probable Probable Possible Possible

Pd Year (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$) (M$)1 2011 17,523 22,309 39,832 0 39,832 1,053 53,484 54,537 0 54,537 18,576 75,793 94,369 0 94,3692 2012 0 44,294 44,294 10,816 55,110 0 22,662 22,662 0 22,662 0 66,956 66,956 10,816 77,7723 2013 0 0 0 7,283 7,283 0 0 0 0 0 0 0 0 7,283 7,2834 2014 0 0 0 0 0 0 0 0 0 0 0 0 0 0 05 2015 0 0 0 0 0 0 0 0 0 0 0 0 0 0 06 2016 0 0 0 0 0 0 0 0 0 0 0 0 0 0 07 2017 0 0 0 0 0 0 0 0 0 0 0 0 0 0 08 2018 0 0 0 0 0 0 0 0 0 0 0 0 0 0 09 2019 0 0 0 0 0 12,897 5,620 18,517 0 18,517 12,897 5,620 18,517 0 18,51710 2020 20,638 7,242 27,880 2,414 30,294 0 0 0 0 0 20,638 7,242 27,880 2,414 30,294

Totals 38,161 73,845 112,005 20,513 132,518 13,950 81,766 95,717 0 95,717 52,111 155,611 207,722 20,513 228,235

TABLE 15SUMMARY OF CAPITAL EXPENDITURES BY FIELD

Forecast Price Case --- Net to Coastal Energy --- Offshore PropertiesAs of December 31, 2010

SONGKHLA A FIELD SONGKHLA C FIELD TOTAL -- ALL FIELDS


Offshore - Net to Coastal EnergyReserve Category 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Total 1P 732,470 671,825 618,046 570,592 528,782 464,907 438,760 413,544 389,934 368,191

Total 2P 1,477,156 1,322,875 1,189,481 1,074,174 974,367 667,924 624,679 583,549 545,395 510,497

Total 3P 2,680,540 2,342,363 2,057,428 1,816,608 1,612,321 903,620 840,364 780,630 725,335 674,736


Future Net Revenues Discounted at Future Net Revenues Discounted at

TABLE 16ACOMPARISON OF BEFORE AND AFTER INCOME TAX NET REVENUES

Forecast Price CaseAs of December 31, 2010

Net Revenues Before Income Taxes, M$ (App F) Net Revenues After Income Taxes, M$


Offshore - Net to Coastal EnergyReserve Category 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%

Total 1P 872,995 806,571 747,406 694,911 648,380 554,453 525,778 498,202 472,346 448,446

Total 2P 1,780,449 1,614,093 1,468,826 1,341,963 1,231,004 804,616 759,427 716,180 675,730 638,389

Total 3P 3,161,618 2,803,357 2,497,725 2,236,181 2,011,555 1,065,375 1,002,824 942,869 886,557 834,292


Future Net Revenues Discounted at Future Net Revenues Discounted at

TABLE 16BCOMPARISON OF BEFORE AND AFTER INCOME TAX NET REVENUES

Forecast Price CaseAs of April 1, 2011

Net Revenues Before Income Taxes, M$ Net Revenues After Income Taxes, M$


Gross Net Gross Net Gross Net Gross NetReserve Category (Mbbl) (Mbbl) (Bcf) (Bcf) (Mbbl) (Mbbl) (MBOE) (MBOE)

Proved: Offshore Developed Producing (App F) 9,552 8,880 0.0 0.0 0 0 9,552 8,880 Offshore Developed Nonproducing (App F) 687 633 0.0 0.0 0 0 687 633 Offshore Undeveloped (App F) 4,250 3,945 0.0 0.0 0 0 4,250 3,945Total Proved - 1P 14,489 13,458 0 0 0 0 14,489 13,458

Probable: Offshore Nonproducing (App F) 3,197 2,851 0.0 0.0 0 0 3,197 2,851 Offshore Undeveloped (App F) 9,457 8,446 0.0 0.0 0 0 9,457 8,446Total Probable 12,654 11,297 0 0 0 0 12,654 11,297

Total Proved Plus Probable - 2P 27,143 24,755 0.0 0.0 0 0 27,143 24,755

Crude Oil Natural Gas (Natural Gas Liquids) Totals

TABLE 17

AIF - Offshore Remaining Reserves Data - Forecast Prices and CostsAs of December 31, 2010

Light and Medium Condensate


Unit Value

Before Income TaxDisc. @ 10%

Reserve Category 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% ($/bbl)

Proved: Offshore Developed Producing 364.4 341.4 319.3 298.8 280.0 227.6 221.3 213.2 204.5 195.7 $35.96 Offshore Developed Nonproducing 49.1 46.6 44.1 41.7 39.4 32.1 31.2 30.1 28.9 27.8 $69.62 Offshore Undeveloped 318.9 283.9 254.7 230.1 209.4 205.2 186.3 170.3 156.5 144.7 $64.56Total Proved - 1P 732.5 671.8 618.0 570.6 528.8 464.9 438.8 413.5 389.9 368.2 $45.92

Probable: Offshore Nonproducing 234.2 205.0 180.1 158.8 140.5 62.9 57.6 52.7 48.2 44.1 $63.18 Offshore Undeveloped 510.5 446.0 391.3 344.8 305.1 140.1 128.3 117.3 107.3 98.2 $46.33Total Probable 744.7 651.1 571.4 503.6 445.6 203.0 185.9 170.0 155.5 142.3 $50.58

Total Proved Plus Probable - 2P 1,477.2 1,322.9 1,189.5 1,074.2 974.4 667.9 624.7 583.5 545.4 510.5 $48.05

TABLE 18

AIF - Offshore Net Present Value of Future Net Revenues - Forecast Prices and Costs As of December 31, 2010

Net Present Values of Future Net Revenue, $ Millions

Before Income Taxes, Discounted at After Income Taxes, Discounted at


Future Net Revenue Unit ValueBefore Income Taxes Before Income Tax

Discounted at 10% Discounted at 10%Reserve Category Production Group (MM$) ($/bbl)

Proved Reserves - 1P Light and Medium Crude Oil 618.046 $45.92

Probable Reserves Light and Medium Crude Oil 571.435 $50.58

Proved Plus Probable Reserves - 2P Light and Medium Crude Oil 1,189.481 $48.05

TABLE 19

AIF - Offshore Future Net Revenue by Production Group - Forecast Prices and CostsAs of December 31, 2010


Future FutureNet Net

Revenue RevenueWell Before After

Operating Development Abandonment Income Income IncomeRevenue Royalties Costs Costs Costs Taxes Taxes Taxes

Reserve Category (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$) (MM$)

Proved - 1P 1,224.261 86.652 353.027 18.576 33.535 732.470 267.563 464.907

Proved Plus Probable - 2P 2,291.282 200.388 406.015 161.325 46.397 1,477.157 809.233 667.924

TABLE 20

AIF - Offshore Future Net Revenues - Forecast Prices and CostsAs of December 31, 2010


AIF - Summary of Offshore Pricing and Inflation Rate Assumptions - Forecast Prices and Costs

ThailandWTI Brent OffshoreSpot Spot CrudeOil Oil Oil Inflation

Price Price Price RatePd Year ($/bbl) ($/bbl) ($/bbl) (%/yr)

1 2011 88.00 88.50 82.76 ---2 2012 89.00 88.25 82.51 -0.3%3 2013 90.00 88.50 82.76 0.3%4 2014 92.00 90.50 84.76 2.4%5 2015 95.17 93.67 87.93 3.7%6 2016 97.55 96.05 90.31 2.7%7 2017 100.26 98.76 93.02 3.0%8 2018 102.74 101.24 95.50 2.7%

Thereafter 2% per year 2% per year 2% per year 2%

TABLE 21



Proved - 1P Probable Total - 2P Proved - 1P Probable Total - 2P Proved - 1P Probable Total - 2P

Beginning Balance as of December 31, 20091 13,992 15,676 29,668 0.0 0.0 0.0 0 0 0

Acquisitions 0 0 0 0.0 0.0 0.0 0 0 0

Revisions 2,013 (4,378) (2,366) 0.0 0.0 0.0 0 0 0

Less Production 2,547 0 2,547 0.0 0.0 0.0 0 0 0

Ending Balance as of December 31, 2010 13,458 11,298 24,756 0.0 0.0 0.0 0 0 0

Notes: 1. Source = Huddleston report dated March 17, 2010

TABLE 22

AIF - Offshore Reconciliation of Net Reserves - Forecast Prices and CostsAs of December 31, 2010

Light/Medium Crude Oil, Mbbl Natural Gas, MMcf Condensate, Mbbl


APPENDIX A:

Glossary of Technical Terms

GLOSSARY OF TERMS

As edited by Huddleston (Taken from Appendix A – Glossary of the COGE Handbook)

Bottom-hole pressure: The pressure in a well at a point opposite the producing formation as recorded by a bottom-hole pressure recorder.

Bottom-hole temperature: The temperature in a well at a point opposite the producing formation.

Compressibility (z) factor: A factor used to correct the Ideal Gas Law (pv=nRT) to actual measurements.

Crude Oil: A mixture, consisting mainly of pentanes and heavier hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain sulphur and other non-hydrocarbon compounds, but does not include liquids obtained from the processing of natural gas. Classes of crude oil are often reported on the basis of density, sometimes with different meanings. Acceptable ranges are as follows:

Light: less than 870 kg/m3 (greater than 31.1° API)

Medium: 870 to 920 kg/m3 (31.1° API to 22.3° API)

Heavy: 920 to 1000 kg/m3 (22.3° API to 10° API)

Extra-heavy: greater than 1000 kg/m3 (less than 10° API)

Heavy or extra-heavy crude oils, as defined by the density ranges given, but with viscosities greater than 10,000 mPa.s measured at original temperature in the reservoir and atmospheric pressure, on a gas-free basis, would generally be classified at bitumen.

Discounted cash flow: Future cash converted to present conditions using an appropriate discount rate.

Disposal well: A well used for the disposal of salt water where it is pumped into a surface formation sealed off from other formations by impervious strata of rock.

Dolomitization: The process whereby limestone is altered to dolomite by substitution of magnesium carbonate for a portion of the original calcium carbonate.

Drill stem test: The procedure used to gather data on a formation to determine its potential productivity before installing casing in a well.

Effective Date: The effective date, also referred to as the “As of Date,” serves two purposes in an oil and gas reserves evaluation: (1) It is the cut-off date for all geological, engineering, and financial data after which no new information can be included in the evaluation. (2) It is the date to which all future net revenue or other cash flow forecasts are discounted to determine present worth values.

Flow test: A test of the ability of a well to produce fluids usually at a constant rate.

Fracturing: A stimulation to increase productivity that results in the formation of a fracture in the wellbore area; conducted mostly in clastics.

Gas oil ratio: The ratio of gas in solution to the oil volume in which it is dissolved, usually expressed in cubic feet of gas per barrel of liquid at 14.65 psia and 60°F.

Gross pay: The gross economically productive thickness of a hydrocarbon formation.

Isopach map: A geological map of subsurface strata showing contours of the thickness of a given formation underlying an area; one type of volumetric map.

Natural Gas: A mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

Natural Gas Liquids: Those hydrocarbon components that can be recovered from natural gas as liquids including but not limited to ethane, propane, butanes, and pentanes, plus condensate and small quantities of non-hydrocarbons.

Net present value: The value obtained when all cash flow streams, including the investment, are discounted to the present and totaled.

Porosity: The volume of the pore space expressed as a percentage of the total volume of rock mass.

Production tests: Test conducted to determine the productivity of a given reservoir.

Stratigraphic trap: A type of reservoir capable of holding oil or gas in which the trap is formed by a change in the characteristics of the formation, which could be loss of porosity and permeability or a break in its continuity.

Structural trap: A type of reservoir containing oil and/or gas formed by deformation of the earth’s crust that seals off the oil and gas accumulation in the reservoir forming a trap.

Unconformity: Lack of continuity in deposition between rock strata in contact with one another corresponding to a gap in the stratigraphic record; the surface of contact between rock beds in which there is a discontinuity in the ages of the rocks.

Water injector: A well in which water has been injected into an underground stratum to increase reservoir pressure.

APPENDIX B:

Conversion Factors and Abbreviations

CONVERSION FACTORS AND ABBREVIATIONS

Conversion Factors

1 meter 3.281 feet

1 kilometer 3,281 feet

1 kilometer 0.6214 miles

1 cubic meter of gas 35.31467 cubic feet of gas

1 cubic meter of liquid 6.28981 barrels

1 kg/sq cm 14.22334 psi

1 hectare (10,000 square meters) 2.471054 acres

1 square kilometer 247.1 acres

1 US gallon 3.7854 liters

1 barrel of oil 42 gallons

1 barrel of oil 6.0 McfE (Btu basis)

1 mPa-s 1.0 centipoise

Abbreviations

1P Proved

2P Proved + Probable

3P Proved + Probable + Possible

AAPG American Association of Petroleum Geologists

ac acre

ACQ Annual Contract Quantity

AIM Alternative Investment Market of London

AOF absolute open flow

AOFP Absolute Open Flow Potentials

API American Petroleum Institute

APICO APICO LLC

B billion

bbl barrels

bbl/MMcf barrels per million cubic feet

bopd barrels of oil per day

BS&W Bottom sediment and water

Bcf Billion cubic feet

Btu British thermal units

Btu/scf British thermal unit per standard cubic feet

bwpd Barrels of water per day

Conversion Factors and Abbreviations Page Two Capex Capital Expenditures

CEO Chief Executive Officer

CDC Contract Delivery Capacity

CGR Condensate Gas Ratio

CIM Canadian Institute of Mining, Metallurgy & Petroleum

Coastal Coastal Energy Company

COGE(H) Canadian Oil and Gas Evaluation (Handbook)

CO2 Carbon Dioxide

CoS chance of success

cp centipose

CPR Competent Person’s Report

DCD Date of Commencement Delivery

DCQ Daily Contract Quantity

Disc discounted or discount

°F degrees, Fahrenheit

°R degrees, Rankin (= °F + 460)

$/bbl dollars per barrel

$/Mcf dollars per thousand cubic feet

$/MMBtu dollars per million British thermal units

DST drill stem test

EIA Environment Impact Assessment

ESP Electric Submersible Pump

EUR Estimated Ultimate Recovery

ft feet

ft3 cubic feet

FNR Future Net Revenue

FVF Formation volume factor

G&A General and Administrative costs

GIIP Gas Initially-In-Place

GLJ Gilbert Lausten Jung Petroleum Consultants (www.gljpc.com)

GOC Gas-Oil contact

GOR Gas-Oil ratio

GSA Gas Sales Agreement

GWC Gas-Water Contact

H2S Hydrogen Sulfide

Conversion Factors and Abbreviations Page Three HSFO 180 CST High Sulfur Fuel Oil 180 CST

HHL Huai Hin Lat formation

KB Kelly bushing

KBE Kelly bushing elevation

kg/sq cm kilograms per square centimeter

kg/m3 kilograms per cubic meter

km Kilometers

km2 Square kilometers

m meters

mPa-s thousand Pascal-seconds (viscosity measurement)

m3 Cubic meters

M Thousand

M$ Thousand dollars

Mbbl thousands of barrels

MBOE thousands of barrel oil equivalents

Mcf thousand cubic feet

McfE thousand cubic feet equivalents

MD measured depth

mD permeability in millidarcies

MM million

MMBtu million British thermal units

MMBtu/d million British thermal units per day

MMcf million cubic feet

MMcf/d million cubic feet per day

MMcf/y million cubic feet per year

NI National Instrument

NPV Net Present Value

NRI net revenue interest (partners share of the revenues less the royalty)

NWS Australian Northwest Shelf crude oil

OOIP Original Oil-In-Place

Opex Operating expenses

OWC oil-water contact

% Percentage

PCA Petroleum Concession Agreement

Conversion Factors and Abbreviations Page Four PH Phu Horm

PI Productivity Index

PLT Production Logging Tool

PNK Pha Nok Khao formation

ppm parts per million

PSC Production Sharing Contract

psi pounds per square inch

psia pounds per square inch absolute

psig pounds per square inch gauge

PTT PTT Public Company Limited, Thailand gas buyer

PVT pressure-volume-temperature

REC Recovery

RF Recovery Factor

RFT Repeat formation test

rb/STB reservoir barrels per stock tank barrel

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

scf/bbl standard cubic feet per barrel

SG Specific gravity

SPE Society of Petroleum Engineers

ss subsea

stb stock tank barrel

SW Southwest

Sw Water Saturation

TSX Toronto Venture Stock Exchange, Canada

TVD True vertical depth

TVDSS True Vertical Depth Subsea

US$ United States Dollar

WFT Western Fault Terrace

WI working interest

Working Interest Share (of reserves) calculated by multiplying the Gross estimate by the Contractor’s Working Interest in a Production Sharing Contract

WPC World Petroleum Congress

z – factor gas compressibility factor

APPENDIX C:

Certificate of Qualification




PHONE (713) 209-1100 FAX (713) 752-0828

CERTIFICATE OF QUALIFICATION

I, John P. Krawtz, P.E., with an office at 1221 McKinney, Suite 3700, Houston, Texas, 77010, USA, hereby certify:

1. That I am a Consulting Petroleum Engineer employed by Huddleston & Co., Inc., which company has prepared a report on the interests for Coastal Energy Company during the months of January 2011 through March 2011.

2. That Huddleston & Co., Inc.’s officers or its employees are independent of Coastal Energy Company, its directors, senior management and advisers; have no direct or indirect interests, nor do they expect to receive any direct or indirect interest, in the properties or in any securities of Coastal Energy Company.

3. That Huddleston & Co., Inc. is registered with the Texas Board of Professional Engineers (Registration Number F-001024). That I attended Texas A&M University and that I graduated with a Bachelor of Science in Petroleum Engineering in 1982 and with a Master of Science in Petroleum Engineering in 1984. That I am a registered Professional Engineer in the state of Texas since 1990 and am a member of both the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and that I have in excess of twenty-six years experience in engineering studies and the evaluation of oil and gas properties in the USA, Canada, Argentina, Colombia, Guatemala, Kazakhstan, Kuwait, North Sea, Turkmenistan, and Russia.

4. That I am a qualified evaluator and auditor as defined in National Instrument 51-101.

5. That a personal field inspection of the Company’s property was not conducted due to the availability of published data from the State-owned company and public data.

John P. Krawtz, P.E. Professional Engineer Texas Reg. No. 67593

APPENDIX D:

Canadian Form 51-101 F2




PHONE (713) 209-1100 FAX (713) 752-0828

FORM 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

To the board of directors of Coastal Energy Company (the “Company”):

1. We have evaluated the Company’s reserves data as at December 31, 2010. The reserves data consist of the following:

(i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2010 using forecast prices and costs; and

(ii) the related estimated net revenue

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year-ended December 31, 2010, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s Board of Directors:

Independent Qualified Reserves Evaluator

Description and Preparation Date of Evaluation Report

Location of Reserves Net Present Value of Future Net Revenue (before income taxes, 10% discount rate)

Evaluated Total Huddleston & Co., Inc.

Coastal Energy Company in the G5-43 Offshore Block, December 31, 2010

Gulf of Thailand – Offshore Thailand

US$1,189,480,860

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not evaluate.

FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR Page Two


6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

John P. Krawtz, P.E. Huddleston & Co., Inc. Houston, Texas, USA March 21, 2011

APPENDIX E:

Definitions of Reserves and Resources

1

SPE Petroleum Resources Management System Guide for Non-Technical Users

_________________________________________________________ This guide is to help non-technical users understand how the petroleum industry assesses and quantifies the major driver of value for exploration and production companies – oil and natural gas reserves and resources. Clear terms and definitions that result in reliable and easily comparable reserves estimations are essential for investors, regulators, governments and consumers not only in assessing a petroleum company’s current and future value, but in determining the outlook for the world’s energy supply. Completed in 2007, the PRMS provides updated definitions and the related classification system for petroleum reserves and resources that reflect advances in technology, the international expansion and the increasing role of unconventional resources in the industry. These updated definitions establish a universal language which can be used for estimating and classifying quantities of oil and gas discovered in a reservoir. SPE’s Role in Developing the PRMS For decades, the SPE has been a leader in developing the technical definitions that have become the industry standard for evaluating petroleum reserves and resources. The SPE historically draws together the scientific and engineering expertise of the global oil industry in this effort. The PRMS is the result of more than two years of collaboration by the SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE), with considerable input from the industry at large. The new system builds on the previous set of definitions and incorporates best practices identified in other international petroleum and mineral classification systems. These technical definitions are offered for any company, agency, country or other stakeholder to use. Fundamentals of the PRMS Oil and gas reserves and resources are defined as volumes that will be commercially recovered in the future. Unlike the inventory of a manufacturing company, reserves are physically located in reservoirs deep underground and cannot be visually inspected or counted, but rather are estimates based on the evaluation of data that provides evidence of the amount of oil and gas present. There is no definitive answer until the end of a reservoir's producing life. All reserve estimates involve some degree of uncertainty. The estimation of reserves volumes is generally performed by highly-skilled individuals who use their experience and professional judgment in the calculation of those volumes. To take into account this uncertainty, the PRMS incorporates a central framework that categorizes reserves and resources according to the level of certainty associated with their recoverable volumes (horizontal axis in the figure below), and classifies them according to the potential for reaching commercial producing status (vertical axis).

2


Reserves

Production

ProspectiveResources

Unrecoverable

Dis

cove

red

Sub

-com

mer

cial

Com

mer

cial

Und

isco

vere

d

Unrecoverable

chance of discovery


Reserves

ProspectiveResources

Dis

cove

red

Sub

-com

mer

cial

Com

mer

cial

Und

isco

vere

d

Categorize based primarily on technical uncertainty of sales quantities associated with a project

chance of discovery

Classify by Chance of

Commerciality (Risk)of project applied

Chance of Commerciality (Risk)

of project applied

Chance of Commerciality (Risk)

of project applied

chance of development



chance of discovery

PROVED PROBABLE POSSIBLE

When applying PRMS, technical specialists must determine a specific project that will be used to recover the reserves and resources and determine the chance that it will be commercially successful, then must estimate the volume expected to be recovered from the “project.” It is important to remember when applying the PRMS that, as shown above, reserves are a subset of resources. Differences in Classes (Vertical Axis) The four major recoverable resources classes defined by the PRMS are production, reserves, contingent resources, and prospective resources. There is also a distinct class for unrecoverable petroleum. These classes are shown on the vertical axis of the PRMS framework. Production is the quantity of oil and natural gas that has been recovered already (by a specified date). This is primarily output from operations that has already been produced for use by consumers. Reserves represent that part of resources which are commercially recoverable and have been justified for development, while contingent and prospective resources are less certain because some significant commercial or technical hurdle must be overcome prior to there being confidence in the eventual production of the volumes.

3

Contingent resources are less certain than reserves. These are resources that are potentially recoverable but not yet considered mature enough for commercial development due to technological or business hurdles. For contingent resources to move into the reserves category, the key conditions, or contingencies, that prevented commercial development must be clarified and removed. As an example, all required internal and external approvals should be in place or determined to be forthcoming, including environmental and governmental approvals. There also must be evidence of firm intention by a company’s management to proceed with development within a reasonable time frame (typically 5 years, though it could be longer). Prospective resources are estimated volumes associated with undiscovered accumulations. These represent quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from oil and gas deposits identified on the basis of indirect evidence but which have not yet been drilled. This class represents a higher risk than contingent resources since the risk of discovery is also added. For prospective resources to become classified as contingent resources, hydrocarbons must be discovered, the accumulations must be further evaluated and an estimate of quantities that would be recoverable under appropriate development projects prepared. Some petroleum will be classified as “unrecoverable” at this point in time, not being producible by any projects that the company may plan or foresee. While a portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur, some of the remaining portion may never be recovered due to physical or chemical constraints in the reservoir. The volumes classified using the system represent the analysis of the day, and should be regularly reviewed and updated, as necessary, to reflect changing conditions. A project may have recoverable quantities in several resource classes simultaneously. As barriers to development are removed, some resources may move to a higher classification. One of the primary distinctions between resources and reserves is that while resources are technically recoverable, they may not be commercially viable. Reserves are always commercially viable and there is intent development them. Differences in Categories (Horizontal Axis) Within any resource class other than production, volumes are placed into different categories based on their certainty of eventually coming out of the ground. Decisions to upgrade volumes to any category within a class are generally based on the technical certainty of recovering the volumes. In this discussion, the focus is on the reserve class, as these volumes are commonly the focus of public discussions of oil and gas company producing assets. The highest valued category of reserves is “proved” reserves. Proved reserves have a “reasonable certainty” of being recovered, which means a high degree of confidence that the volumes will be recovered. To be clear, reserves must have all commercial aspects addressed. It is technical issues which separate proved from unproved categories. “Probable” or “possible” reserves are lower categories of reserves, commonly combined and referred to as “unproved reserves,” with decreasing levels of technical certainty. Probable reserves are volumes that are defined as “less likely to be recovered than proved, but more certain to be recovered than Possible Reserves”. Possible reserves are reserves which analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves.

4

The term 1P is frequently used to denote proved reserves, 2P is the sum of proved and probable reserves and 3P the sum of proved, probable and possible reserves. The best estimate of recovery from committed projects is generally considered to be the 2P sum of proved and probable reserves. Note that these volumes only refer to projects that are currently justified for or already in development. Total value of any resource base must include an assessment of the contingent and prospective resources as well as reserves. In order for volumes to move from one category to the next, the technical issues which cause them to be placed in less certain categories must be resolved. In the majority of cases, this requires that additional data must be obtained before any greater certainty can be recognized. This may include, among other things, the drilling of additional wells, the monitoring of current production to better understand performance or the implementation of a pilot to have greater confidence in the volumes that full scale development projects may eventually produce. Conclusion The PRMS is designed to provide a framework for the classification of oil and gas volumes which a company may have associated with its portfolio of assets. It is not specific to any particular geographic location and can be applied to both conventional and unconventional reserves and resources anywhere in the world, in any fiscal regime. When summarizing these volumes, some key points must be kept in mind: 1) All oil and gas reserve and resource volumes are not the same, and should generally not be added

together without taking into consideration the risk and uncertainty associated with each volume. Some volumes are clearly less certain and more risky than others. Whether the focus is only on reserves, or on the resource base as a whole (remember, reserves are a subset of resources!), expressing these volumes as one number may be misleading.

2) Risk and uncertainty are key but significantly different concepts. Risk is primarily associated with the classification of volumes and is a measure of the certainty of a project progressing to production. Uncertainty is the driver for categorization and is a measure of the technical factors impacting the volumes ultimate producibility.

3) The PRMS was developed as a collaborative system, designed to support a wide group of stakeholders. Throughout the early drafting stages, advice and input was sought not only from the petroleum industry, but from the financial, accounting, governmental sectors, in addition to the mining industry.

The PRMS is available on the SPE website at http://www.spe.org/spe-app/spe/industry/reserves/index.htm. It is highly recommended that users visit the website to gain a deeper understanding of the terms and definitions, learn more about the system and its application, and other aspects of reserves and resources estimation.

DEFINITIONS USED FOR RESERVE CATEGORIES

The following reserves definitions are set out by the Canadian Securities Administrators in National Instrument 51-101 (NI51-101; in Part 2 of Appendix 1 to Companion Policy 51-101CP) with reference to the COGE Handbook.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from know accumulations, from a given date forward, based on:

• analysis of drilling, geological, geophysical, and engineering data;

• the use of established technology;

• specified economic conditions1, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classified according to the degree of certainty associated with the estimates.

Proved Reserves

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Other criteria that must also be met for the categorization of reserves are provided in [Section 5.5 of the COGE Handbook].

Development and Production Status

Each of the reserves categories (proved, probable, and possible) may be divided into developed and undeveloped categories.

Developed Reserves

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

1 For the purposes of NI 51-101, the key economic assumptions will be the prices and costs used in the estimate, namely: (a) constant prices and costs as at the last day of a reporting issuer’s financial year; or (b) forecast prices and costs.

DEFINITIONS USED FOR RESERVE CATEGORIES Page Two Developed Producing Reserves

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be know with reasonable certainty.

Developed Non-Producing Reserves

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

Undeveloped Reserves

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves estimates are presented). Reported Reserves should target the following levels of certainty under a specific set of economic conditions:

• at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;

• at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves;

• at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5.5.3 [of the COGE Handbook].

Incorporation of these guidelines means that total corporate proved reserves reflect a conservative estimated and proved plus probable reserves reflect a current “best estimate” of the oil and gas quantities which will be recovered.

APPENDIX F:

Detailed Cash Flow Projections Forecast Price Case – Net to Coastal Energy


Offshore Property Evaluation

(Proved + Probable + Possible)

Table 1.1 Data

Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011

Cash FlowNet Reserves Net Revenue

Ownership Group :

Project Name : As of Date:

Economic One-Liners

Reserve Category

2:59:50PM

COASTAL - FORECAST CASE - 3P

Coastal Net Interests

Disc. 10%

(M$)Risked / UnRisked

12/31/2010

Grand Total 2,057,428.30 2,680,539.87 228,234.72 439,894.01 0.00 0.00 3,348,668.60 0.00Total 8.00 39,501.30

Proved Rsv Class 618,045.95 732,470.45 52,111.09 353,026.92 0.00 0.00 1,137,608.46 0.00Total 8.00 13,457.81

Proved Rsv Class

Producing Rsv Category 319,287.55 364,417.29 34,878.87 353,026.92 0.00 0.00 752,323.08 0.00Total 8.00 8,879.94

Non-Producing Rsv Category 44,066.53 49,125.89 3,310.74 0.00 0.00 0.00 52,436.63 0.00Total 3.70 632.93

Undeveloped Rsv Category 254,691.87 318,927.27 13,921.48 0.00 0.00 0.00 332,848.75 0.00Total 6.86 3,944.95

Probable Rsv Class 571,434.91 744,686.05 155,611.01 52,987.82 0.00 0.00 953,284.87 0.00Total 8.00 11,297.71

Probable Rsv Class

Non-Producing Rsv Category 180,126.33 234,150.70 5,335.91 0.00 0.00 0.00 239,486.61 0.00Total 5.56 2,851.42

Undeveloped Rsv Category 391,308.58 510,535.35 150,275.10 52,987.82 0.00 0.00 713,798.26 0.00Total 8.00 8,446.29

Possible Rsv Class 867,947.44 1,203,383.37 20,512.62 33,879.28 0.00 0.00 1,257,775.27 0.00Total 8.00 14,745.78

Possible Rsv Class

Non-Producing Rsv Category 234,779.69 324,404.22 0.00 0.00 0.00 0.00 324,404.22 0.00Total 5.88 3,815.20

Undeveloped Rsv Category 633,167.74 878,979.15 20,512.62 33,879.28 0.00 0.00 933,371.05 0.00Total 8.00 10,930.58

SONGKHLA A Field 1,560,465.35 2,036,335.04 132,518.09 303,274.90 0.00 0.00 2,472,128.03 0.00Total 8.00 29,126.86

SONGKHLA A Field

EOCENE Reservoir 411,472.00 559,262.20 85,220.79 13,839.82 0.00 0.00 658,322.81 0.00Total 8.00 7,747.19

SONGKHLA A Field

EOCENE Reservoir

Proved Non-Producing Rsv Class & Category 4,190.22 4,327.36 482.77 0.00 0.00 0.00 4,810.13 0.00Total 2.19 58.19

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00P-NP 0.00SONGKHLA A07 (SI 12/10)

4,327.36 4,190.22 2.19 0.00 0.00 4,810.13 0.00 0.00 482.77P-NP 58.19SONGKHLA A11 (w/o Perfs)

SONGKHLA A Field

EOCENE Reservoir

Proved Undeveloped Rsv Class & Category 31,102.90 34,090.87 0.00 0.00 0.00 0.00 34,090.87 0.00Total 1.62 412.40

11,363.62 10,367.63 1.62 0.00 0.00 11,363.62 0.00 0.00 0.00P-UD 137.47SONGKHLA A07 ST

11,363.62 10,367.63 1.62 0.00 0.00 11,363.62 0.00 0.00 0.00P-UD 137.47SONGKHLA A0A LOC

11,363.62 10,367.63 1.62 0.00 0.00 11,363.62 0.00 0.00 0.00P-UD 137.47SONGKHLA A0C LOC

SONGKHLA A Field

EOCENE Reservoir

Probable Undeveloped Rsv Class & Category 147,487.44 195,736.54 64,225.40 13,839.82 0.00 0.00 273,801.76 0.00Total 8.00 3,228.59

TRC Eco One Liner.rpt 1

Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011


Ownership Group :


Economic One-Liners

Reserve Category

2:59:50PM



Disc. 10%


12/31/2010

17,708.69 15,793.10 2.75 0.00 0.00 21,796.78 0.00 0.00 4,088.10PR-UD 263.69SONGKHLA A0E LOC

17,708.69 15,793.10 2.75 0.00 0.00 21,796.78 0.00 0.00 4,088.10PR-UD 263.69SONGKHLA A0F LOC

114,073.42 79,849.25 7.43 0.00 0.00 138,602.00 0.00 0.00 24,528.57PR-UD 1,620.83SONGKHLA A - EOCENE A 6 Wells

75,536.97 56,422.71 6.88 0.00 0.00 91,606.20 0.00 0.00 16,069.23PR-UD 1,080.37SONGKHLA A - EOCENE B 4 Wells

-13,839.82 -7,060.12 8.00 0.00 0.00 0.00 0.00 13,839.82 0.00PR-UD 0.00SONGKHLA A - PROB LOE

-15,451.41 -13,310.59 3.00 0.00 0.00 0.00 0.00 0.00 15,451.41PR-UD 0.00SONGKHLA A - EOCENE CAPITAL

SONGKHLA A Field

EOCENE Reservoir

Possible Undeveloped Rsv Class & Category 228,691.44 325,107.43 20,512.62 0.00 0.00 0.00 345,620.05 0.00Total 6.48 4,048.02

54,346.24 39,076.24 6.48 0.00 0.00 66,610.52 0.00 0.00 12,264.29PS-UD 784.36SONGKHLA A - EOCENE A 3 Wells

226,568.52 157,942.53 6.29 0.00 0.00 226,568.52 0.00 0.00 0.00PS-UD 2,643.75SONGKHLA A - EOCENE A POSS

44,192.68 31,672.67 4.78 0.00 0.00 52,441.01 0.00 0.00 8,248.34PS-UD 619.91SONGKHLA A - EOCENE B 2 Wells

SONGKHLA A Field

OLIGOCENE Reservoir 1,148,993.35 1,477,072.85 47,297.30 289,435.08 0.00 0.00 1,813,805.22 0.00Total 8.00 21,379.67

SONGKHLA A Field

OLIGOCENE Reservoir

Proved Producing Rsv Class & Category 297,496.45 347,649.79 23,756.59 284,465.35 0.00 0.00 655,871.72 0.00Total 8.00 7,717.33

181,448.41 134,158.29 8.00 0.00 0.00 181,931.18 0.00 0.00 482.77P-DP 2,117.89SONGKHLA A01

-482.77 -187.49 0.00 0.00 0.00 0.00 0.00 0.00 482.77P-DP 0.00SONGKHLA A02 (SI 10/09)

136,937.68 104,663.18 8.00 0.00 0.00 137,420.44 0.00 0.00 482.77P-DP 1,610.18SONGKHLA A03

38,826.48 33,388.06 4.02 0.00 0.00 39,309.25 0.00 0.00 482.77P-DP 473.37SONGKHLA A04

-422.42 -164.05 0.00 0.00 0.00 0.00 0.00 0.00 422.42P-DP 0.00SONGKHLA A05 (Injector)

-422.42 -164.05 0.00 0.00 0.00 0.00 0.00 0.00 422.42P-DP 0.00SONGKHLA A06 (Injector)

84,454.13 67,471.98 6.38 0.00 0.00 84,936.90 0.00 0.00 482.77P-DP 1,006.11SONGKHLA A08

121,266.09 95,934.18 7.38 0.00 0.00 121,748.86 0.00 0.00 482.77P-DP 1,435.33SONGKHLA A09

90,042.32 73,042.46 6.32 0.00 0.00 90,525.08 0.00 0.00 482.77P-DP 1,074.46SONGKHLA A12 ST

-284,465.35 -200,215.30 8.00 0.00 0.00 0.00 0.00 284,465.35 0.00P-DP 0.00SONGKHLA A - PDP LOE

-19,532.37 -10,430.82 3.00 0.00 0.00 0.00 0.00 0.00 19,532.37P-DP 0.00SONGKHLA A - PDP CAPITAL

SONGKHLA A Field

OLIGOCENE Reservoir

Proved Undeveloped Rsv Class & Category 223,588.97 284,836.40 13,921.48 0.00 0.00 0.00 298,757.88 0.00Total 6.86 3,532.55


Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011


Ownership Group :


Economic One-Liners

Reserve Category

2:59:50PM



Disc. 10%


12/31/2010

96,271.50 75,496.49 6.83 0.00 0.00 102,158.37 0.00 0.00 5,886.87P-UD 1,208.07SONGKHLA A07 ST

97,885.08 78,444.27 6.69 0.00 0.00 101,902.39 0.00 0.00 4,017.31P-UD 1,206.91SONGKHLA A0A LOC

90,679.81 69,648.21 6.86 0.00 0.00 94,697.12 0.00 0.00 4,017.31P-UD 1,117.57SONGKHLA A0C LOC

SONGKHLA A Field

OLIGOCENE Reservoir

Probable Non-Producing Rsv Class & Category 141,793.34 187,882.24 1,584.62 0.00 0.00 0.00 189,466.86 0.00Total 5.00 2,253.16

12,588.65 10,773.17 3.46 0.00 0.00 14,173.27 0.00 0.00 1,584.62PR-NP 171.06SONGKHLA A11 (w/o Perfs)

175,293.59 131,020.17 5.00 0.00 0.00 175,293.59 0.00 0.00 0.00PR-NP 2,082.10SONGKHLA A - MAIN FB PROB INCREMENTAL

SONGKHLA A Field

OLIGOCENE Reservoir

Probable Undeveloped Rsv Class & Category 151,811.20 192,429.30 8,034.61 0.00 0.00 0.00 200,463.91 0.00Total 6.69 2,374.93

93,862.08 75,100.77 6.69 0.00 0.00 97,879.38 0.00 0.00 4,017.31PR-UD 1,158.80SONGKHLA A0B LOC

98,567.22 76,710.44 6.05 0.00 0.00 102,584.53 0.00 0.00 4,017.31PR-UD 1,216.13SONGKHLA A0D LOC

SONGKHLA A Field

OLIGOCENE Reservoir

Possible Non-Producing Rsv Class & Category 223,395.22 309,972.08 0.00 0.00 0.00 0.00 309,972.08 0.00Total 5.88 3,642.49

6,878.38 5,637.58 2.57 0.00 0.00 6,878.38 0.00 0.00 0.00PS-NP 83.24SONGKHLA A11 POSS NP

303,093.70 217,757.64 5.88 0.00 0.00 303,093.70 0.00 0.00 0.00PS-NP 3,559.25SONGKHLA A - MAIN FB POSS INCREMENTAL

SONGKHLA A Field

OLIGOCENE Reservoir

Possible Undeveloped Rsv Class & Category 110,908.16 154,303.04 0.00 4,969.72 0.00 0.00 159,272.77 0.00Total 8.00 1,859.21

16,925.91 13,595.35 3.10 0.00 0.00 16,925.91 0.00 0.00 0.00PS-UD 204.54SONGKHLA A - SA09 FB POSS INCREMENTAL

142,346.86 99,668.47 7.53 0.00 0.00 142,346.86 0.00 0.00 0.00PS-UD 1,654.68SONGKHLA A - SA12 FB POSS INCREMENTAL

-4,969.72 -2,355.66 8.00 0.00 0.00 0.00 0.00 4,969.72 0.00PS-UD 0.00SONGKHLA A - POSS LOE

SONGKHLA C (BUA BAN) Field 496,962.95 644,204.83 95,716.63 136,619.12 0.00 0.00 876,540.57 0.00Total 7.00 10,374.44

SONGKHLA C (BUA BAN) Field

EOCENE Reservoir 73,694.00 94,171.43 32,591.84 0.00 0.00 0.00 126,763.27 0.00Total 5.54 1,514.14


Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011


Ownership Group :


Economic One-Liners

Reserve Category

2:59:50PM



Disc. 10%


12/31/2010


EOCENE Reservoir


4,387.98 3,978.93 2.18 0.00 0.00 4,387.98 0.00 0.00 0.00P-NP 53.08SONGKHLA C04 (w/o Frac)


EOCENE Reservoir

Probable Non-Producing Rsv Class & Category 21,644.83 25,805.45 3,751.29 0.00 0.00 0.00 29,556.74 0.00Total 4.95 354.06

12,902.72 10,822.42 4.95 0.00 0.00 14,778.37 0.00 0.00 1,875.65PR-NP 177.03SONGKHLA C04 (w/o Frac)

12,902.72 10,822.42 4.95 0.00 0.00 14,778.37 0.00 0.00 1,875.65PR-NP 177.03SONGKHLA C07 (w/o Frac)


EOCENE Reservoir

Probable Undeveloped Rsv Class & Category 21,758.11 30,818.38 28,840.55 0.00 0.00 0.00 59,658.93 0.00Total 5.54 711.22

9,452.76 7,163.02 5.29 0.00 0.00 14,874.40 0.00 0.00 5,421.64PR-UD 177.57SONGKHLA G01

9,452.76 7,163.02 5.29 0.00 0.00 14,874.40 0.00 0.00 5,421.64PR-UD 177.57SONGKHLA G04

5,956.43 3,716.03 5.54 0.00 0.00 14,955.06 0.00 0.00 8,998.63PR-UD 178.04SONGKHLA C HORZ #4

5,956.43 3,716.03 5.54 0.00 0.00 14,955.06 0.00 0.00 8,998.63PR-UD 178.04SONGKHLA C HORZ #5


EOCENE Reservoir

Possible Undeveloped Rsv Class & Category 26,312.13 33,159.63 0.00 0.00 0.00 0.00 33,159.63 0.00Total 5.53 395.76

16,579.82 13,156.06 5.53 0.00 0.00 16,579.82 0.00 0.00 0.00PS-UD 197.88SONGKHLA C HORZ #4

16,579.82 13,156.06 5.53 0.00 0.00 16,579.82 0.00 0.00 0.00PS-UD 197.88SONGKHLA C HORZ #5


MIOCENE Reservoir 35,105.39 42,442.95 473.29 0.00 0.00 0.00 42,916.23 0.00Total 5.56 513.92


MIOCENE Reservoir

Proved Producing Rsv Class & Category 7,032.77 7,547.79 473.29 0.00 0.00 0.00 8,021.08 0.00Total 2.58 97.02

7,547.79 7,032.77 2.58 0.00 0.00 8,021.08 0.00 0.00 473.29P-DP 97.02SONGKHLA C11 MIOCENE


Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011


Ownership Group :


Economic One-Liners

Reserve Category

2:59:50PM



Disc. 10%


12/31/2010


MIOCENE Reservoir

Probable Non-Producing Rsv Class & Category 16,688.15 20,463.01 0.00 0.00 0.00 0.00 20,463.01 0.00Total 5.56 244.20

20,463.01 16,688.15 5.56 0.00 0.00 20,463.01 0.00 0.00 0.00PR-NP 244.20SONGKHLA C11 MIOCENE


MIOCENE Reservoir

Possible Non-Producing Rsv Class & Category 11,384.47 14,432.14 0.00 0.00 0.00 0.00 14,432.14 0.00Total 4.93 172.71

14,432.14 11,384.47 4.93 0.00 0.00 14,432.14 0.00 0.00 0.00PS-NP 172.71SONGKHLA C11 MIOCENE


OLIGOCENE MAIN Reservoir 272,616.39 371,823.20 44,783.18 68,057.55 0.00 0.00 484,663.92 0.00Total 7.00 5,679.42


OLIGOCENE MAIN Reservoir

Proved Producing Rsv Class & Category 3,527.91 3,614.61 473.29 0.00 0.00 0.00 4,087.90 0.00Total 2.12 49.45

3,614.61 3,527.91 2.12 0.00 0.00 4,087.90 0.00 0.00 473.29P-DP 49.45SONGKHLA C03 - MAIN



Proved Non-Producing Rsv Class & Category 2,864.47 2,290.10 2,677.72 0.00 0.00 0.00 4,967.82 0.00Total 2.06 60.10

666.25 797.36 2.02 0.00 0.00 1,590.98 0.00 0.00 924.73P-NP 19.25SONGKHLA C01 - MAIN (w/o Perfs)

2,452.11 2,422.52 2.06 0.00 0.00 3,376.84 0.00 0.00 924.73P-NP 40.85SONGKHLA C02 - MAIN (w/o Perfs)

-414.13 -177.71 0.00 0.00 0.00 0.00 0.00 0.00 414.13P-NP 0.00SONGKHLA C08 (Injector)

-414.13 -177.71 0.00 0.00 0.00 0.00 0.00 0.00 414.13P-NP 0.00SONGKHLA C09 (Injector)



Probable Undeveloped Rsv Class & Category 62,649.65 82,395.58 41,632.17 39,148.00 0.00 0.00 163,175.74 0.00Total 7.00 1,929.41

36,695.53 27,019.49 5.41 0.00 0.00 40,774.15 0.00 0.00 4,078.62PR-UD 482.75SONGKHLA G01 - MAIN - PROB

36,695.53 27,019.49 5.41 0.00 0.00 40,774.15 0.00 0.00 4,078.62PR-UD 482.75SONGKHLA G04 - MAIN - PROB

33,271.36 24,448.12 6.59 0.00 0.00 40,813.73 0.00 0.00 7,542.37PR-UD 481.96SONGKHLA C HORZ #2 - MAIN

33,271.36 24,448.12 6.59 0.00 0.00 40,813.73 0.00 0.00 7,542.37PR-UD 481.96SONGKHLA C HORZ #3 - MAIN

-39,148.00 -24,394.17 7.00 0.00 0.00 0.00 0.00 39,148.00 0.00PR-UD 0.00SONGKHLA C PROB - LOE

-18,390.20 -15,891.40 3.00 0.00 0.00 0.00 0.00 0.00 18,390.20PR-UD 0.00SONGKHLA C - CAPITAL


Lease Name Life

(years)

Oil

(Mbbl)

Gas

(MMcf)

Gas

(M$)

Oil

(M$)

Other

(M$)

Expense

& Tax

(M$)Invest.

(M$)

Non-Disc.

(M$)

3/23/2011


Ownership Group :


Economic One-Liners

Reserve Category

2:59:50PM



Disc. 10%


12/31/2010



Possible Undeveloped Rsv Class & Category 203,574.36 283,522.91 0.00 28,909.55 0.00 0.00 312,432.46 0.00Total 7.00 3,640.46

312,432.46 219,541.93 6.93 0.00 0.00 312,432.46 0.00 0.00 0.00PS-UD 3,640.46SONGKHLA C - MAIN - POSS

-28,909.55 -15,967.57 7.00 0.00 0.00 0.00 0.00 28,909.55 0.00PS-UD 0.00SONGKHLA C POSS - LOE


OLIGOCENE WEDGE Reservoir 115,547.16 135,767.25 17,868.33 68,561.57 0.00 0.00 222,197.15 0.00Total 4.90 2,666.96


OLIGOCENE WEDGE Reservoir

Proved Producing Rsv Class & Category 11,230.42 5,605.10 10,175.71 68,561.57 0.00 0.00 84,342.38 0.00Total 4.83 1,016.14

21,522.70 18,934.31 3.94 0.00 0.00 21,995.99 0.00 0.00 473.29P-DP 265.10SONGKHLA C05 - WEDGE



-68,561.57 -57,241.14 4.83 0.00 0.00 0.00 0.00 68,561.57 0.00P-DP 0.00SONGKHLA C PDP - LOE

-8,755.84 -3,757.25 3.00 0.00 0.00 0.00 0.00 0.00 8,755.84P-DP 0.00SONGKHLA C - CAPITAL




38,120.46 33,032.91 3.70 0.00 0.00 38,270.71 0.00 0.00 150.25P-NP 461.55SONGKHLA C05 - WEDGE (w/o Perfs)



Probable Undeveloped Rsv Class & Category 7,602.18 9,155.55 7,542.37 0.00 0.00 0.00 16,697.92 0.00Total 2.27 202.14

9,155.55 7,602.18 2.27 0.00 0.00 16,697.92 0.00 0.00 7,542.37PR-UD 202.14SONGKHLA C HORZ #1- WEDGE



Possible Undeveloped Rsv Class & Category 63,681.66 82,886.14 0.00 0.00 0.00 0.00 82,886.14 0.00Total 4.90 987.13

82,886.14 63,681.66 4.90 0.00 0.00 82,886.14 0.00 0.00 0.00PS-UD 987.13SONGKHLA C HORZ #1 - WEDGE


Net

Gas

(MMcf)

As Of Date :

Discount Rate (%) : 10.00

All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

ECONOMIC SUMMARY PROJECTION03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

4,916.88



GRAND TOTAL CASE

Total

12/31/2010

82.76 0.00 6,488.52 0.00 5,843.96 0.00 483,645.73 0.00 0.002011

82.51 0.00 9,504.17 0.00 8,425.04 0.00 695,150.21 0.00 0.002012

82.76 0.00 10,129.76 0.00 8,956.80 0.00 741,264.67 0.00 0.002013

84.76 0.00 7,171.32 0.00 6,441.40 0.00 545,973.17 0.00 0.002014

87.93 0.00 5,326.26 0.00 4,826.98 0.00 424,436.58 0.00 0.002015

90.31 0.00 3,401.23 0.00 3,125.10 0.00 282,227.57 0.00 0.002016

93.02 0.00 1,608.68 0.00 1,517.14 0.00 141,124.01 0.00 0.002017

95.50 0.00 384.09 0.00 364.89 0.00 34,846.66 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

51.002011 0.00 0.00 94,368.76 55,241.95 0.00 334,035.03 0.00 0.00 316,051.71

72.002012 0.00 0.00 77,772.08 56,347.82 0.00 561,030.31 0.00 0.00 795,884.48

72.002013 0.00 0.00 7,282.80 57,473.73 0.00 676,508.15 0.00 0.00 1,325,129.02

58.002014 0.00 0.00 0.00 58,623.20 0.00 487,349.97 0.00 0.00 1,670,068.55

53.002015 0.00 0.00 0.00 59,769.55 0.00 364,667.03 0.00 0.00 1,903,756.47

43.002016 0.00 0.00 0.00 60,992.69 0.00 221,234.88 0.00 0.00 2,032,317.94

33.002017 0.00 0.00 0.00 62,211.41 0.00 78,912.60 0.00 0.00 2,074,290.65

8.002018 0.00 0.00 0.00 29,233.67 0.00 5,612.99 0.00 0.00 2,077,139.19

0.002019 0.00 0.00 18,517.42 0.00 0.00 -18,517.42 0.00 0.00 2,069,193.12

0.002020 0.00 0.00 30,293.67 0.00 0.00 -30,293.67 0.00 0.00 2,057,428.30

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 228,234.72 439,894.01 0.00 2,680,539.87 0.00

0.00 0.00

0.00

0.00

2,057,428.30

0.00 0.00

84.77 0.00

0.00

48,930.91 0.00

0.00 0.00 0.00 0.00 0.00 0.00

44,014.03 0.00 39,501.30 0.00 3,348,668.60 0.00 0.00

Disc. Initial Invest. (M$) :

ROInvestment (disc/undisc) :

Years to Payout :

12.27 / 12.74

0.60

Internal ROR (%) :

Present Worth Profile (M$)

5.00% :10.00% :15.00% :

PWPWPWPWPW

2,342,363.07 2,057,428.30 1,816,607.64

20.00% :50.00% :

1,612,320.79 872,077.86

PW 628,546.2770.00% :

182,526.90

>1000

Hud Eco Detailed.rpt 1

Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

ECONOMIC SUMMARY PROJECTION

Proved Rsv Class

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

4,916.88



REPORT BREAK SUB-TOTAL CASE

Total

12/31/2010

82.76 0.00 4,552.04 0.00 4,149.53 0.00 343,415.41 0.00 0.002011

82.51 0.00 3,125.42 0.00 2,889.37 0.00 238,402.25 0.00 0.002012

82.76 0.00 2,171.44 0.00 2,030.80 0.00 168,068.94 0.00 0.002013

84.76 0.00 1,697.94 0.00 1,600.82 0.00 135,685.73 0.00 0.002014

87.93 0.00 1,140.59 0.00 1,078.30 0.00 94,814.79 0.00 0.002015

90.31 0.00 923.61 0.00 874.88 0.00 79,010.76 0.00 0.002016

93.02 0.00 613.66 0.00 582.98 0.00 54,228.78 0.00 0.002017

95.50 0.00 264.34 0.00 251.12 0.00 23,981.81 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

26.002011 0.00 0.00 18,575.66 55,241.95 0.00 269,597.80 0.00 0.00 256,459.45

26.002012 0.00 0.00 0.00 56,347.82 0.00 182,054.43 0.00 0.00 414,070.21

23.002013 0.00 0.00 0.00 57,473.73 0.00 110,595.21 0.00 0.00 500,598.73

15.002014 0.00 0.00 0.00 51,309.77 0.00 84,375.97 0.00 0.00 560,381.15

12.002015 0.00 0.00 0.00 40,018.40 0.00 54,796.39 0.00 0.00 595,512.08

9.002016 0.00 0.00 0.00 40,698.96 0.00 38,311.80 0.00 0.00 617,753.14

9.002017 0.00 0.00 0.00 31,430.97 0.00 22,797.80 0.00 0.00 629,893.73

4.002018 0.00 0.00 0.00 20,505.33 0.00 3,476.48 0.00 0.00 631,595.35

0.002019 0.00 0.00 12,897.12 0.00 0.00 -12,897.12 0.00 0.00 626,061.03

0.002020 0.00 0.00 20,638.32 0.00 0.00 -20,638.32 0.00 0.00 618,045.95

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 52,111.09 353,026.92 0.00 732,470.45 0.00

0.00 0.00

0.00

0.00

618,045.95

0.00 0.00

84.53 0.00

0.00

19,405.91 0.00

0.00 0.00 0.00 0.00 0.00 0.00

14,489.03 0.00 13,457.81 0.00 1,137,608.46 0.00 0.00



Years to Payout :

20.62 / 15.06

0.19

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

671,824.63 618,045.95 570,591.66

20.00% :50.00% :

528,781.99 361,226.56

PW 296,692.2470.00% :

31,505.27

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Proved Rsv ClassProducing Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

4,835.18




Total

12/31/2010

82.76 0.00 2,850.78 0.00 2,598.71 0.00 215,069.24 0.00 0.002011

82.51 0.00 1,935.02 0.00 1,788.88 0.00 147,600.71 0.00 0.002012

82.76 0.00 1,487.30 0.00 1,390.97 0.00 115,116.84 0.00 0.002013

84.76 0.00 1,185.18 0.00 1,117.39 0.00 94,709.88 0.00 0.002014

87.93 0.00 774.88 0.00 732.57 0.00 64,414.61 0.00 0.002015

90.31 0.00 630.29 0.00 597.04 0.00 53,918.34 0.00 0.002016

93.02 0.00 424.49 0.00 403.26 0.00 37,511.64 0.00 0.002017

95.50 0.00 264.34 0.00 251.12 0.00 23,981.81 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

15.002011 0.00 0.00 5,049.34 55,241.95 0.00 154,777.95 0.00 0.00 148,161.45

15.002012 0.00 0.00 0.00 56,347.82 0.00 91,252.90 0.00 0.00 227,074.05

15.002013 0.00 0.00 0.00 57,473.73 0.00 57,643.11 0.00 0.00 272,206.32

11.002014 0.00 0.00 0.00 51,309.77 0.00 43,400.12 0.00 0.00 302,965.68

9.002015 0.00 0.00 0.00 40,018.40 0.00 24,396.22 0.00 0.00 318,633.73

6.002016 0.00 0.00 0.00 40,698.96 0.00 13,219.39 0.00 0.00 326,333.77

6.002017 0.00 0.00 0.00 31,430.97 0.00 6,080.67 0.00 0.00 329,623.78

4.002018 0.00 0.00 0.00 20,505.33 0.00 3,476.48 0.00 0.00 331,325.40

0.002019 0.00 0.00 11,122.28 0.00 0.00 -11,122.28 0.00 0.00 326,552.68

0.002020 0.00 0.00 18,707.24 0.00 0.00 -18,707.24 0.00 0.00 319,287.55

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 34,878.87 353,026.92 0.00 364,417.29 0.00

0.00 0.00

0.00

0.00

319,287.55

0.00 0.00

84.72 0.00

0.00

14,387.47 0.00

0.00 0.00 0.00 0.00 0.00 0.00

9,552.29 0.00 8,879.94 0.00 752,323.08 0.00 0.00



Years to Payout :

19.96 / 11.45

0.17

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

341,353.11 319,287.55 298,777.90

20.00% :50.00% :

280,023.17 200,066.35

PW 167,850.5670.00% :

16,844.05

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Proved Rsv ClassNon-Producing Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

81.70




Total

12/31/2010

82.76 0.00 317.48 0.00 289.41 0.00 23,951.48 0.00 0.002011

82.51 0.00 209.33 0.00 193.52 0.00 15,967.62 0.00 0.002012

82.76 0.00 104.71 0.00 97.93 0.00 8,104.42 0.00 0.002013

84.76 0.00 55.22 0.00 52.07 0.00 4,413.10 0.00 0.002014

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002015

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002016

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002017

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

5.002011 0.00 0.00 1,053.14 0.00 0.00 22,898.34 0.00 0.00 21,695.66

5.002012 0.00 0.00 0.00 0.00 0.00 15,967.62 0.00 0.00 35,499.69

5.002013 0.00 0.00 0.00 0.00 0.00 8,104.42 0.00 0.00 41,851.25

1.002014 0.00 0.00 0.00 0.00 0.00 4,413.10 0.00 0.00 45,015.62

0.002015 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 45,015.62

0.002016 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 45,015.62

0.002017 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 45,015.62

0.002018 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 45,015.62

0.002019 0.00 0.00 1,774.83 0.00 0.00 -1,774.83 0.00 0.00 44,254.01

0.002020 0.00 0.00 482.77 0.00 0.00 -482.77 0.00 0.00 44,066.53

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 3,310.74 0.00 0.00 49,125.89 0.00

0.00 0.00

0.00

0.00

44,066.53

0.00 0.00

82.85 0.00

0.00

768.44 0.00

0.00 0.00 0.00 0.00 0.00 0.00

686.75 0.00 632.93 0.00 52,436.63 0.00 0.00



Years to Payout :

23.18 / 15.84

0.25

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

46,574.25 44,066.53 41,664.54

20.00% :50.00% :

39,399.05 28,805.60

PW 24,013.8770.00% :

1,986.56

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Proved Rsv ClassUndeveloped Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

82.76 0.00 1,383.77 0.00 1,261.41 0.00 104,394.69 0.00 0.002011

82.51 0.00 981.06 0.00 906.97 0.00 74,833.91 0.00 0.002012

82.76 0.00 579.43 0.00 541.90 0.00 44,847.67 0.00 0.002013

84.76 0.00 457.54 0.00 431.37 0.00 36,562.75 0.00 0.002014

87.93 0.00 365.70 0.00 345.73 0.00 30,400.18 0.00 0.002015

90.31 0.00 293.32 0.00 277.85 0.00 25,092.41 0.00 0.002016

93.02 0.00 189.17 0.00 179.72 0.00 16,717.14 0.00 0.002017

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

6.002011 0.00 0.00 12,473.18 0.00 0.00 91,921.51 0.00 0.00 86,602.33

6.002012 0.00 0.00 0.00 0.00 0.00 74,833.91 0.00 0.00 151,496.47

3.002013 0.00 0.00 0.00 0.00 0.00 44,847.67 0.00 0.00 186,541.17

3.002014 0.00 0.00 0.00 0.00 0.00 36,562.75 0.00 0.00 212,399.85

3.002015 0.00 0.00 0.00 0.00 0.00 30,400.18 0.00 0.00 231,862.74

3.002016 0.00 0.00 0.00 0.00 0.00 25,092.41 0.00 0.00 246,403.75

3.002017 0.00 0.00 0.00 0.00 0.00 16,717.14 0.00 0.00 255,254.34

0.002018 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 255,254.34

0.002019 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 255,254.34

0.002020 0.00 0.00 1,448.30 0.00 0.00 -1,448.30 0.00 0.00 254,691.87

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 13,921.48 0.00 0.00 318,927.27 0.00

0.00 0.00

0.00

0.00

254,691.87

0.00 0.00

84.37 0.00

0.00

4,250.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

4,250.00 0.00 3,944.95 0.00 332,848.75 0.00 0.00



Years to Payout :

21.09 / 23.91

0.21

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

283,897.27 254,691.87 230,149.22

20.00% :50.00% :

209,359.78 132,354.61

PW 104,827.8170.00% :

12,674.66

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Probable Rsv Class

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

82.76 0.00 1,936.48 0.00 1,694.42 0.00 140,230.32 0.00 0.002011

82.51 0.00 3,367.59 0.00 2,958.51 0.00 244,106.40 0.00 0.002012

82.76 0.00 2,858.90 0.00 2,537.25 0.00 209,983.04 0.00 0.002013

84.76 0.00 1,953.16 0.00 1,760.40 0.00 149,211.13 0.00 0.002014

87.93 0.00 1,489.90 0.00 1,365.64 0.00 120,080.34 0.00 0.002015

90.31 0.00 687.74 0.00 641.85 0.00 57,965.30 0.00 0.002016

93.02 0.00 311.74 0.00 293.58 0.00 27,309.23 0.00 0.002017

95.50 0.00 48.49 0.00 46.06 0.00 4,399.09 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

23.002011 0.00 0.00 75,793.10 0.00 0.00 64,437.23 0.00 0.00 59,592.26

32.002012 0.00 0.00 66,956.09 0.00 0.00 177,150.30 0.00 0.00 210,927.97

32.002013 0.00 0.00 0.00 0.00 0.00 209,983.04 0.00 0.00 375,313.37

27.002014 0.00 0.00 0.00 7,313.44 0.00 141,897.70 0.00 0.00 475,745.52

26.002015 0.00 0.00 0.00 16,253.05 0.00 103,827.29 0.00 0.00 542,258.95

23.002016 0.00 0.00 0.00 12,510.75 0.00 45,454.56 0.00 0.00 568,750.76

16.002017 0.00 0.00 0.00 13,151.97 0.00 14,157.26 0.00 0.00 576,294.77

2.002018 0.00 0.00 0.00 3,758.61 0.00 640.48 0.00 0.00 576,658.96

0.002019 0.00 0.00 5,620.30 0.00 0.00 -5,620.30 0.00 0.00 574,247.22

0.002020 0.00 0.00 7,241.51 0.00 0.00 -7,241.51 0.00 0.00 571,434.91

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 155,611.01 52,987.82 0.00 744,686.05 0.00

0.00 0.00

0.00

0.00

571,434.91

0.00 0.00

84.38 0.00

0.00

12,654.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

12,654.00 0.00 11,297.71 0.00 953,284.87 0.00 0.00



Years to Payout :

5.24 / 5.79

1.08

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

651,050.59 571,434.91 503,582.23

20.00% :50.00% :

445,585.15 231,666.32

PW 160,053.4870.00% :

134,799.99

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Probable Rsv ClassNon-Producing Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

82.76 0.00 293.23 0.00 256.58 0.00 21,234.28 0.00 0.002011

82.51 0.00 743.15 0.00 652.88 0.00 53,868.88 0.00 0.002012

82.76 0.00 964.38 0.00 855.88 0.00 70,832.72 0.00 0.002013

84.76 0.00 690.93 0.00 622.74 0.00 52,783.11 0.00 0.002014

87.93 0.00 494.03 0.00 452.83 0.00 39,817.23 0.00 0.002015

90.31 0.00 11.28 0.00 10.52 0.00 950.39 0.00 0.002016

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002017

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

4.002011 0.00 0.00 3,906.56 0.00 0.00 17,327.72 0.00 0.00 16,203.06

5.002012 0.00 0.00 0.00 0.00 0.00 53,868.88 0.00 0.00 61,891.78

5.002013 0.00 0.00 0.00 0.00 0.00 70,832.72 0.00 0.00 117,266.99

5.002014 0.00 0.00 0.00 0.00 0.00 52,783.11 0.00 0.00 154,645.56

4.002015 0.00 0.00 0.00 0.00 0.00 39,817.23 0.00 0.00 180,157.77

1.002016 0.00 0.00 0.00 0.00 0.00 950.39 0.00 0.00 180,720.00

0.002017 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 180,720.00

0.002018 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 180,720.00

0.002019 0.00 0.00 946.58 0.00 0.00 -946.58 0.00 0.00 180,313.81

0.002020 0.00 0.00 482.77 0.00 0.00 -482.77 0.00 0.00 180,126.33

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 5,335.91 0.00 0.00 234,150.70 0.00

0.00 0.00

0.00

0.00

180,126.33

0.00 0.00

83.99 0.00

0.00

3,197.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

3,197.00 0.00 2,851.42 0.00 239,486.61 0.00 0.00



Years to Payout :

41.32 / 44.88

0.35

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

205,021.80 180,126.33 158,796.00

20.00% :50.00% :

140,470.50 72,106.75

PW 49,070.3970.00% :

4,467.36

590.61


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Probable Rsv ClassUndeveloped Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

82.76 0.00 1,643.25 0.00 1,437.84 0.00 118,996.04 0.00 0.002011

82.51 0.00 2,624.44 0.00 2,305.63 0.00 190,237.52 0.00 0.002012

82.76 0.00 1,894.52 0.00 1,681.37 0.00 139,150.32 0.00 0.002013

84.76 0.00 1,262.24 0.00 1,137.66 0.00 96,428.02 0.00 0.002014

87.93 0.00 995.86 0.00 912.81 0.00 80,263.12 0.00 0.002015

90.31 0.00 676.46 0.00 631.32 0.00 57,014.92 0.00 0.002016

93.02 0.00 311.74 0.00 293.58 0.00 27,309.23 0.00 0.002017

95.50 0.00 48.49 0.00 46.06 0.00 4,399.09 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

19.002011 0.00 0.00 71,886.53 0.00 0.00 47,109.51 0.00 0.00 43,389.20

27.002012 0.00 0.00 66,956.09 0.00 0.00 123,281.43 0.00 0.00 149,036.19

27.002013 0.00 0.00 0.00 0.00 0.00 139,150.32 0.00 0.00 258,046.38

22.002014 0.00 0.00 0.00 7,313.44 0.00 89,114.59 0.00 0.00 321,099.96

22.002015 0.00 0.00 0.00 16,253.05 0.00 64,010.07 0.00 0.00 362,101.18

22.002016 0.00 0.00 0.00 12,510.75 0.00 44,504.17 0.00 0.00 388,030.76

16.002017 0.00 0.00 0.00 13,151.97 0.00 14,157.26 0.00 0.00 395,574.76

2.002018 0.00 0.00 0.00 3,758.61 0.00 640.48 0.00 0.00 395,938.96

0.002019 0.00 0.00 4,673.73 0.00 0.00 -4,673.73 0.00 0.00 393,933.40

0.002020 0.00 0.00 6,758.75 0.00 0.00 -6,758.75 0.00 0.00 391,308.58

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 150,275.10 52,987.82 0.00 510,535.35 0.00

0.00 0.00

0.00

0.00

391,308.58

0.00 0.00

84.51 0.00

0.00

9,457.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

9,457.00 0.00 8,446.29 0.00 713,798.26 0.00 0.00



Years to Payout :

4.00 / 4.40

1.19

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

446,028.79 391,308.58 344,786.23

20.00% :50.00% :

305,114.65 159,559.58

PW 110,983.0870.00% :

130,332.63

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Possible Rsv Class

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002011

82.51 0.00 3,011.16 0.00 2,577.16 0.00 212,641.56 0.00 0.002012

82.76 0.00 5,099.42 0.00 4,388.75 0.00 363,212.69 0.00 0.002013

84.76 0.00 3,520.21 0.00 3,080.18 0.00 261,076.31 0.00 0.002014

87.93 0.00 2,695.78 0.00 2,383.05 0.00 209,541.45 0.00 0.002015

90.31 0.00 1,789.89 0.00 1,608.37 0.00 145,251.51 0.00 0.002016

93.02 0.00 683.28 0.00 640.57 0.00 59,586.00 0.00 0.002017

95.50 0.00 71.27 0.00 67.70 0.00 6,465.76 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.002011 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

14.002012 0.00 0.00 10,815.98 0.00 0.00 201,825.58 0.00 0.00 170,886.30

17.002013 0.00 0.00 7,282.80 0.00 0.00 355,929.89 0.00 0.00 449,216.92

16.002014 0.00 0.00 0.00 0.00 0.00 261,076.31 0.00 0.00 633,941.88

15.002015 0.00 0.00 0.00 3,498.10 0.00 206,043.34 0.00 0.00 765,985.43

11.002016 0.00 0.00 0.00 7,782.98 0.00 137,468.53 0.00 0.00 845,814.03

8.002017 0.00 0.00 0.00 17,628.46 0.00 41,957.53 0.00 0.00 868,102.15

2.002018 0.00 0.00 0.00 4,969.72 0.00 1,496.03 0.00 0.00 868,884.87

0.002019 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 868,884.87

0.002020 0.00 0.00 2,413.84 0.00 0.00 -2,413.84 0.00 0.00 867,947.44

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 20,512.62 33,879.28 0.00 1,203,383.37 0.00

0.00 0.00

0.00

0.00

867,947.44

0.00 0.00

85.30 0.00

0.00

16,871.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

16,871.00 0.00 14,745.78 0.00 1,257,775.27 0.00 0.00



Years to Payout :

54.51 / 59.67

1.32

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

1,019,487.84 867,947.44 742,433.75

20.00% :50.00% :

637,953.65 279,184.97

PW 171,800.5570.00% :

16,221.63

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Possible Rsv ClassNon-Producing Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002011

82.51 0.00 833.89 0.00 713.70 0.00 58,887.52 0.00 0.002012

82.76 0.00 1,270.52 0.00 1,093.46 0.00 90,494.70 0.00 0.002013

84.76 0.00 969.44 0.00 848.26 0.00 71,898.78 0.00 0.002014

87.93 0.00 768.12 0.00 679.01 0.00 59,705.69 0.00 0.002015

90.31 0.00 535.02 0.00 480.76 0.00 43,417.53 0.00 0.002016

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

0.002011 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

3.002012 0.00 0.00 0.00 0.00 0.00 58,887.52 0.00 0.00 49,646.66

3.002013 0.00 0.00 0.00 0.00 0.00 90,494.70 0.00 0.00 120,401.49

2.002014 0.00 0.00 0.00 0.00 0.00 71,898.78 0.00 0.00 171,253.07

2.002015 0.00 0.00 0.00 0.00 0.00 59,705.69 0.00 0.00 209,483.37

1.002016 0.00 0.00 0.00 0.00 0.00 43,417.53 0.00 0.00 234,779.69

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 0.00 0.00 0.00 324,404.22 0.00

0.00 0.00

0.00

0.00

234,779.69

0.00 0.00

85.03 0.00

0.00

4,377.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

4,377.00 0.00 3,815.20 0.00 324,404.22 0.00 0.00



Years to Payout :

0.00 / 0.00

0.00

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

275,355.04 234,779.69 201,058.77

20.00% :50.00% :

172,906.24 75,669.56

PW 46,437.0970.00% :

0.00

0.00


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Possible Rsv ClassUndeveloped Rsv Category

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

0.00




Total

12/31/2010

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002011

82.51 0.00 2,177.27 0.00 1,863.46 0.00 153,754.04 0.00 0.002012

82.76 0.00 3,828.89 0.00 3,295.29 0.00 272,717.99 0.00 0.002013

84.76 0.00 2,550.77 0.00 2,231.92 0.00 189,177.53 0.00 0.002014

87.93 0.00 1,927.66 0.00 1,704.03 0.00 149,835.75 0.00 0.002015

90.31 0.00 1,254.87 0.00 1,127.60 0.00 101,833.98 0.00 0.002016

93.02 0.00 683.28 0.00 640.57 0.00 59,586.00 0.00 0.002017

95.50 0.00 71.27 0.00 67.70 0.00 6,465.76 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

2.002011 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

11.002012 0.00 0.00 10,815.98 0.00 0.00 142,938.06 0.00 0.00 121,239.64

14.002013 0.00 0.00 7,282.80 0.00 0.00 265,435.19 0.00 0.00 328,815.42

14.002014 0.00 0.00 0.00 0.00 0.00 189,177.53 0.00 0.00 462,688.81

13.002015 0.00 0.00 0.00 3,498.10 0.00 146,337.65 0.00 0.00 556,502.06

10.002016 0.00 0.00 0.00 7,782.98 0.00 94,051.00 0.00 0.00 611,034.34

8.002017 0.00 0.00 0.00 17,628.46 0.00 41,957.53 0.00 0.00 633,322.45

2.002018 0.00 0.00 0.00 4,969.72 0.00 1,496.03 0.00 0.00 634,105.18

0.002019 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 634,105.18

0.002020 0.00 0.00 2,413.84 0.00 0.00 -2,413.84 0.00 0.00 633,167.74

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 20,512.62 33,879.28 0.00 878,979.15 0.00

0.00 0.00

0.00

0.00

633,167.74

0.00 0.00

85.39 0.00

0.00

12,494.00 0.00

0.00 0.00 0.00 0.00 0.00 0.00

12,494.00 0.00 10,930.58 0.00 933,371.05 0.00 0.00



Years to Payout :

40.03 / 43.85

1.37

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

744,132.80 633,167.74 541,374.97

20.00% :50.00% :

465,047.41 203,515.41

PW 125,363.4770.00% :

16,221.63

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year

ECONOMIC SUMMARY PROJECTION03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

4,916.88



GRAND TOTAL CASE

Total

12/31/2010

82.76 0.00 6,488.52 0.00 5,843.96 0.00 483,645.73 0.00 0.002011

82.51 0.00 9,504.17 0.00 8,425.04 0.00 695,150.21 0.00 0.002012

82.76 0.00 10,129.76 0.00 8,956.80 0.00 741,264.67 0.00 0.002013

84.76 0.00 7,171.32 0.00 6,441.40 0.00 545,973.17 0.00 0.002014

87.93 0.00 5,326.26 0.00 4,826.98 0.00 424,436.58 0.00 0.002015

90.31 0.00 3,401.23 0.00 3,125.10 0.00 282,227.57 0.00 0.002016

93.02 0.00 1,608.68 0.00 1,517.14 0.00 141,124.01 0.00 0.002017

95.50 0.00 384.09 0.00 364.89 0.00 34,846.66 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

51.002011 0.00 0.00 94,368.76 55,241.95 0.00 334,035.03 0.00 0.00 316,051.71

72.002012 0.00 0.00 77,772.08 56,347.82 0.00 561,030.31 0.00 0.00 795,884.48

72.002013 0.00 0.00 7,282.80 57,473.73 0.00 676,508.15 0.00 0.00 1,325,129.02

58.002014 0.00 0.00 0.00 58,623.20 0.00 487,349.97 0.00 0.00 1,670,068.55

53.002015 0.00 0.00 0.00 59,769.55 0.00 364,667.03 0.00 0.00 1,903,756.47

43.002016 0.00 0.00 0.00 60,992.69 0.00 221,234.88 0.00 0.00 2,032,317.94

33.002017 0.00 0.00 0.00 62,211.41 0.00 78,912.60 0.00 0.00 2,074,290.65

8.002018 0.00 0.00 0.00 29,233.67 0.00 5,612.99 0.00 0.00 2,077,139.19

0.002019 0.00 0.00 18,517.42 0.00 0.00 -18,517.42 0.00 0.00 2,069,193.12

0.002020 0.00 0.00 30,293.67 0.00 0.00 -30,293.67 0.00 0.00 2,057,428.30

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 228,234.72 439,894.01 0.00 2,680,539.87 0.00

0.00 0.00

0.00

0.00

2,057,428.30

0.00 0.00

84.77 0.00

0.00

48,930.91 0.00

0.00 0.00 0.00 0.00 0.00 0.00

44,014.03 0.00 39,501.30 0.00 3,348,668.60 0.00 0.00



Years to Payout :

12.27 / 12.74

0.60

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

2,342,363.07 2,057,428.30 1,816,607.64

20.00% :50.00% :

1,612,320.79 872,077.86

PW 628,546.2770.00% :

182,526.90

>1000


Net

Gas

(MMcf)

As Of Date :


All Cases

Misc.

Revenue

(M$)

Gas

Revenue

(M$)

Oil

Revenue

(M$)

Gas

Price

($/Mcf)

Oil

Price

($/bbl)

Net

Oil

(Mbbl)

Gross

Gas

(MMcf)

Gross

Oil

(Mbbl)

Year


Proved Rsv Class

03/23/2011 2:53:23PMDate :

0.00

Project Name :

Partner :

Case Type :

Cum Oil (Mbbl) :

Cum Gas (MMcf) :

4,916.88




Total

12/31/2010

82.76 0.00 4,552.04 0.00 4,149.53 0.00 343,415.41 0.00 0.002011

82.51 0.00 3,125.42 0.00 2,889.37 0.00 238,402.25 0.00 0.002012

82.76 0.00 2,171.44 0.00 2,030.80 0.00 168,068.94 0.00 0.002013

84.76 0.00 1,697.94 0.00 1,600.82 0.00 135,685.73 0.00 0.002014

87.93 0.00 1,140.59 0.00 1,078.30 0.00 94,814.79 0.00 0.002015

90.31 0.00 923.61 0.00 874.88 0.00 79,010.76 0.00 0.002016

93.02 0.00 613.66 0.00 582.98 0.00 54,228.78 0.00 0.002017

95.50 0.00 264.34 0.00 251.12 0.00 23,981.81 0.00 0.002018

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002019

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002020

Rem

Total

Ult

Year

Net Tax

Production

(M$)

Net Tax

AdValorem

(M$)

Net

Investment

(M$)

Net

Lease Costs

(M$)

Net

Well Costs

(M$)

Annual

Cash Flow

(M$)

Cum Disc.

Cash Flow

(M$)

Other

Costs

(M$)

Well

Count

Net

Profits

(M$)

26.002011 0.00 0.00 18,575.66 55,241.95 0.00 269,597.80 0.00 0.00 256,459.45

26.002012 0.00 0.00 0.00 56,347.82 0.00 182,054.43 0.00 0.00 414,070.21

23.002013 0.00 0.00 0.00 57,473.73 0.00 110,595.21 0.00 0.00 500,598.73

15.002014 0.00 0.00 0.00 51,309.77 0.00 84,375.97 0.00 0.00 560,381.15

12.002015 0.00 0.00 0.00 40,018.40 0.00 54,796.39 0.00 0.00 595,512.08

9.002016 0.00 0.00 0.00 40,698.96 0.00 38,311.80 0.00 0.00 617,753.14

9.002017 0.00 0.00 0.00 31,430.97 0.00 22,797.80 0.00 0.00 629,893.73

4.002018 0.00 0.00 0.00 20,505.33 0.00 3,476.48 0.00 0.00 631,595.35

0.002019 0.00 0.00 12,897.12 0.00 0.00 -12,897.12 0.00 0.00 626,061.03

0.002020 0.00 0.00 20,638.32 0.00 0.00 -20,638.32 0.00 0.00 618,045.95

Rem.

Total

0.00 0.00 0.00 0.00 0.00 0.00

0.00 0.00 52,111.09 353,026.92 0.00 732,470.45 0.00

0.00 0.00

0.00

0.00

618,045.95

0.00 0.00

84.53 0.00

0.00

19,405.91 0.00

0.00 0.00 0.00 0.00 0.00 0.00

14,489.03 0.00 13,457.81 0.00 1,137,608.46 0.00 0.00



Years to Payout :

20.62 / 15.06

0.19

Internal ROR (%) :


5.00% :10.00% :15.00% :

PWPWPWPWPW

671,824.63 618,045.95 570,591.66

20.00% :50.00% :

528,781.99 361,226.56

PW 296,692.2470.00% :

31,505.27

>1000
