PTTEP Canada International Finance Limited(incorporated in the Province of Alberta, Canada with limited liability)

Guaranteed by

PTT Exploration and Production Public Company Limited(registered in the Kingdom of Thailand as a public company with limited liability)

U.S.$700,000,000

5.692% Senior Notes due 2021

Interest Payable October 5 and April 5

Issue Price: 100.0%

PTTEP Canada International Finance Limited, a company with limited liability incorporated under the laws of theProvince of Alberta, Canada (the “Issuer”), is offering U.S.$700,000,000 aggregate principal amount of its 5.692% SeniorNotes due 2021 (the “Notes”). The Notes will mature on April 5, 2021. Interest on the Notes will be payable semi-annuallyand interest will accrue from April 5, 2011, and the first payment date is October 5, 2011.

The Notes will be unsecured, rank equally with all of the Issuer’s existing and future senior debt and senior to all of theIssuer’s existing and future subordinated debt. The Notes will be effectively subordinated to all of the Issuer’s future secureddebt to the extent of the value of the assets securing such debt and effectively subordinated to all future debt of the Issuer’ssubsidiaries. The Notes will be guaranteed (the “Guarantee”) on a senior basis by PTT Exploration and Production PublicCompany Limited (“PTTEP”). The Guarantee will be unsecured, rank equally with all of PTTEP’s existing and future seniordebt and senior to all of PTTEP’s existing and future subordinated debt.

The Issuer may redeem the Notes in whole, but not in part, at any time at a price equal to their principal amount plusany accrued but unpaid interest, in the event of certain tax changes as described under “Description of the Notes — OptionalTax Redemption.” For a more detailed description of the Notes, see “Description of the Notes” beginning on page 102.

See “Risk Factors” beginning on page 14 for a discussion of certain risks that you should consider in connection withan investment in the Notes.

The Notes and the related Guarantee have not been and will not be registered under the United States Securities Act of1933, as amended (the “Securities Act”), or with any securities regulatory authority of any State or other jurisdiction of theUnited States. Accordingly, the Notes and the related Guarantee are being offered and sold to non-U.S. persons in offshoretransactions in reliance on Regulation S under the Securities Act (“Regulation S”) and within the United States only to qualifiedinstitutional buyers (“QIBs”) in reliance on Rule 144A (“Rule 144A”) under the Securities Act. Prospective purchasers that areQIBs as defined under Rule 144A are hereby notified that the sellers of the Notes and the related Guarantee may be relyingon the exemption from the provisions of Section 5 of the Securities Act provided by Rule 144A. The Notes may not be offeredor sold in Canada or to or for the benefit of residents thereof except to “accredited investors” as defined in National Instrument(Canada) 45-106 “Prospectus and Registration Exemptions” (“Accredited Investors”) or, as the case may be, “permittedclients” as defined in National Instrument (Canada) 31-103 “Registration Requirements and Exemptions” (“PermittedClients”). For a description of restrictions on offers, sales and transfers of the Notes and distribution of this OfferingMemorandum, see “Plan of Distribution” and “Transfer Restrictions.”

Application has been made to the Singapore Exchange Securities Trading Limited (“SGX-ST”) for the listing of theNotes on the Official List of the SGX-ST. Such approval will be granted when the Notes have been admitted to the OfficialList of the SGX-ST. The SGX-ST assumes no responsibility for the correctness of any statements made, reports contained oropinions expressed contained herein. Admission of the Notes to the Official List of the SGX-ST is not to be taken as anindication of the merits of the Notes, the Guarantee, the Issuer, the Guarantor or its subsidiaries. The Notes will be traded onthe SGX-ST in a minimum board lot size of U.S.$200,000 for as long as the Notes are listed on the SGX-ST.

The Issuer expects that delivery of the Notes will be made to investors in book-entry form through The Depository TrustCompany (“DTC”) for the accounts of its direct and indirect participants, including Euroclear Bank S.A./N.V. and Clearstream,Banking, société anonyme (“Clearstream, Banking”), on or about April 5, 2011 (or such other time and date as the Issuer andBarclays Bank PLC may agree).

Lead Manager and Bookrunner

Barclays Capital

The date of this Offering Memorandum is March 29, 2011.

You should rely only on the information contained in this Offering Memorandum or to which the Issuer andthe Guarantor have referred you. The Issuer and the Guarantor have not authorized anyone to provide you withinformation that is different. This Offering Memorandum may only be used where it is legal to sell these securities.The information in this Offering Memorandum may only be accurate as of the date of this Offering Memorandum.

The Issuer and the Guarantor, to the best of their knowledge and belief, having made all reasonable enquires,confirm that (i) this Offering Memorandum contains all information with respect to the Issuer, the Guarantor andthe Notes which is material in the context of the issue and offering of the Notes, (ii) the statements containedherein relating to the Issuer and the Guarantor and the Notes are in every material particular true and accurate andnot misleading, (iii) the opinions and intentions expressed in this Offering Memorandum with regard to the Issueror the Guarantor are honestly held, have been reached after considering all relevant circumstances and are basedon reasonable assumptions, (iv) there are no other facts in relation to the Issuer and the Guarantor or the Notesthe omission of which would, in the context of the issue and offering of the Notes, make any statement in thisOffering Memorandum misleading in any material respect and (v) all reasonable enquiries have been made by theIssuer and the Guarantor to ascertain such facts and to verify the accuracy of all such information and statements.

The Issuer and the Guarantor accept responsibility for the information contained in this OfferingMemorandum. The Issuer and the Guarantor are furnishing this Offering Memorandum on a confidential basis inconnection with an offering exempt from registration under the Securities Act and applicable state securities lawssolely for the purpose of enabling a prospective investor to consider the purchase of the Notes. The informationcontained in this Offering Memorandum has been provided by the Issuer and the Guarantor and other sourcesidentified in this Offering Memorandum. None of the Trustee, Paying Agent, Registrar, Transfer Agents (each asdefined below) or Barclays Bank PLC (the “Initial Purchaser”) has independently verified the informationcontained in this Offering Memorandum. No representation or warranty, express or implied, is made by the InitialPurchaser of the Notes or by their respective U.S. selling agents as to the accuracy or completeness of suchinformation, and nothing contained in this Offering Memorandum and appendices is, or shall be relied upon as,a promise or representation by the Initial Purchaser or such agents and no responsibility or liability is accepted byany of them as to the accuracy or completeness of the information contained or incorporated in this OfferingMemorandum or any other information provided by the Issuer or the Guarantor in connection with the issue ofthe Notes and the Guarantee. None of the Trustee, Paying Agent, Registrar, Transfer Agents (each as definedbelow) or the Initial Purchaser accepts any liability in relation to the information contained or incorporated byreference in this Offering Memorandum or any other information provided by the Issuer or the Guarantor inconnection with the issue of the Notes. Advisers or consultants named in this Offering Memorandum have actedpursuant to the terms of their respective engagements and do not make, and should not be taken to have verified,any statement or information in this Offering Memorandum unless expressly stated otherwise. Any reproductionor distribution of this Offering Memorandum, in whole or in part, and any disclosure of its contents or use of anyinformation herein is prohibited, except to the extent such information is otherwise publicly available. You shouldbe aware that since the date of this Offering Memorandum there may have been changes in PTTEP’s or theIssuer’s business or otherwise that could affect the accuracy or completeness of the information set out in thisOffering Memorandum.

PTTEP’s consolidated financial statements as presented in this Offering Memorandum are prepared andpresented in accordance with generally accepted accounting principles in Thailand (“Thai GAAP”) and reportingpractices in Thailand, which differ in certain significant respects from International Financial Reporting Standards(“IFRS”). For a discussion of differences between Thai GAAP and IFRS that are relevant to PTTEP’s financialstatements, see “Summary of Principal Differences Between Thai GAAP and IFRS.” Potential investors shouldconsult their own professional advisors for an understanding of the differences between Thai GAAP and IFRS, andhow these differences affect the financial information contained in this Offering Memorandum. This OfferingMemorandum should not be considered as a recommendation by the Initial Purchaser that any recipient of thisOffering Memorandum should purchase the Notes.

The securities are subject to restrictions on transferability and resale and may not be transferred or resoldexcept as permitted under the Securities Act and applicable state securities laws pursuant to registration orexemption from registration. You should be aware that you may be required to bear the risk of an investment inthe Notes for an indefinite period of time.

i

Each person receiving this Offering Memorandum acknowledges that: (i) such person has not relied on theInitial Purchaser or any person affiliated with the Initial Purchaser in connection with any investigation of theaccuracy of such information or its investment decision; and (ii) no person has been authorized to give anyinformation or to make any representation concerning the Issuer and/or the Guarantor, their respective subsidiariesand affiliates, the Notes or the Guarantee (other than as contained herein and information given by the dulyauthorized officers and employees of the Issuer and/or the Guarantor in connection with investors’ examinationof the Guarantor and its subsidiaries (including the Issuer) and the terms of this offering of the Notes and theGuarantee (this “Offering”)) and, if given or made, any such other information or representation should not berelied upon as having been authorized by the Issuer, the Guarantor or the Initial Purchaser.

The Notes and the related Guarantee have not been approved or disapproved by any United Statesfederal or state securities commission or regulatory authority (including the United States Securities andExchange Commission) or any securities regulatory body in Canada, nor have any of the foregoingauthorities passed upon or endorsed the merits of this Offering or the accuracy or adequacy of this OfferingMemorandum. Any representation to the contrary is a criminal offense in the United States. Prospectivepurchasers are hereby notified that sellers of the Notes may be relying on the exemption from the provisionsof Section 5 of the Securities Act provided by Rule 144A.

The distribution of this Offering Memorandum and this Offering may in certain jurisdictions be restrictedby law. Persons into whose possession this Offering Memorandum comes are required by the Issuer, the Guarantorand the Initial Purchaser to inform themselves about and to observe any such restrictions. For a description of therestrictions on offers, sales and resales of the Notes and the distribution of this Offering Memorandum, see “Planof Distribution” and “Transfer Restrictions” below.

In making an investment decision, you must rely on your own examination of the Issuer and the Guarantorand the terms of this Offering, including the merits and risks involved. The Issuer and the Guarantor are notmaking any representation to you regarding the legality of an investment in the Notes or the Guarantee by youunder any legal, investment or similar laws or regulations. You should not consider any information in thisOffering Memorandum to be legal, business or tax advice. You should consult your own attorney, business advisorand tax advisor for legal, business and tax advice regarding an investment in the Notes and the Guarantee.

The Issuer and the Guarantor reserve the right to withdraw this Offering at any time, and the InitialPurchaser reserve the right to reject any commitment to subscribe for the Notes in whole or in part and to allotto any prospective purchaser less than the full amount of the Notes sought by such purchaser. The Initial Purchaserand certain related entities may acquire for their own account a portion of the Notes.

In connection with this Offering, certain persons participating in the Offering may engage in transactionsthat stabilize, maintain or otherwise affect the price of the Notes outside of Canada and on a financial marketoperated outside of Canada. Specifically, the Initial Purchaser may bid for and purchase Notes in the open marketto stabilize the price of the Notes. The Initial Purchaser may also over allot the Offering, creating a syndicate shortposition. In addition, the Initial Purchaser may bid for and may stabilize or maintain the market price of the Notesabove market levels that might otherwise prevail. The Initial Purchaser is not required to engage in these activities,and may end these activities at any time in their sole discretion without prior notice. These activities will beundertaken solely for the account of Initial Purchaser, and not for and on behalf of the Issuer or the Guarantor.

Notwithstanding anything in this Offering Memorandum to the contrary, each investor in the Notes (and anyemployee, representative, or other agent of any investor) may disclose to any and all persons, without limitationof any kind, the U.S. federal tax treatment and the U.S. federal tax structure of the transactions contemplated bythis Offering Memorandum and all materials of any kind (including opinions or other tax analyses) that areprovided to it relating to such U.S. federal tax treatment and U.S. federal tax structure.

ii

UNITED STATES INTERNAL REVENUE SERVICE CIRCULAR 230 DISCLOSURE

PURSUANT TO U.S. INTERNAL REVENUE SERVICE CIRCULAR 230, THE ISSUER HEREBYINFORMS YOU THAT THE DESCRIPTION SET FORTH HEREIN WITH RESPECT TO U.S.FEDERAL TAX ISSUES WAS NOT INTENDED OR WRITTEN TO BE USED, AND SUCHDESCRIPTION CANNOT BE USED BY ANY TAXPAYER, FOR THE PURPOSE OF AVOIDING ANYPENALTIES THAT MAY BE IMPOSED ON THE TAXPAYER UNDER THE UNITED STATESINTERNAL REVENUE CODE OF 1986, AS AMENDED. SUCH DESCRIPTION WAS WRITTEN TOSUPPORT THE PROMOTION OR MARKETING OF THE NOTES. TAXPAYERS SHOULD SEEKADVICE BASED ON THEIR PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAXADVISOR.

NO OFFERS OR SALES OF THE NOTES OFFERED PURSUANT TO THIS OFFERINGMEMORANDUM MAY BE MADE IN THAILAND.

NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR ANAPPLICATION FOR A LICENSE HAS BEEN FILED UNDER CHAPTER 421-B OFTHE NEW HAMPSHIRE REVISED STATUTES WITH THE STATE OF NEWHAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELYREGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW HAMPSHIRECONSTITUTES A FINDING BY THE SECRETARY OF STATE OF NEWHAMPSHIRE THAT ANY DOCUMENT FILED UNDER RSA 421-B IS TRUE,COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THEFACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITYOR A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED INANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDEDOR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT ISUNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVEPURCHASER, CUSTOMER OR CLIENT ANY REPRESENTATION INCONSISTENTWITH THE PROVISIONS OF THIS PARAGRAPH.

AVAILABLE INFORMATION

To preserve the exemptions for resales and transfers pursuant to Rule 144A, the Issuer will furnish, upon therequest of a holder of the Notes, such information as is specified in paragraph (d)(4) of Rule 144A under theSecurities Act, to such holder or beneficial owner or to a prospective purchaser of the Notes or interest therein whois a “QIB” within the meaning of Rule 144A, in order to permit compliance by such holder or beneficial ownerwith Rule 144A in connection with the resale of such Notes or beneficial interest therein unless, at the time of suchrequest, the Issuer is subject to the reporting requirements of Section 13 or 15(d) of the United States SecuritiesExchange Act of 1934, as amended (the “Exchange Act”), or is included in the list of foreign private issuers thatclaim exemption from the registration requirements of Section 12(g) of the Exchange Act and therefore is requiredto furnish to the U.S. Securities and Exchange Commission certain information pursuant to Rule 12g3-2(b) underthe Exchange Act.

ENFORCEMENT OF CIVIL LIABILITIES

The Issuer is incorporated in the Province of Alberta, Canada and the Guarantor is incorporated in Thailand.The majority of the directors of the Issuer and all of the directors of the Guarantor are residents of Thailand. Asubstantial portion of the assets of the Issuer and the Guarantor, as the case may be, and the assets of theirrespective directors, are located in Canada or Thailand. As a result, you may not be able to:

• effect service of process upon the Issuer or the Guarantor or these persons outside Canada or Thailand;or

iii

• enforce against the Issuer or the Guarantor or their respective directors judgments obtained in courtsoutside of Canada or Thailand. These judgments include judgments relating to the federal securitieslaws of the United States.

The Issuer has been advised by its Canadian counsel, Stikeman Elliott LLP, that there is doubt as to theenforceability, in original actions in the courts of the Canada, of liabilities predicated solely on the federalsecurities law of the United Sates or any state thereof and as to the enforceability, in the courts of Canada, ofjudgments of U.S. courts obtained in actions predicated upon the civil liability provisions of the federal securitieslaw of the United States or any state thereof. Therefore, it may not be possible to enforce those judgments againstthe Issuer or its directors.

PTTEP’s Thai counsel, Allen & Overy (Thailand) Co., Ltd. has advised PTTEP that Thai courts will notenforce any judgment or order obtained outside Thailand, but a judgment or order from a foreign court, in thediscretion of a court in Thailand, may be admitted as evidence of an obligation in a new proceeding instituted inthat court, which will consider the issue or the evidence before it.

Under the Petroleum Act B.E. 2514 (1971) (as amended), the right to hold a petroleum concession shall notbe subject to execution of judgment. Thus, to the extent investors are entitled to bring a legal action againstPTTEP, they may be limited in their remedies or any recovery, and any Thai proceedings may be limiteddepending on the relevant court’s discretion.

FORWARD-LOOKING STATEMENTS

This Offering Memorandum includes forward-looking statements. These forward-looking statements relateto analyses and other information, which are based on forecasts of future results and estimates of amounts not yetdeterminable. These statements also relate to PTTEP’s future prospects, developments and business strategies.You are cautioned not to rely on these forward-looking statements.

These forward-looking statements include, without limitation, statements relating to:

• PTTEP’s future overall business development and economic performance;

• PTTEP’s estimated financial information regarding, and the future development and economicperformance of, its business;

• PTTEP’s future earnings, cash flow and financial position;

• PTTEP’s expansion plans;

• PTTEP’s business strategy;

• the amount and nature of future exploration, development and other capital expenditures required byPTTEP;

• wells to be drilled by PTTEP;

• future prices and demand for natural gas, crude oil and refined petroleum products;

• estimates of PTTEP’s proved reserves;

• Kai Kos Dehseh Oil Sands Project (“KKD”)’s future development plans, expansion and operations;and

• the liberalization of the Thai gas industry.

Although PTTEP’s management believes that its expectations as reflected by such forward-lookingstatements are reasonable based on information currently available to it, no assurances can be given that suchexpectations will prove to be correct. In addition, PTTEP’s management’s expectations with respect to itsexploration, production and development activities are subject to risks arising from the inherent difficulty ofpredicting the presence, yield or quality of oil and gas reserves, as well as unknown or unforeseen difficulties inextracting or transporting any oil or gas found, or doing so on a commercial basis.

iv

The forward-looking statements reflect PTTEP’s current views with respect to future events and are not aguarantee of future performance. Actual results may differ materially from information contained in theforward-looking statements as a result of a number of factors including:

• fluctuations in prices of natural gas, crude oil and condensate;

• change in estimates of reserves;

• the continued availability of capital and financing;

• general economic and business conditions both globally and regionally and energy demand and supplyin Thailand and Southeast Asia;

• the failure of PTTEP to continue to achieve exploration successes;

• failure or delays by PTTEP in achieving production from development projects or failure to achievetargeted production or sales volumes;

• the achievement of development plans and targets in relation to its projects, including KKD;

• liability for remedial actions and other damages under environmental regulations or associatedthird-party claims; and

• other factors beyond PTTEP’s control.

PTTEP’s risks are more specifically described in “Risk Factors.” If one or more of these risks oruncertainties materialize, or if the underlying assumptions prove incorrect, PTTEP’s actual results may varymaterially from those expected, estimated or projected. PTTEP does not undertake to update its forward-lookingstatements or risk factors to reflect future events or circumstances.

CERTAIN DEFINED TERMS AND CONVENTIONS

Market data and certain industry forecasts used throughout this Offering Memorandum were obtained frominternal surveys, market research, publicly available information and industry publications published by thirdparty sources that PTTEP believes are reliable. Such information has been accurately reproduced herein and, asfar as PTTEP is aware and is able to ascertain from information published by such third parties, no facts have beenomitted that would render the reproduced information inaccurate or misleading. Industry publications generallystate that the information that they contain has been obtained from sources believed to be reliable but that theaccuracy and completeness of that information is not guaranteed. Similarly, internal surveys, industry forecastsand market research, while believed to be reliable, have not been independently verified, and none of the Issuer,the Guarantor or the Initial Purchaser makes any representation as to the accuracy or completeness of thisinformation. The industry in which PTTEP operates is subject to a high degree of uncertainty and risks due to avariety of factors, including those described under “Risk Factors.” These and other factors could cause results todiffer materially from the information contained in such publications, surveys, forecasts and market research.

All references to “Thailand” or “Thai” herein are references to the Kingdom of Thailand. All references tothe “Government” herein are references to the Government of Thailand. All references to “Myanmar” arereferences to the Union of Myanmar, formerly known as Burma.

In this Offering Memorandum, unless otherwise specified or the context otherwise requires, “the Company,”“PTTEP” or “the Guarantor” refers to PTT Exploration and Production Public Company Limited and, unlessotherwise indicated or required by context, PTTEP’s consolidated subsidiaries.

All financial information, descriptions and other information in this Offering Memorandum regardingPTTEP’s activities, financial condition and results of operations are, unless otherwise indicated or required bycontext, presented on a consolidated basis.

v

In this Offering Memorandum, references to “$,” “U.S. dollars,” “U.S.$” and “dollars” are to the currencyof the United States of America, references to “Bt” and “Baht” are to the currency of Thailand and “CAD” and“Canadian dollar” are to the currency of Canada. PTTEP maintains its accounts in Baht and Statoil CanadaPartnership (“SCP”) maintains its accounts in Canadian dollars. This Offering Memorandum contains conversionsof certain amounts into dollars at specified rates solely for the convenience of the reader. Unless otherwiseindicated, all conversions of Baht to dollars have been made at the rate of Baht 30.296 = U.S.$1.00, the averageselling rate announced by the Bank of Thailand on December 30, 2010. See “Exchange Rate Information.” Norepresentation is made that the Baht or dollar amounts referred to herein could have been or could be convertedinto dollars or Baht, as the case may be, at this rate, at any particular rate or at all.

Any discrepancies in the tables included herein between totals and sums of the amounts listed are due torounding.

PRESENTATION OF OIL AND GAS RESERVES DATA

This Offering Memorandum includes estimates made by PTTEP of its gross proved reserves. Noindependent reserve report is available on the gross proved reserves of PTTEP. These estimates are based onPTTEP’s Classification of Petroleum Resources Guidelines, which is substantially similar to the standardsestablished by the Society of Petroleum Engineers (the “SPE”), the SPE Petroleum Resources ManagementSystem. Investors should note, however, that different reserves reporting systems employ different assumptions,and that, in particular, PTTEP’s Classification of Petroleum Resources Guidelines may differ from the standardsestablished by the United States Securities and Exchange Commission. In regards to the reserves and resourcesfigures provided for KKD, PTTEP references the figures from the independent report done by Sproule AssociatesLimited, which is based on the draft Canadian Oil and Gas Evaluation Handbook Vol. 3, Part 3 — DetailedGuidelines for Estimation and Classification of Bitumen and Steam Assisted Gravity Drainage (SAGD) Reservesand Resources, prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and theCanadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the “COGE Handbook”). The COGEHandbook was reviewed in reference to the SPE Petroleum Resources Management System and there is nowbroad alignment between the COGE Handbook and the SPE definitions.

There are uncertainties inherent in estimating quantities of gross proved reserves and in the timing ofdevelopment expenditures and the projection of future rates of production. However, the proved reserve data setout in this Offering Memorandum represents estimates of a high confidence, which according to both the SPEPetroleum Resources Management System and the COGE Handbook, means at least a 90% chance that quantitiesactually recovered will equal or exceed the estimates.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factorsbeyond the control of PTTEP. The reserve data set forth in this Offering Memorandum represent estimatesdetermined by PTTEP according to industry practice. In general, estimates of commercially recoverable oil andnatural gas reserves are based upon a number of variable factors and assumptions, such as geological andgeophysical characteristics of the reservoirs, historical production performance from the properties, the quality andquantity of technical and economic data, prevailing oil and gas prices applicable to a company’s production,engineering judgments, forward-looking commercial and market assumptions, the assumed effects of regulationby Government agencies and future operating costs. All such estimates involve uncertainties, and classificationsof reserves are only attempts to define the degree of likelihood that the reserves will result in revenue for PTTEP.For these reasons, estimates of the commercially recoverable oil and natural gas reserves attributable to anyparticular group of properties, classification of such reserves based on uncertainty of recovery and estimates offuture net revenues expected therefrom, prepared by different engineers or by the same engineers at differenttimes, may vary substantially. In addition, such estimates can be and will be subsequently revised as additionalpertinent data becomes available prompting revision. Actual recoverable reserves may vary significantly fromsuch estimates. See “Risk Factors — Risks Relating to PTTEP’s Business — The reserves data in this OfferingMemorandum are only estimates, there is no independent reserve report available for PTTEP and its actualproduction, revenues and expenditures with respect to its reserves may differ from these estimates.”

vi

When converting natural gas volumes to barrel of oil equivalent (“Boe”), PTTEP uses a formula where theBoe conversion is “volume (MMboe) = volume (BSCF) multiplied by the gross calorific value (“GCV”) of thepetroleum divided by 6,000.” The gross calorific values used to convert gas volume to barrels of oil equivalentare different and vary in each project depending on reservoir fluids composition. The gross calorific value usedfor BOE conversion in reserves estimations and annual production volumes are also different. Ones that used forreserves estimations are the estimated GCV of each project throughout its field life. The GCVs used for productionreports were the actual GCVs that were measured in each month. Generally, the assumed GCV is 1,000 BTU/Cf,so that 1 Boe is equal to 6 MSCF.

For a description of how certain terms relating to reserves and other data are used in this OfferingMemorandum, see “Glossary of Technical Terms.”

PRESENTATION OF FINANCIAL INFORMATION

PTTEP’s financial statements have been prepared in accordance with Thai GAAP. PTTEP’s reportingcurrency is the Thai Baht. After January 1, 2011, PTTEP’s financial statements will be prepared in accordancewith IFRS and the reporting currency will be U.S. dollars. See “Risk Factors — PTTEP may incur significant costsin preparing for and complying with IFRS and may not be able to fully comply with such standards.”

This Offering Memorandum includes unaudited pro forma combined financial information reflecting thecombined results of operations of PTTEP and PTTEP’s 40% interest in SCP, which owns KKD, acquired throughPTTEP’s subsidiary PTTEP Canada Limited (“PTTEP CA”) from two indirect subsidiaries of Statoil ASA(“Statoil”) on a pro forma basis as of and for the year ended December 31, 2010. All such pro forma financialinformation is unaudited and may not be indicative of the results of operations that actually would have beenachieved had PTTEP acquired its interest in SCP as of January 1, 2010 and do not purport to be indicative of futureresults. The audited financial statements of SCP as of and for the year ended December 31, 2010, were preparedin accordance with IFRS.

Certain numerical figures set out in this Offering Memorandum, including financial data presented inmillions or thousands, have been subject to rounding adjustments and, as a result, the totals of the data in thisOffering Memorandum may vary slightly from the actual arithmetic totals of such information. Percentages andamounts reflecting changes over time periods relating to financial and other data set forth in “Management’sDiscussion and Analysis of Financial Condition and Results of Operations” are calculated using the numerical datain PTTEP’s consolidated financial statements or the tabular presentation of other data (subject to rounding)contained in this Offering Memorandum, as applicable, and not using the numerical data in the narrativedescription thereof.

This Offering Memorandum contains supplemental non-GAAP financial measures and ratios that are notrequired by, or presented in accordance with, Thai GAAP.

The term “EBITDA” refers to earnings before interest expenses, taxes, depreciation and amortization.Earnings for calculating PTTEP’s EBITDA include sales revenue and revenue from pipeline transportation.

PTTEP believes that EBITDA is a widely accepted financial indicator of an entity’s operating performanceand an entity’s ability to incur and service debt. EBITDA should not be considered by an investor as alternativesto net income or income from operations, or as indicators of PTTEP’s operating performance or other combinedoperations or cash flow data prepared in accordance with generally accepted accounting principles, or as analternative to cash flows as a measure of liquidity. PTTEP’s computation of EBITDA may differ from similarlytitled computations of other companies.

Further, EBITDA is not a measurement of PTTEP’s financial performance or liquidity under Thai GAAPand should not be considered as an alternative to net income, gross revenues or any other performance measurederived in accordance with Thai GAAP or as an alternative to cash flow from operations or as a measure ofPTTEP’s liquidity.

The non-GAAP financial measures may not be comparable to other similarly titled measures of othercompanies and have limitations as analytical tools and should not be considered in isolation or as a substitute foranalysis of our operating results reported under Thai GAAP.

vii

TABLE OF CONTENTS

Page

OFFERING MEMORANDUM SUMMARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

THE OFFERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

SUMMARY HISTORICAL THAI GAAP CONSOLIDATED FINANCIAL DATA . . . . . . . . . . . . . 9

SUMMARY UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION . . . . . . . . . 11

SUMMARY OPERATING, SALES AND ASSET DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

RISK FACTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

USE OF PROCEEDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

EXCHANGE RATE INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

THE ISSUER . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

THE PETROLEUM INDUSTRY IN THAILAND . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

RELATIONSHIP WITH THE GOVERNMENT AND PTT AND REGULATORY MATTERS . . . . 61

PTTEP CORPORATE STRUCTURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

PRINCIPAL SHAREHOLDERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

MANAGEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

DESCRIPTION OF THE NOTES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

TAXATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

PLAN OF DISTRIBUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

TRANSFER RESTRICTIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126

LEGAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129

INDEPENDENT ACCOUNTANTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

GENERAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

SUMMARY OF PRINCIPAL DIFFERENCES BETWEEN THAI GAAP AND IFRS . . . . . . . . . . . 132

GLOSSARY OF TECHNICAL TERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND AUDITOR’S REPORTS . . . . . F-1

viii

OFFERING MEMORANDUM SUMMARY

This summary may not contain all of the information that is important to you. You should read the entireOffering Memorandum, including the financial statements and related notes, before making an investmentdecision. You should pay special attention to the “Risk Factors” section beginning on page 13 of this OfferingMemorandum to determine whether an investment in the Notes is appropriate for you.

General

PTTEP’s principal activity is the petroleum exploration, production and development of interests in oil andnatural gas and crude oil properties and reserves in Thailand, in neighboring countries and elsewhereinternationally. PTTEP was incorporated in 1985 as the oil and natural gas exploration and production arm of PTT,a state enterprise established to develop and promote Thailand’s petroleum industry and to ensure the security ofThailand’s energy supply. PTT had a 65.32% ownership interest in the Company as of February 15, 2011.

PTTEP conducts a substantial portion of its exploration and production activities through its workinginterests in petroleum concessions operated through joint ventures with international oil and gas companies. UnderPTTEP’s joint venture arrangements, one joint venture participant actively manages the concession as operator inaccordance with the terms of a joint venture agreement. As of January 31, 2011, PTTEP had participation interestsranging from 5.0% to 100.0% in 19 Thai projects, 14 regional projects in neighboring countries and 11international projects. Of these projects, PTTEP has participation interests ranging from 19.3% to 100.0% in fourinvestment projects in Myanmar. PTTEP is also the operator of seven Thai petroleum exploration and developmentprojects in which it holds a 100.0% interest.

PTTEP’s common stock was first listed on the Stock Exchange of Thailand in June 1993. PTTEP’s marketcapitalization as at February 28, 2011 was Baht 555,838 million, making it the second largest publicly tradedcompany in Thailand.

Competitive Strengths

PTTEP believes that its historical success and future prospects are directly related to a combination ofstrengths, including the following.

Leading regional exploration and production company with substantial international exposure

PTTEP is the largest publicly-listed oil and gas exploration and production company in Thailand and aleading oil and gas producer among publicly-listed oil companies in South East Asia. It is also one of the largestindependent exploration and production companies in South East Asia in terms of reserves and production, withgross proved reserves of 1,043 MMboe, as well as production of 304 Kboe/d for the year ended December 31,2010. Given its large size, the Company has the resources and expertise to serve as operator of many of its blocks.

PTTEP believes its large portfolio of blocks offers a diversification of reserves, production and explorationopportunities and risk. It has also diversified internationally, acquiring attractive assets in Australia, Canada, theMiddle East, and North Africa, in addition to acquiring assets in South East Asia. As of January 31, 2011, itsportfolio comprises a total of 44 projects, consisting of a combination of both oil and gas assets. The majority ofthe Company’s reserves are located in Thailand and nearby areas overlapping with Thailand’s neighbors (19blocks), out of which 14 are producing. The remaining 25 projects are located overseas across the Asia Pacific,North American, Middle Eastern and North African regions. The remaining projects, which are not currentlyproducing, are at various stages of exploration and development.

The Company believes its financial and operational strength allows it better access to the domestic andinternational capital markets to fund its acquisition and development costs, as demonstrated by its successfulprevious fund raisings in the capital markets.

Strong relationship with majority shareholder

PTTEP has a strong relationship with its majority shareholder, PTT. PTTEP was founded as the explorationand production arm of PTT in 1985. PTT had a 65.32% ownership interest in PTTEP as of February 15, 2011.Many of PTTEP’s directors and senior managers worked at PTT before working at PTTEP and several membersof PTT’s board of directors are also members of PTTEP’s board of directors.

1

PTT is Thailand’s national energy and petrochemical group and possesses a strong financial position andgovernment backing in the Thai petroleum markets. PTT also purchases substantially all of the natural gasproduction in Thailand, providing 98% of PTTEP’s natural gas sales revenue in 2010. PTT is the largest supplierof petroleum and petrochemical products in Thailand. The relationship with PTT also creates synergies betweenPTTEP and PTT in the natural gas value chain, ensuring access to petroleum production for PTT and a guaranteedcustomer relationship for PTTEP. PTT enjoys a natural monopoly as the owner and operator of Thailand’s entiregas transmission and distribution pipeline system, which PTTEP uses to transport natural gas to PTT. As agovernment corporation, PTT provides leverage and support for PTTEP’s relationships with other governmentbodies and agencies. PTTEP works closely and coordinates with PTT and related government agencies tocollectively outline and implement Thailand’s national petroleum supply plans and policies.

Experienced management team

PTTEP’s senior management team has extensive experience in the oil and gas industry, and most of itsexecutives have been with PTTEP or PTT since PTTEP’s inception in 1985. PTTEP’s management team and staffhave had the opportunity to work closely with foreign partners both within and outside Thailand. PTTEP has beenable to deploy experienced management team members across its geographic operations to implement projects andoversee operations. PTTEP believes that its management team has contributed significantly to its past success andwill continue to contribute to its future growth.

Well-positioned to benefit from Thailand’s increasing energy consumption

PTTEP’s role as the sole investment vehicle for the Government in undertaking exploration and productionactivities and developing a long-term natural gas supply for Thailand plays an important role in developingThailand’s hydrocarbon reserves. In 2010, PTTEP’s sales accounted for approximately 31% of total nationalproduction of petroleum products. In the year ended December 31, 2010, approximately 44% of Thailand’sprimary energy consumption was from natural gas and in that same period natural gas accounted for approximately72% of fuel for power generation by the Electricity Generating Authority of Thailand, independent powerproducers, and small power producers, PTT’s primary customers for natural gas. Natural gas consumption hasexperienced persistent growth, generating a growth rate of 13.1%, from 3,597 MMSCFD in 2009 to 4,039MMSCFD in 2010, according to EPPO.

Strong reserves base to support production growth

PTTEP’s proved undeveloped reserves accounted for approximately 55% of its 1,043 MMboe provedreserves as of December 31, 2010. PTTEP intends to utilize this proved undeveloped reserve base and otherreserve prospects to grow its production and sales. PTTEP has an established track record of growing its reservesand production: during 2010, PTTEP’s average daily sales volume increased approximately 13% compared to2009, while its compound average growth rate for the three years ended December 31, 2010 was 9.8%. Keyprojects for PTTEP’s growth include the development of Arthit North and MT-JDA.

Significant growth, stable margins and competitive cost structure

PTTEP’s sales volumes have increased at a compound annual growth rate of 9.8% over the past three years.This increase is due to contributions in the sales of petroleum from Arthit, which experienced its first full year ofproduction in 2009, Arthit North, which commenced production in 2009, and Malaysia-Thailand JointDevelopment Authority (“MTJDA”) project, which commenced production in February 2010. PTTEP’s EBITDAincreased in line with the sales growth, with a compound annual growth rate of 9.8% reaching Baht 101,708million (U.S.$3.4 billion) in 2010. Since 2008, PTTEP has also maintained EBITDA margins over 65.4%.PTTEP’s finding and development costs are low due to production sharing contracts with various foreign partners.In the years ended December 31, 2008, 2009 and 2010, PTTEP’s finding and development costs were U.S.$15.7per Boe, U.S.$11.1 per Boe and U.S.$13.6 per Boe, respectively. Low finding and development costs allow forthe capital-efficient growth of PTTEP’s business, while its low operating costs further enhance returns andoperating margins. In the years ended December 31, 2008, 2009 and 2010, PTTEP’s lifting costs were U.S.$2.46per Boe, U.S.$3.16 per Boe and U.S.$3.75 per Boe, respectively. PTTEP believes that this is significantly lowerthan the average lifting cost of most other exploration and production companies. Lifting costs consist of fieldoperating expenses. PTTEP kept its lifting costs low through various measures, including more efficient use ofoffshore infrastructure, the adoption of new technology in its operations, renegotiation of supply-chain costs,standardization among existing assets, as well as the adoption of an excellence program to further develop its

2

organizational capacity with a focus on organization restructuring, business process streamlining and optimizingresource allocation. PTTEP believes that its growth of EBITDA and maintenance of its EBITDA margin isevidence of PTTEP’s focused development objectives, synergies with PTT operations as well as its cost structure.These factors allow it to compete effectively, even in a low crude oil price environment.

Strategy

PTTEP’s primary objective as a leading exploration and production company is to enhance its position inthe Southeast Asian region and internationally. Significant elements of PTTEP’s strategy include the following:

Expanding its investment portfolio with a goal towards sustainable growth, and focus on growth by targetingselected acquisitions

PTTEP intends to capitalize on synergies with its subsidiaries and expand its investments and acquisitionsin particular areas including Southeast Asia, Canada and Australia. In addition, PTTEP plans to focus on areas orcountries that it believes have high petroleum potential and those where it has existing projects or interests tomaximize value, including Australia, Indonesia, Vietnam and Canada. PTTEP sees these developments as anopportunity to pursue acquisitions which would create value for it in the long term. PTTEP intends to focus mainlyon business development and transactions with respect to conventional exploration and production projects in thedevelopment and production phase and where the opportunities fit with PTTEP’s corporate culture. However, aswith the acquisition of SCP, PTTEP will also selectively pursue opportunities to invest in unconventionalexploration and production projects characterized by specialized technological expertise and high investment andunit costs (for example, oil sands, deepwater drilling and heavy oil). PTTEP is currently in the study phase ofdeveloping Floating Liquefied Natural Gas (“FLNG”) production, which is an emerging offshore productiontechnology to monetize stranded gas resources. The areas of commercial focus for FLNG production will be inthe Cash/Maple and Oliver fields in the Timor Sea. Both the oil sands and FLNG opportunities resulted fromPTTEP’s continued monitoring and research into “mega trends,” which may provide sustainable long-termgrowth.

Continuing to participate in key regional and international petroleum projects

Since PTTEP was founded as the exploration and production arm of PTT in 1985, PTTEP has benefited fromthe Government’s policy of encouraging Thai participation in exploration and production activities in the region.As a result, PTTEP has participated in key projects in its regional focus areas of the Gulf of Thailand and the Gulfof Martaban, which PTT believes are attractive exploration and development areas due to their reserve potential,relatively low geological risk and finding costs and a developing infrastructure network of gathering systems,pipelines and platforms.

In PTTEP’s early stages of development, working interests were acquired through Government rights.Subsequently, PTTEP successfully developed relationships with leading international oil and gas companies andhas independently negotiated interests in many of its projects. PTTEP has also been able to farm-in to numerousother projects in Thailand and internationally. To farm-in is to acquire an interest in a lease or concession ownedby another operator on which oil or gas has been discovered or is being produced.

PTTEP believes that with its growing regional knowledge base, technical capability and its closerelationships with PTT, the Government and international oil and gas companies, it is well positioned to continueto take advantage of favorable exploration and development opportunities in the region, particularly in Thailandand elsewhere in Southeast Asia, as well as internationally.

Maximize existing assets through production plateau extension initiatives and implementing supply chainsecurity

PTTEP’s sales volume averaged 264,575 Boe/d in 2010, approximately 13% higher than its average salesvolume of 233,756 Boe/d in 2009. From 2008 to 2010, the compound annual growth rate of petroleum sales byvolume was 9.8%. PTTEP intends to increase the production level, production plateau period and production lifeof its existing assets by focusing on maximizing the recovery at its producing projects. PTTEP intends to continueactively developing its large undeveloped proved reserves which accounted for 55% of its proved reserves as ofDecember 31, 2010. PTTEP also expects further resources to be discovered by continuing to explore the areas nearits existing projects. In 2010, PTTEP succeeded in discovering petroleum in 15 of 18 exploration and appraisalwells drilled, which is equivalent to a drilling success rate of 83%.

3

PTTEP is dedicated to ensuring that Thailand has a secure supply of energy to meet its current and futureneeds. To respond to the dynamics of energy demand, PTTEP has closely monitored petroleum demands and hasbeen coordinating with PTT and related government agencies to collectively outline the optimal supply plan.PTTEP also has reviewed and adjusted its production as well as project development plans to match energyrequirements. In 2010, PTTEP conducted a study, provided a detailed evaluation of PTTEP’s competitiveness inselected countries and business technologies, the result of which was integrated into PTTEP’s overall growthstrategy roadmap with prioritized countries and technology to be pursued.

Implementing cost savings initiatives to optimize value from existing assets

PTTEP periodically reviews investment plans for its existing assets and has rescheduled investments witha view toward optimizing asset value. In particular, PTTEP focuses on cost savings initiatives such asrenegotiating procurement spending, so that product quantities and procurement periods are clearly defined inorder to coincide with the prevailing market situation. PTTEP also plans to standardize these initiatives across itsexisting assets. Moreover, PTTEP has initiated programs to improve its project management performance and theoverall efficiency of its production and operation activities.

Strengthen the capability of its operating model through enhancing organizational excellence in accordancewith international standards

PTTEP is instituting programs to enhance the efficiency and productivity of its business operations includingmeasures to accelerate the recruitment process in support of its business expansion activities, as well as toaccelerate the development and improve the skills of its personnel. On the technological side, PTTEP strives tocontinually gain new drilling and exploration competencies. PTTEP will complement these initiatives bydeveloping its structured leadership development program. PTTEP hopes that their initiatives will allow PTTEPto maintain its high level of corporate governance. PTTEP is also strengthening its organizational support tobusiness expansion and long-term growth through reviews and streamlining of the procurement process, theinvestment process and the portfolio management process.

Recent Developments

Acquisition of an Interest in the Kai Kos Dehseh Project

On January 21, 2011, PTTEP, through its subsidiary, PTTEP CA, acquired from two indirect subsidiaries ofStatoil a 40% interest in SCP, a partnership that owns KKD in Alberta, Canada, for consideration of U.S.$2.28billion. Statoil owns the remaining 60% interest in SCP and is the managing partner. PTTEP and Statoil enteredinto several key agreements to govern the sale and their partnership. KKD is an oil sands project, which PTTEPestimates has 3.8 to 4.3 billion Bbls of recoverable Bitumen resources as independently verified by a leadingexternal petroleum consultant. The project is an in-situ oil sands project utilizing SAGD technology, and has anexpected project life of over 40 years. Commercial production began in January 2011. On March 19, 2011, PTTEPand Statoil entered into a memorandum of understanding to jointly investigate future collaboration opportunitiesinternationally.

Oil sands are composed of a mixture of sand, clay and other mineral matter, water and bitumen. The largestproven deposit of oil sands reserves is in Alberta, Canada although deposits also exist in Venezuela, Russia, theUnited States, Madagascar, Albania, Trinidad and Romania. The first oil sands project in Canada began in 1967.The Athabasca region, where KKD is located, is one of three oil sands regions in Alberta. The two extractionmethods used in Canadian oil sands projects are surface mining and in-situ methods. Surface mining is generallyused for oil sands located less than 75 meters from the surface. For deeper deposits, in-situ methods, whichresemble conventional oil drill projects, are used. There are several types of in-situ methods and KKD uses SAGD.The SAGD method injects steam into the earth to heat the bitumen and help separate it from the sand, then it ispumped to the surface. Bitumen extracted from oil sands is so viscous that it does not flow at normal temperatures.It has to be either blended with diluent to be able to flow through a pipeline and sold as blended bitumen orupgraded into synthetic crude oil by bitumen upgraders, which is a process of removing heavy components. Afterone of these two processes are complete, refineries can transform bitumen or synthetic crude oil into variouspetroleum products.

4

PTTEP has included unaudited pro forma combined financial information as of and for the year endedDecember 31, 2010, as well as the audited financial information of SCP as of and for the year ended December31, 2010 elsewhere in this Offering Memorandum to illustrate the pro forma combined results of operationsfollowing the acquisition and provide information on the historical results of operations of SCP. See, “UnauditedPro Forma Combined Financial Information.”

Project Description

KKD is located in Alberta, Canada, approximately 100 km southwest from Fort McMurray, Alberta, Canada.The project includes five fields, Leismer, Corner, Thornbury, Hangingstone, and South Leismer covering 257,200acres. When fully developed, KKD will include four hubs and a total planned project capacity of over 300,000Bbls/d. PTTEP CA has assessed KKD’s reserves using the COGE Handbook for estimating its resources andreserves, which is broadly aligned with the SPE guidelines. Accordingly, PTTEP estimates that the total expectedBitumen resources for the project will be between 3.8 and 4.3 billion Bbls as independently verified by a leadingexternal petroleum consultant. Statoil acquired its interest in the corporate entity holding KKD in June 2007 andhas since invested over U.S.$1.8 billion in the development of the project, exclusive of the acquisition cost.

The first phase of development was a demonstration plant for the Leismer field (“Leismer DemonstrationPlant”). The Leismer Demonstration Plant became operational in December 2010 and commercial productioncommenced in January 2011. It currently has an approved capacity of 40,000 Bbls/d of bitumen and built-inprocessing and well capacity sufficient to raise production to the commercial scale of 18,800 Bbls/d. The LeismerDemonstration Plant is connected via a 75 km pipeline to storage facilities in Cheecham, Alberta.

The KKD project is currently advancing plans for a second phase of development at the Leismer field. Inaddition, KKD is currently developing plans for the Corner field with a production capacity target of 40,000 Bbls/dof bitumen in the first phase.

For more information, see “Risk Factors — Risks Relating to the Acquisition of an interest in SCP.”

Material Agreements

PTTEP indirectly holds its interest in SCP through its wholly-owned subsidiary PTTEP CA. PTTEP CAholds a 40% interest in SCP, which wholly-owns KKD. PTTEP’s relationship with Statoil and SCP is governedby a Partnership Agreement dated January 21, 2011. Under the Partnership Agreement, Statoil is the initialmanaging partner in charge of oversight of the operations of SCP. However, unanimous approval of a managementcommittee representing each of the partners is required for many decisions, including approving changes to, andthe initiation of, project plans, accumulating debt, making expenditures over certain thresholds and othersignificant changes to the operations of KKD.

SCP sells its entire production volume of bitumen to Statoil under a sales agreement entered into as part ofthe acquisition process. The sales agreement is a long-term agreement for the life of SCP or until certainproduction volumes are reached. Once those volumes are reached, PTTEP can exercise its option to take its shareof production. The price of the bitumen is set according to a formula that references market benchmarks andpre-determined adjustments for adjustments for delivery costs, U.S. duties and marketing fees.

5

THE OFFERING

The following is a brief summary of some of the terms of the Notes. For a more detailed description of theterms of the Notes, see “Description of the Notes.” Terms used in this summary and not otherwise defined shallhave the meanings given to them in the Indenture.

Issuer PTTEP Canada International Finance Limited

Guarantor PTT Exploration and Production Public Company Limited.

Offering U.S.$700,000,000 aggregate principal amount of 5.692% Notes due2021 are being offered (i) in the United States to QIBs in reliance onRule 144A and (ii) outside of the United States to non-U.S. personsin reliance on Regulation S. See “Plan of Distribution.”

Issue Price 100.0% of the principal amount of the Notes, plus accrued interest,if any, from the issue date of the Notes.

Maturity Date April 5, 2021.

Interest The Notes will bear interest from and including April 5, 2011, at therate of 5.692% per annum payable semi-annually in arrear onOctober 5 and April 5 of each year up to and excluding the maturitydate, April 5, 2021, with the first interest payment to be made onOctober 5, 2011.

Status The Notes will be unsecured, rank equally with all of the Issuer’sexisting and future senior debt and senior to all of the Issuer’sexisting and future subordinated debt. The Notes will be effectivelysubordinated to all of the Issuer’s future secured debt to the extent ofthe value of the assets securing such debt and effectivelysubordinated to all future debt of the Issuer’s subsidiaries.

Guarantee The Notes will be guaranteed on a senior basis by PTTEP. TheGuarantee will be unsecured, rank equally with all of PTTEP’sexisting and future senior debt and senior to all of PTTEP’s existingand future subordinated debt.

Optional Redemption 100% of the principal amount of the Notes redeemed, plus theApplicable Premium and accrued and unpaid interest, if any, to theredemption date.

Optional Tax Redemption The Notes may be redeemed at the Issuer’s option, in whole but notin part, at a price equal to the principal amount thereof plus accruedand unpaid interest, in certain circumstances in which the Issuer orthe Company would become obligated to pay Additional Amounts.See “Description of the Notes — Optional Tax Redemption.”

Certain Covenants The indenture (the “Indenture”) under which the Notes will be issuedcontains certain covenants that limit (i) the incurrence of liens,mortgages, or pledges on certain of the Issuer’s assets and (ii) certainsale/leaseback transactions. However, these limitations andrestrictions are subject to important exceptions. See “Description ofthe Notes — Certain Covenants.”

6

Change of Control The interest rate payable on the Notes will be subject to an increaseof 1.00% upon the occurrence of a Change of Control TriggeringEvent (as defined herein). See “Description of the Notes — Principal,Maturity and Interest.”

Events of Default The Notes will be subject to certain events of default, including thefailure by the Issuer to pay principal of or interest on the Notes andacceleration of certain other indebtedness. See “Description of theNotes — Events of Default.”

Withholding Tax See “Description of the Notes — Additional Amounts,” “Taxation —Canadian Taxation” and “Taxation — Thailand Taxation.”

Further Issues The Issuer may, from time to time, without the consent of the holdersof the Notes, create and issue further notes having the same terms andconditions as the Notes in all respects so that such further issue shallbe consolidated and form a single series with the Notes; providedthat, if any further issue is not fungible with the Notes for U.S.federal income tax purposes, such further issue shall trade separatelyfrom such previously issued Notes under a separate CUSIP numberbut shall otherwise be treated as a single series with all other Notesissued under the Indenture. See “Description of Notes — FurtherIssuances.”

Use of Proceeds The net proceeds from the sale of the Notes, which are estimated tobe approximately U.S.$699,720,000 million after payment ofcommissions to the Initial Purchaser but before expenses payable bythe Issuer and the Company, will be used for general corporatepurposes, including, but not limited to, funding the Company’sexploration, development and production activities.

Listing Approval-in-principle has been received for the listing of the Noteson the Official List of the SGX-ST. The Notes will be traded on theSGX-ST in a minimum board lot size of U.S.$200,000 for as long asthe Notes are listed on the SGX-ST.

Transfer Restrictions; Absence ofPublic Market for the Notes

The Notes and the Guarantee have not been and will not be registeredunder the Securities Act or any applicable securities legislation inCanada and are subject to restrictions on transferability and resale.For more information, see “Transfer Restrictions.” The Notes are anew issue of securities and there is currently no established tradingmarket for the Notes. Accordingly, there can be no assurance as to thedevelopment or liquidity of any market for the Notes. The InitialPurchaser has advised the Issuer and the Company that it currentlyintends to make a market in the Notes. However, it is not obligatedto do so, and any market making with respect to the Notes may bediscontinued without notice. See “Risk Factors — Risks Related tothis Offering — There is no public market for the Notes.”

7

Form, Denomination and Registrationof Notes

The Notes offered hereby will be issued in fully registered form,issued in minimum denominations of U.S.$200,000 and integralmultiples of U.S.$1,000 in excess thereof. The Rule 144A Notesoffered in the United States to QIBs in reliance on Rule 144A will beevidenced by a Rule 144A Global Note deposited with the Trustee, ascustodian for, and registered in the name of a nominee of, DTC. Rule144A Notes evidenced by the Rule 144A Global Note will settle inDTC’s Same Day Funds Settlement System, and secondary markettrading activity in such Rule 144A Notes will therefore settle inimmediately available funds. Regulation S Global Notes offeredoutside the United States in reliance on Regulation S will beevidenced by a Regulation S Global Note deposited with the Trustee,as custodian for, and registered in the name of a nominee of, DTC forits direct and indirect participants, including Euroclear andClearstream, Banking.

Delivery of the Notes Delivery of the Notes, against payment in same-day funds, isexpected on or about April 5, 2011. See “Plan of Distribution —Delivery of the Notes.”

Risk Factors See “Risk Factors” beginning on page 16 for a discussion of certainrisks that you should consider in connection with an investment inthe Notes.

Trustee The Bank of New York Mellon will act as the Trustee under theIndenture for the Notes.

Governing Law The Notes and the Indenture are governed by, and construed inaccordance with, the laws of the State of New York.

Security Codes Rule 144A Notes: Regulation S Notes:

CUSIP No.: 74442A AA6 CUSIP No.: C75088 AA9ISIN: US74442AAA60 ISIN: USC75088AA97

8

SUMMARY HISTORICAL THAI GAAP CONSOLIDATED FINANCIAL DATA

The following table presents selected financial information of PTTEP, which should be read in conjunctionwith the consolidated financial statements of PTTEP and “Management’s Discussion and Analysis of FinancialCondition and Results of Operations” that appear elsewhere herein. The summary financial information as of andfor each of the years in the three-year period ended December 31, 2010 are derived from PTTEP’s consolidatedfinancial statements for those periods. All such consolidated financial statements have been audited by the Officeof the Auditor General of Thailand, an agency of the Government. The consolidated financial statements of PTTEPare prepared and presented in accordance with Thai GAAP and reporting practices in Thailand. Thai GAAPvaries in certain significant respects from IFRS. For a description of certain differences between Thai GAAP andIFRS, see “Summary of Principal Differences Between Thai GAAP and IFRS.”

For the year ended December 31,

2008 2009 2010 2010

Bt Bt Bt U.S.$(1)

(in millions, except per share amounts)(audited) (unaudited)

Income Statement Data:Sales ........................................................................................ 132,621 115,547 138,474 4,571

Revenue from pipeline transportation.................................... 4,131 3,763 3,504 116

Other revenues(2) ................................................................... 3,255 1,028 5,594 184

Total revenues ....................................................................... 140,007 120,338 147,572 4,871Operating expenses................................................................. 10,529 11,926 14,588 482

Exploration expenses.............................................................. 8,273 7,377 2,752 91

Administrative expenses(3) .................................................... 4,497 5,062 5,972 197

Petroleum royalties and remuneration ................................... 17,328 14,066 16,773 554

Depreciation, depletion and amortization .............................. 23,286 29,856 36,825 1,215

Other expenses(4) ................................................................... 1,064 9,750 2,127 70

Total expenses........................................................................ 64,977 78,037 79,037 2,609Loss from the investments in associates ............................... (12) (18) (45) (1)

Income before finance costs and income taxes..................... 75,018 42,283 68,490 2,261

Finance costs........................................................................... 841 1,870 2,540 84

Income taxes ........................................................................... 32,502 18,259 24,211 799

Net income ............................................................................. 41,675 22,154 41,739 1,378Number of shares outstanding(5) ........................................... 3,307 3,313 3,317 3,317

Basic earnings per share(6) .................................................... 12.62 6.69 12.59 0.42

(1) The U.S. dollar translations are provided for indicative purposes only and are unaudited. These translations were calculated based onan exchange rate as of December 30, 2010: Baht/U.S.$ = Baht 30.296 to U.S.$1.00.

(2) Other revenues include gain on foreign exchange, interest income, income from gas pipeline construction service, rental revenues, gainon settlement of derivative financial instrument, compensation from the insurer for the Montara Incident, revenues from the disposalof assets and others.

(3) Prior to 2009, this line item was referred to as “Selling, general and administrative expenses.”

(4) Other expenses include losses on foreign exchange, hedging losses, management’s remuneration, losses from the Montara Incident andexpenses relating to the purchase of a floating production storage and offloading unit (“FPSO”).

(5) Number of shares (in millions) as of the year-ended.

(6) Basic earnings per share are calculated by dividing the net income attributable to shareholders by the weighted average number ofordinary shares in issue during the year.

9

For the year ended December 31,

2008 2009 2010 2010

Bt Bt Bt U.S.$(1)

(in millions)(audited) (unaudited)

Cash Flow Data:Net income from operating activities before

changes in operating assets and liabilities........................ 104,022 83,669 101,584 3,353

Net cash provided by operating activities ............................. 82,265 42,886 81,732 2,697

Net cash used in investing activities ..................................... 50,277 62,203 75,175 2,481

Net cash provided by (used in) financing activities ............. (12,235) 24,151 4,667 154

As at December 31,

2008 2009 2010 2010

Bt Bt Bt U.S.$(1)

(in millions except ratios, and percentages)(audited) (unaudited)

Balance Sheet Data:Cash and cash equivalents(2) ................................................. 43,995 48,678 59,515 1,964

Total current assets ................................................................. 66,952 78,784 85,076 2,808

Property, plant and equipment — net.................................... 167,326 206,705 226,332 7,471

Total assets.............................................................................. 238,255 300,711 342,220 11,296

Total current liabilities ........................................................... 49,450 56,196 58,197 1,921

Total non-current liabilities(3) ............................................... 54,701 101,514 111,729 3,688

Total liabilities ........................................................................ 104,151 157,710 169,926 5,609

Total shareholders’ equity ...................................................... 134,104 143,001 172,294 5,687

Other Financial Data:Net debt (4).............................................................................. (22,521) 23,093 18,323 605

EBITDA (5) ............................................................................. 95,061 78,068 101,708 3,357

EBIT (5) ................................................................................... 71,775 48,212 64,882 2,142

EBITDA margin (%)(6) ......................................................... 69.5 65.4 71.6 N/A

EBITDA interest coverage ratio (times) (7) .......................... 113.1 41.7 40.0 N/A

Total debt / EBITDA.............................................................. 0.23 0.92 0.77 N/A

Total debt / equity .................................................................. 0.16 0.50 0.45 N/A

Total debt / capital(8) ............................................................. 0.14 0.33 0.31 N/A

Net debt / EBITDA ................................................................ (0.24) 0.30 0.18 N/A

Net debt / equity..................................................................... (0.17) 0.16 0.11 N/A

Return on equity (%)(9) .......................................................... 35 16 26 N/A

(1) The U.S. dollar translations are provided for indicative purposes only and are unaudited. These translations were calculated based onan exchange rate as of December 30, 2010: Baht/U.S.$ = Baht 30.296 to U.S.$1.00.

(2) Cash and cash equivalents includes cash on hand and at banks, fixed deposits and treasury bills.

(3) Total non-current liabilities includes bonds, deferred income tax liabilities and other non-current liabilities such as deferred income,provision for employee benefits, provision for decommissioning costs, among others.

(4) Net debt comprises total interest bearing debt net cash and cash equivalents.

(5) EBIT is defined as earnings before income tax and interest and EBITDA is defined as earnings before income tax, interest anddepreciation and amortization. Earnings for calculating PTTEP’s EBIT and EBITDA include sales revenue and revenue from pipelinetransportation. EBIT and EBITDA are presented because the management believes that EBIT and EBITDA are widely acceptedfinancial indicators of an entity’s operating performance and ability to incur and service debt. EBIT and EBITDA should not beconsidered by an investor as alternatives to net income or income from operations, as indicators of PTTEP’s operating performanceor other combined operations, as cash flow data prepared in accordance with generally accepted accounting principles, or as analternative to cash flows as a measure of liquidity. PTTEP’s computation of EBIT and EBITDA may differ from similarly titledcomputations of other companies. See “Presentation of Financial Information.”

(6) EBITDA margin is equal to EBITDA divided by sales and revenue from pipeline transportation.

(7) Interest coverage is equal to EBITDA for any period, divided by interest expense during such period.

(8) Capital comprises total debt and shareholder’s equity.

(9) Return on equity comprises net profit divided by total shareholder’s equity.

10

SUMMARY UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

On January 21, 2011, PTTEP, through its subsidiary PTTEP CA, acquired from two indirect subsidiaries ofStatoil a 40% interest in SCP in Alberta, Canada for consideration of U.S.$2.28 billion. Approximately 61% ofthe aggregate purchase price was financed from PTTEP’s internal cash flows. Approximately 39% of theaggregate purchase price was financed through indebtedness under loan agreements with a variety of lenders.

The following summary unaudited pro forma combined financial information is based on the historicalconsolidated financial statements of PTTEP as of and for the year ended December 31, 2010 contained elsewherein this Offering Memorandum and the historical financial statements of SCP as of and for the year endedDecember 31, 2010, as adjusted to give pro forma effect to PTTEP’s acquisition of a 40% interest in SCP as ifthe acquisition had occurred as of January 1, 2010 and as adjusted further to give effect to the issuance of theNotes.

The unaudited pro forma adjustments are based upon available information and certain assumptions thatPTTEP believes are reasonable under the circumstances. The summary unaudited pro forma statement of incomedoes not purport to represent what the results of operations of PTTEP and its subsidiaries would actually havebeen had the acquisition in fact occurred as of January 1, 2010, nor do they purport to project the results ofoperations of PTTEP and its subsidiaries for any future period or date.

The information set out below should be read together with the other information contained under thecaptions “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and“Business” and the Unaudited Pro Forma Combined Financial Information found in Appendix A.

Profit and Loss Data

Pro Forma Adjustments

HistoricalPTTEP

Historical SCP(40%)

SCPAcquisition

(40%)NotesIssued

Pro FormaPTTEP

Bt Bt Bt Bt Bt(in millions except for share amounts)

Net revenueRevenues

Sales........................................................................ 138,474 69 — — 138,543Revenue from pipeline transportation ................... 3,504 — — — 3,504Other revenues ....................................................... 5,594 249 — — 5,843Total revenues ....................................................... 147,572 318 — — 147,890

ExpensesOperating expenses ................................................ 14,588 548 — — 15,136Exploration expenses ............................................. 2,752 1,233 — — 3,985Administrative expenses ........................................ 5,972 325 — — 6,297Petroleum royalties and remuneration................... 16,773 — — — 16,773Depreciation, depletion and amortization ............. 36,825 35 540 — 37,400Other expenses ....................................................... 2,127 — — — 2,127Total expenses ....................................................... 79,037 2,141 540 — 81,718

Operating income ...................................................... 68,535 (1,823) (540) — 66,172Loss from the investments in associates ............... (45) — — — (45)Income before finance costs and income taxes .... 68,490 (1,823) (540) — 66,127Finance costs .......................................................... 2,540 345 — 1,213 4,098Income before income taxes.................................. 65,950 (2,168) (540) (1,213) 62,029Income taxes .......................................................... 24,211 — (151) (340) 23,720

Net income ................................................................. 41,739 (2,168) (389) (873) 38,309Earnings per share

Basic earnings per share ........................................ 12.59 11.56Diluted earnings per share ..................................... 12.59 11.56

11

Balance Sheet Data

Pro Forma Adjustments

HistoricalPTTEP

Historical SCP(40%)

SCPAcquisition

(40%)NotesIssued

Pro FormaPTTEP

Bt Bt Bt Bt Bt(in millions)

ASSETSCash and cash equivalents ..................................... 59,515 1,371 (58,829) 21,146 23,203Accounts receivable ............................................... 11,728 57 — — 11,785Inventories .............................................................. 594 141 — — 735Materials and supplies, net .................................... 7,954 — — — 7,954Other current assets................................................ 5,285 15 — — 5,300Total current assets .............................................. 85,076 1,584 (58,829) 21,146 48,977

Non-current assetsInvestments............................................................. 1,468 — — — 1,468Property, plant and equipment, net........................ 226,333 14,934 27,596 — 268,863Intangible assets, net .............................................. 3,939 29,366 5,327 — 38,632Goodwill ................................................................. — — 9,146 — 9,146Deferred income tax assets.................................... 13,824 — — — 13,824Other non-current assets .......................................

Prepaid expenses ............................................... 152 — — — 152Deposit for the purchase of partnership units.. 10,312 — (10,312) — —Deferred remuneration under agreement.......... 920 — — — 920Other non-current assets ................................... 196 — — — 196

Total non-current assets ...................................... 257,144 44,300 31,757 — 333,201Total assets ................................................................. 342,220 45,884 (27,072) 21,146 382,178Current Liabilities

Accounts payable ................................................... 1,959 1,120 — — 3,079Current portion of long-term debt ......................... — — — — —Short-term loans..................................................... 7,945 — — — 7,945Working capital to co-venturers ............................ 1,014 — — — 1,014Accrued expenses................................................... 18,274 — — — 18,274Accrued interests payable ...................................... 552 — — — 552Income tax payable ................................................ 22,448 — — — 22,448Short-term provision .............................................. 3,933 — — — 3,933Other current liabilities .......................................... 2,072 — — — 2,072Total current liabilities ........................................ 58,197 1,120 — — 59,317

Non-current LiabilitiesBonds...................................................................... 69,893 — — 21,146 91,039Finance lease liabilities.......................................... — — — — —Deferred income tax liabilities .............................. 15,780 — 17,491 — 33,271Other non-current liabilities................................... 26,056 201 — — 26,257Total non-current liabilities ................................ 111,729 201 17,491 21,146 150,567

Total Liabilities .......................................................... 169,926 1,321 17,491 21,146 209,884

Stockholders’ Equity ...............................................Share Capital .......................................................... 17,500 — — — 17,500Partnership units..................................................... — 49,481 (49,481) — —Currency translation differences............................ (2,953) — — — (2,953)Retained earnings/ (Deficit)................................... 157,747 (4,918) 4,918 — 157,747Total stockholders’ equity ................................... 172,294 44,563 (44,563) — 172,294

Total liabilities and stockholders’ equity ............... 342,220 45,884 (27,072) 21,146 382,178

12

SUMMARY OPERATING, SALES AND ASSET DATA

The summary consolidated operating data set forth below are derived from unaudited reports prepared byPTTEP and should be read in conjunction with the section of this Offering Memorandum entitled “Business andProperties.” The proved reserves attributable to PTTEP are derived according to PTTEP’s Classification ofPetroleum Resources Guideline, which is substantially the same as the standards established by the SPE. Investorsshould note, however, that different reserves reporting systems employ different assumptions, and that, inparticular, PTTEP’s Classification of Petroleum Resources Guidelines may differ from the standards establishedby the United States Securities and Exchange Commission. PTTEP’s proved reserves have been derived in partfrom reports prepared by the operator of each concession in which PTTEP has a working interest, and have notbeen audited or otherwise reviewed by an independent petroleum engineering firm. PTTEP follows substantiallythe procedures recommended by standards issued by the SPE for preparing estimates of reserves for each of theconcessions in which PTTEP has an interest. See “Risk Factors — Risks Relating to PTTEP’s Business — Thereserves data in this Offering Memorandum are only estimates, there is no independent reserve report availablefor PTTEP and its actual production, revenues and expenditures with respect to its reserves may differ from theseestimates.”

As of and for the year ended December 31,

2008 2009 2010

Reserve Data:Proved Reserves: (1)

Natural gas (BSCF) ............................................................. 4,770 5,649 5,325Oil and condensate (MMbbls).............................................. 201 219 214

Total proved reserves (MMboe) (2) ...................................... 944 1,099 1,043Proved reserves developed (%)................................................ 46 41 44

Reserve Replacement Data:Three year average finding costs(U.S. dollars per boe)(3) ........................................................... 15.7 11.1 13.6Reserve Replacement Ratio (times)(4) .................................... 1.0 1.7 1.3Lifting cost data (U.S. dollars per boe) ................................... 2.5 3.2 3.75

Annual Production Volumes:Natural gas (BSCF) .................................................................. 409.7 427.3 518.0Oil and condensate (MMbbls).................................................. 23.8 25.7 27.1Total production (MMboe)(2) .................................................. 90.6 95.8 111.0Reserve life index (5) ............................................................... 10.4 11.5 9.4

Sales Volume (Boe/d)Gas ............................................................................................ 149,639 160,336 188,385Liquid ........................................................................................ 69,675 73,420 76,190Average volume ....................................................................... 219,314 233,756 264,575

Average Unit Prices:Natural gas (U.S. dollars per MMbtu)..................................... 5.2 5.2 5.5Crude oil and Condensate (U.S. dollars per Bbl) ................... 91.4 58.0 73.8Weighted Average (U.S. dollars per boe) ............................. 49.7 39.5 44.8

Oil Prices:Average Dubai (U.S. dollars per Bbl) ..................................... 93.5 61.2 78.1Average MFO (U.S. dollars per Bbl)....................................... 78.6 57.0 72.6

(1) Reserves and actual production data presented are net to PTTEP. See “Business — Reserves” for a description of the Company’spolicies regarding the classification of reserves.

(2) The Gross Calorific Values (“GCV”) used to convert gas volume to barrels of oil equivalent are different and vary for each project.The GCVs used for BOE conversion in reserves estimations and annual production volumes are also different. GCV used for reservesestimations are the estimated GCV of each project throughout its field life, while those used for production reports are the actual GCVsmeasured in each month.

(3) Three-year average finding costs are calculated on a rolling-year basis and are defined as acquisition costs, exploration anddevelopment costs incurred divided by reserve additions and revisions to previous reserve estimates from existing periods.

(4) Calculated by dividing three-year average reserve additions through acquisitions of reserves, extensions and discoveries, improvedrecovery, and revisions to prior estimates by the production for such period.

(5) Calculated by dividing year-end proved reserves by annual actual production for the year.

13

RISK FACTORS

You should carefully consider the following risk factors, as well as other information set out in this OfferingMemorandum, before making an investment in the Notes. The risks described below are not the only ones that mayaffect the Issuer, PTTEP, the Notes or the Guarantee. Additional risks not presently known to PTTEP or the Issueror risks that they currently deem immaterial may also impair their business operations. In general, investing insecurities of issuers or guarantors in emerging market countries such as Thailand involves risks not typicallyassociated with investing in the securities of companies in countries with more developed economies. To the extentit relates to the Government or Thai macroeconomic data, the following information has been extracted fromofficial Government publications or other third party sources and has not been independently verified by PTTEPor the Issuer.

Risks Relating to PTTEP’s Business

The volatility of prices for natural gas, crude oil and condensate and the cyclical nature of the oil and gasindustry affect PTTEP’s results of operations

Most of PTTEP’s revenues are attributable to the sale of natural gas, crude oil and condensate. Domesticand international prices for PTTEP’s products generally reflect price fluctuations in the international markets andare sensitive to other factors outside its control, including changes in worldwide industry capacity and outputlevels, cyclical changes in regional and global economic conditions, the price and availability of substituteproducts and changes in consumer demand, all of which from time to time have had a significant impact onproduct prices.

Historically, prices of natural gas, crude oil and condensate have fluctuated widely in response to manyfactors. For example, in 2008, the Organization of Petroleum Exporting Countries (“OPEC”) basket price forcrude oil fluctuated between U.S.$33.36 and U.S.$140.73 per barrel. In early 2009, the world oil market sufferedfrom the global economic crisis which began in 2008, resulting in a sharp drop in demand for oil and a significantdecrease in oil prices to U.S.$38.10 per barrel, though prices recovered in the latter half of the year, fluctuatingbetween U.S.$59.66 and U.S.$77.88 per barrel as economic stimulus plans led to renewed confidence in the globaleconomy. In 2010, the price of crude oil fluctuated between U.S.$66.84 and U.S.$90.73 per barrel. In addition,with recent political developments in the Middle East and North Africa, the price of oil has risen sharply in 2011.PTTEP does not and will not have control over the factors affecting international prices for natural gas, crude oiland condensate. The factors affecting prices include:

• global and regional economic and political developments in natural gas, crude oil and condensateproducing regions, particularly in the Middle East;

• the ability of the OPEC and other petroleum producing nations to set and maintain crude oil andnatural gas production levels and prices;

• global and regional supply and demand for natural gas, crude oil, condensate, and refined petroleumproducts;

• competition from other energy sources;

• domestic and foreign government regulations;

• weather conditions; and

• global economic conditions.

Substantially all of PTTEP’s natural gas production is sold under long-term gas sales agreements (“GSA”)at prices that are adjusted periodically to reflect changes to a benchmark price based on an average price per barrelof medium-sulphur (and in certain instances, low-sulphur) fuel oil exiting Singapore (“ex. Singapore”) and otherfactors, including the Baht-U.S. dollar exchange rate. The price that PTTEP may receive for its natural gasproduction, as well as PTTEP’s profitability, is dependent on the level of these benchmark prices, which is beyondPTTEP’s control. In addition, certain of PTTEP’s long-term gas sales agreements provide for price adjustmentsin the event of fluctuations in the Baht-U.S. dollar exchange rate, subject to certain thresholds and otherconditions. These pricing mechanisms function as a partial hedge against fluctuations in the value of the Baht

14

against the U.S. dollar, with the result that the decline in the value of the Baht against the U.S. dollar generallyhas the effect of increasing PTTEP’s sales revenues in Baht terms. Conversely, an increase in the value of the Bahtagainst the U.S. dollar generally has the effect of decreasing PTTEP’s sales revenues in Baht terms. See“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Substantially all of PTTEP’s domestic crude oil production is sold to PTT under long-term oil salesagreements at prices that are adjusted monthly to reflect changes in prevailing market prices for petroleumproducts. While PTTEP attempts to manage the risk of oil price volatility by entering into oil price hedging forits production of petroleum products using the Brent crude oil prices as a reference, the price that PTTEP receivesfor its crude oil production is dependent on the prevailing market price at the time, which is beyond PTTEP’scontrol. Outside of Thailand, sales are made at prevailing market prices on a case-by-case basis.

PTTEP’s failure to manage its existing projects and growth effectively may adversely impact PTTEP’s business

PTTEP plans to rapidly expand its exploration and production activities, in particular those located outsideof Thailand. This rapid expansion into other geographical regions has presented, and will continue to present,significant challenges for PTTEP’s management, operational and administrative systems and its ability to maintaineffective systems of internal controls. In addition, many petroleum producing countries are subject to risks anduncertainties associated with political instability and difficult economic climates. There can be no assurance thatPTTEP will not experience difficulties in managing its existing projects and growth effectively because of issuessuch as political difficulties, capacity and capital constraints, construction delays and operational difficulties atprojects. PTTEP may also face difficulties in upgrading or expanding existing facilities, locating and providingsuitable local senior management and training an increasing number of personnel to manage and oversee thoseprojects.

Further, PTTEP must manage relationships with a large and growing number of partners, suppliers,contractors, service providers, lenders and other third parties. PTTEP may not successfully integrate newacquisitions to meet its efficiency and performance standards, nor keep existing projects up to those samestandards. In addition, key personnel, either from existing and newly acquired projects, may not continue to workfor PTTEP. PTTEP will also be required to constantly develop and adjust management and administrativeresponsibilities to match market conditions and its growth and expansion. PTTEP’s continued development as aninternational oil and gas exploration and production company requires it to identify new qualified personnel withwidespread knowledge of its industry and the countries in which it operates. PTTEP’s failure to identify suitablepersonnel for these management and administrative positions may adversely affect PTTEP’s ability to manage itsgrowth and continue to pursue its growth strategy. These difficulties could disrupt PTTEP’s ongoing business,distract its management and employees and increase its expenses, which could have an adverse impact onPTTEP’s results of operations, financial condition and prospects.

Failure by PTTEP to develop existing reserves, replace existing reserves and develop additional reserves mayadversely affect PTTEP’s ability to achieve its growth objectives

PTTEP’s ability to achieve its growth objectives depends upon its success in finding and acquiring orgaining access to additional reserves. Approximately 55% of PTTEP’s proved reserves were undeveloped as ofDecember 31, 2010. PTTEP’s future success will depend on its ability to develop these reserves in a timely andcost-effective manner. PTTEP must continually find, acquire, explore for and develop new reserves to replacethose produced and sold in order to maintain or grow production at current levels. PTTEP faces challenges insustaining production growth due to the maturation and depletion of its principal proved reserves. The success ofpresently contemplated exploration, development and production activities cannot be assured. The decision toexplore or develop a property will depend in part on geophysical and geological analyses and engineering studies,the results of which may be inconclusive or subject to varying interpretations. During the exploration phase,drilling activities are subject to numerous risks, including the risk that no commercially viable oil or natural gasaccumulations will be discovered. The cost of drilling and operating wells is also often uncertain. Drilling maybe curtailed, delayed or cancelled as a result of many factors, including weather conditions, governmentrequirements and contractual conditions, shortages of or delays in obtaining equipment and reductions in productprices or limitations in the market for products. Geological uncertainties and unusual or unexpected formationsand pressures may result in dry wells, which may result in unprofitable efforts. In the development phase, drillingactivities are subject to fewer risks since more information becomes available for study. Wells have to becontinuously monitored so that they can deliver the nominated quantities stated in the relevant long term contracts.In addition, PTTEP faces substantial competition in the search for and acquisition of potential resources, whichrequires a substantial investment. The possibility of finding or being able to acquire additional resources isuncertain.

15

PTTEP’s future drilling, exploration and acquisition activities may not be successful if PTTEP does notconduct successful exploration activities, or acquire properties containing potential resources. If PTTEP’s drilling,exploration and acquisition activities are unsuccessful, future proved reserves will decline, which may have amaterial adverse effect on its business, financial condition, results of operations and prospects.

The development of PTTEP’s projects involves construction, financing, regulatory and operational risks thatcould lead to increased expenses and lost revenues

As part of its growth strategy, PTTEP is developing its oil and gas concession areas, or blocks. Thedevelopment and expansion of these projects involve many risks, including:

• the breakdown or failure of plant equipment or processes;

• failure to obtain required governmental permits and approvals;

• work stoppages and other industrial actions by employees or contractors;

• opposition from local communities and special-interest groups;

• engineering and environmental problems;

• construction and operational delays;

• inability to obtain capital to meet the capital expenditure requirements; and

• unanticipated cost overruns.

If PTTEP experiences any of these or other problems, it may not be able to derive income and cash flowsfrom its projects and investments in a timely manner, in the amounts expected or at all. Furthermore, the projectsPTTEP is developing and in which PTTEP invests require substantial capital outlay and a long gestation periodbefore PTTEP will realize any benefits or returns on investments. The time and costs required in completing aproject may be subject to substantial increases due to factors including shortages of, or increased competition ormarket prices for, materials, equipment, skilled personnel and labor; adverse weather conditions; natural disasters;labor disputes with contractors; accidents; changes in government priorities and policies; changes in marketconditions; delays in obtaining the requisite licenses, permits and approvals from the relevant authorities and otherunforeseeable problems and circumstances. PTTEP cannot assure you that its projects will be completed on time,within budget or at all or that their gestation period will not be affected by any or all of these factors. In addition,PTTEP’s ability to pass on any higher development costs to its customers is extremely limited due to long-termcontracts that it has entered into, and expects to enter into, with its customers. Any of these factors could adverselyaffect PTTEP’s business, financial condition, results of operations and prospects.

PTTEP’s exploration, development and production activities will require substantial capital expenditures andit may not be able to raise adequate financing on an ongoing basis

Oil and gas exploration and production are capital intensive operations. Over the next several years, PTTEPexpects to undertake a significant increase in its exploration and development activities for new projects, as wellas production activities in existing projects, all of which will require substantial capital outlays. PTTEP currentlyestimates that its capital expenditure requirements for the three-year period ending December 31, 2013 will beapproximately U.S.$7.5 billion, a significant portion of which will require external financing. PTTEP’s ability toobtain financing and the cost of such financing will be dependent on a number of factors over which PTTEP hasno control, including general economic, capital markets and political conditions, as well as PTTEP’s ability toincur additional debt, including as a result of prospective lenders’ evaluations of PTTEP’s creditworthiness andthe availability of credit from financial institutions. Global capital flows are significantly less certain today thanin the past. While PTTEP has been able to fund its capital requirements in the past, there can be no assurance thatPTTEP will be able to meet its capital requirements at costs acceptable to it in the future. See “Management’sDiscussion and Analysis of Financial Condition and Results of Operations.”

The exploration, development and production risks of oil and natural gas operations may adversely affectPTTEP’s profitability and may not be fully protected by insurance

PTTEP’s oil and natural gas exploration, development and planned production operations involve risksnormally incident to such activities, including blowouts, oil spills and fires (each of which could result in damage

16

to, or the destruction of, wells, production facilities or other property, or injury to persons), geologicaluncertainties and unusual or unexpected rock formations and abnormal pressures, which may result in dry holes,failure to produce oil or natural gas in commercial quantities or inability to fully produce discovered reserves.Offshore operations are subject also to hazards inherent in marine operation, such as capsizing, sinking, grounding,collision and damage from severe weather conditions. These hazards could result in substantial losses to PTTEPdue to injury and loss of life, severe damage to and destruction of property and equipment, pollution and otherenvironmental damage and suspension of operations. The resulting losses may not be fully compensated byinsurance. In addition, there are certain types of losses, such as those due to hurricanes, other natural disasters,terrorism or acts of war, which although covered under PTTEP’s current insurance policies to varying degrees,may be uninsurable or not insurable at a reasonable premium in the future.

Drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents canresult in costly delays or cancellations of drilling operations; serious damage to, or destruction of, equipment;personal injury or death; significant impairment of producing wells or underground geological formations; andmajor environmental damage. For example, in August 2009, PTTEP experienced specific incidents of an oil andgas leak and fire at the Montara H1 project. There can be no assurance that any future potential liabilities arisingfrom these events will be covered by PTTEP’s existing insurance. See “Risk Factors — Risks Relating to PTTEP’sBusiness — PTTEP and PTTEP AA are subject to claims and liabilities in relation to the Montara Incident,”“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors AffectingResults of Operations — The Montara Incident” and “Business — Principal Properties — Principal PropertiesUnder Production — Overseas — PTTEP Australasia.”

In addition, oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, butfrom wells that are productive but do not produce sufficient revenues to return a profit after drilling, operating andother costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completionand operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost ofoperations, and various field operating conditions may adversely affect PTTEP’s production from successfulwells. These conditions include delays in obtaining governmental approvals or consents, shut-in of connectedwells resulting from extreme weather conditions, insufficient storage or transportation capacity, ageing productionequipment, operation errors, or other geological and mechanical conditions. While close well supervision andeffective maintenance operations can contribute to maximizing production rates over time, production delays anddeclines from normal field operating conditions cannot be eliminated and can be expected to adversely affectPTTEP’s revenue and cash flow levels to varying degrees.

Although PTTEP maintains insurance coverage that it believes is in accordance with customary industrypractice, it is not fully insured against certain of these risks either because such insurance is not available orbecause of high premium costs. PTTEP does not carry coverage for timely completion of PTTEP’s projects underdevelopment, loss of rent or profit or defects in the quality of materials used. Should an uninsured loss or a lossin excess of insured limits occur, PTTEP may lose the capital invested in and the anticipated revenue from theaffected property. In addition, any payments PTTEP makes to cover any uninsured loss, or the insolvency of theinsurer of such event, may have a material adverse effect on its business, financial condition, results of operationsand prospects.

Future financing may place restrictions on PTTEP’s operations

PTTEP currently estimates that its overall capital expenditures for the three years ending December 31, 2013will be Baht 228,635 million (U.S.$7.5 billion), excluding the purchase price for SCP of Baht 68,400 million(U.S.$2.28 billion). The additional funding PTTEP may need to raise in order to make its planned capitalexpenditures which, if met by way of additional debt financing, may place restrictions on PTTEP which may,among other things:

• increase its vulnerability to general adverse economic and industry conditions;

• limit its ability to pursue its growth plans;

• require it to dedicate a substantial portion of its cash flow from operations to payments on its debt,thereby reducing the availability of its cash flow to fund capital expenditure, working capitalrequirements and other general corporate purposes; and/or

• limit its flexibility in planning for, or reacting to, changes in its business and its industry, eitherthrough the imposition of restrictive financial or operational covenants or otherwise.

17

Any inability of PTTEP to access financing on acceptable terms and conditions could have a materialadverse effect on PTTEP’s business, financial condition, results of operations and prospects.

PTTEP’s business depends on various exploration and production licenses. If any of these licenses aresuspended, restricted, terminated or not extended prior to expiry, this would have a material adverse effect onPTTEP

The Government owns all of Thailand’s petroleum resources and awards concessions and other rights withrespect to the exploration and production of such resources. Generally, the Department of Mineral Fuels (“DMF”)under the Thai Ministry of Energy is responsible for regulating and overseeing the exploration and exploitationof Thailand’s petroleum resources, and the Energy Minister is authorized to grant petroleum concessions with theconsent of the Cabinet.

On January 23, 1991, the Malaysia-Thailand Joint Development Authority (“MTJDA”) was established forthe exploration and exploitation of natural resources, particularly petroleum, in the overlapping continental shelfarea in the Gulf of Thailand known as the “JDA.” The MTJDA is a statutory body established under the laws ofMalaysia and Thailand to assume all rights and responsibilities on behalf of the two governments. On April 21,1994, the MTJDA awarded one of two Production Sharing Contracts (“PSCs”) in the JDA to PTTEP.

The Myanmar, Cambodian and Indonesian governments also own petroleum resources and have awardedPTTEP concessions and other rights with respect to the exploration and production of such resources. If thevalidity of any of its concessions or licenses were to be challenged, such licenses may be subject to suspensionor revocation. The suspension and/or loss of any such license would require PTTEP to stop its production fromthe field covered by the relevant license and, if PTTEP was unsuccessful in lifting such suspension or re-obtainingthe license, it would lose its right to extract oil or natural gas from the field altogether.

Accordingly, any suspension or loss of a license would materially and adversely affect PTTEP’s business,financial condition, results of operations and prospects.

Competitors of PTTEP may also seek to impede PTTEP’s rights to develop certain natural resource depositsby challenging PTTEP’s compliance with tender and auction rules and procedures or with the terms of the relevantlicense. Any non-compliance by PTTEP with licensing regulations or the terms of the relevant licenses could leadto the suspension, restriction or termination of the licenses and to administrative, civil and criminal liability.

PTTEP must also maintain, and from time to time extend and/or obtain other permits and authorizationsincluding land and mining allotments, approvals of design and feasibility studies, pilot production projects anddevelopment plans and permits for the construction of facilities. If PTTEP fails to receive the necessary permitsand authorizations, or if they are terminated, PTTEP may have to delay investment or development programs,which could materially adversely affect its business, financial condition, results of operations and prospects.

The reserves data in this Offering Memorandum are only estimates, there is no independent reserve reportavailable for PTTEP and its actual production, revenues and expenditures with respect to its reserves may differfrom these estimates

This Offering Memorandum includes estimates made by PTTEP of its gross proved reserves. Noindependent reserve report is available on the gross proved reserves of PTTEP. These estimates are based onPTTEP’s Classification of Petroleum Resources Guidelines, which are substantially similar to the standardsestablished by the SPE, the SPE Petroleum Resources Management System. PTTEP’s Classification of PetroleumResources Guidelines may differ from the standards established by the United States Securities and ExchangeCommission. In regards to the reserves and resources classification provided for KKD, PTTEP refers to the draftCanadian Oil and Gas Evaluation Handbook (COGE Handbook) Vol. 3, Part 3 — Detailed Guidelines forEstimation and Classification of Bitumen and Steam Assisted Gravity Drainage (SAGD) Reserves and Resources,which is broadly aligned with the SPE Petroleum Resources Management System. There are uncertainties inherentin estimating quantities of gross proved reserves and in the timing of development expenditures and the projectionof future rates of production. However, the proved reserve data set out in this Offering Memorandum representsestimates of a high confidence, which according to both the SPE Petroleum Resources Management System andCOGE Handbook, means at least a 90% chance that quantities actually recovered will equal or exceed theestimates. Adverse changes in economic conditions may render it uneconomical to develop certain reserves.

18

The reliability of reserve estimates depends on, among other things:

• the quality and quantity of technical and economic data;

• the prevailing oil and gas prices applicable to production;

• the production performance of the reservoirs;

• extensive reservoir and geological judgments; and

• the assumed effects of regulation by governmental agencies.

Determination of reserve estimates is an inexact, interpretative activity generally based upon the guidelinesand definitions. There often exist various professional interpretive differences of guidelines and reserveclassification between companies, other independent petroleum engineering consultants and operators. This isoften evidenced by different reported reserves between consortium members of the same exploration or producingblock. Such differences may include assigning volumes to proved, probable or possible reserve categories or tocontingent resources, based on interpretation of guidelines or on views of the commercial viability of a given oilor gas reserve or resource, at a particular point in time. There is no assurance that PTTEP, other independentpetroleum engineering consultants or other operators will not change their views on the interpretation of suchguidelines or change their interpretation of the commercial viability of a given reserve or resource, and thuscausing such resources or reserves to be reclassified into another category under SPE, COGE or other similarguidelines.

There are numerous uncertainties inherent in estimating quantities of reserves, including many factorsbeyond the control of PTTEP. The reserve data set forth in this Offering Memorandum represent estimatesdetermined by PTTEP according to industry practice. In general, estimates of commercially recoverable oil andnatural gas reserves are based upon a number of variable factors and assumptions, such as geological andgeophysical characteristics of the reservoirs, historical production performance from the properties, the quality andquantity of technical and economic data, prevailing oil and gas prices applicable to a company’s production,extensive engineering judgments, forward-looking commercial and market assumptions, the assumed effects ofregulation by Government agencies and future operating costs. All such estimates involve uncertainties, andclassifications of reserves are only attempts to define the degree of likelihood that the reserves will result inrevenue for PTTEP. For these reasons, estimates of the commercially recoverable oil and natural gas reservesattributable to any particular group of properties, classification of such reserves based on uncertainty of recoveryand estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineersat different times, may vary substantially. In addition, such estimates can be and will be subsequently revised asadditional pertinent data becomes available prompting revision. Actual recoverable reserves may varysignificantly from such estimates. To the extent actual recoverable reserves are significantly less than PTTEP’sestimates, PTTEP’s financial condition and results of operations are likely to be materially and adverselyimpacted. See “Business — Reserves.”

Additionally, estimates of commercially recoverable reserves based on uncertainty of recovery and estimatesof future net revenues expected from those reserves may vary substantially. Finally, new drilling, testing andproduction after the date the estimates are made may cause substantial upward or downward revisions in theestimates. PTTEP’s actual production, revenues, taxes and development and operating expenditures with respectto its reserves may vary materially from estimates.

PTTEP’s business operations may be adversely affected by present or future product quality requirements andenvironmental regulations

PTTEP’s business is subject to certain laws and regulations relating to product quality and to environmentaland safety matters in the exploration and development, production and transmission of oil and natural gas. Manyof the environmental laws and regulations and product quality standards applicable to PTTEP are significantly lessdeveloped than those in the United States and certain other developed market economies, and enforcement ofexisting requirements may be less rigorous than in such countries. PTTEP cannot assure you that any futureenvironmental laws, or changes in enforcement policies, will not result in a curtailment of production or a materialincrease in the costs of exploration, development, production and transmission activities or otherwise adverselyaffect PTTEP’s operations and financial condition. These costs could have a material adverse effect on PTTEP’sresults of operations and business.

19

PTTEP may be subject to claims and liabilities under environmental, health, safety and other laws andregulations

PTTEP’s operations, which are often potentially hazardous, are subject to health, safety and other laws andregulations, including those inherent to oil exploration and production industries. Although PTTEP endeavors tocomply with all environmental and health and safety laws and regulations at all times, PTTEP or one of itssubsidiaries may become involved in claims, lawsuits and administrative proceedings relating to environmentaland health and safety matters in the future. For example, PTTEP is likely to be involved in proceedings regardingthe Montara Incident. An adverse outcome in these proceedings or in any future proceedings may have asignificant negative impact on PTTEP’s business, prospects, financial condition and results of operations and mayinclude the imposition of civil, administrative or criminal liability on PTTEP or its officers, employees and/ormanagement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Factors Affecting Results of Operations — The Montara Incident,” “— PTTEP and PTTEP AA are subject toclaims and liabilities in relation to the Montara Incident” and “— PTTEP AA and PTTEP may face materialadverse consequences as a result of ongoing and future investigations into the Montara Incident conducted byvarious Australian governmental agencies.”

PTTEP relies on successful human resources development

PTTEP’s success in conducting exploration and production activities, and in operating certain oil and naturalgas concessions, is highly dependent upon its ability to attract and retain qualified petroleum engineers, geologists,geophysicists and other technicians and managers with sufficient experience in the exploration and productionbusiness. PTTEP also uses third-party contractors to undertake certain project tasks. Additionally, PTTEP isselectively investing in certain sophisticated and unconventional oil and gas collection projects, such as FLNG andoil sands, which require specialized technical knowledge and expertise. Although PTTEP has been successful inthe past in attracting qualified personnel from the subsidiaries and affiliates of international oil companies, andalthough PTTEP invests significant resources in training its personnel, shortages of trained engineers, geologists,geophysicists and other technicians and managers in Thailand and other countries where it operates may make itmore difficult or costly for PTTEP to hire adequate numbers of such personnel in the future.

PTTEP and PTTEP AA are subject to claims and liabilities in relation to the Montara Incident

In August 2009, an oil and gas leak began during the Montara H1’s development well drilling whichcontinued until PTTEP AA stopped the leak in November 2009. The causes of the uncontrolled oil and gas releaseinclude deficiencies in the Montara H1 well cementing operation and well barrier testing and the failure to installall required pressure containing corrosion caps. In addition, other causative factors in the uncontrolled oil and gasrelease may have included inadequate supervision and monitoring of operations and personnel and deficiencies inwell management documentation and systems. During operations to stop the leak, PTTEP AA’s wellhead platformand the contractor-operated West Atlas drilling rig caught fire, causing substantial damage to both the wellheadplatform and the West Atlas rig. This affected the production start-up. In order to maintain control of the well andfix damaged production facilities, PTTEP AA temporarily suspended the development of the Montara H1 well.

PTTEP has expended significant amounts of capital on containing and cleaning up the oil and gas leak, andtogether with PTTEP AA, will be subject to claims and liabilities under the laws of Australia, Indonesia andelsewhere. Such causes of action may include, but are not be limited to, regulatory actions brought by governmentagencies in connection with safety issues and the environmental consequences of the oil and gas leak and causesof action initiated by third parties for property damage and loss of livelihood.

On August 26, 2010, PTTEP AA received a letter from the Government of Indonesia claiming U.S.$2.5billion in compensation related to the Montara Incident. Further details of the claim and supporting documentationwere received in October 2010. PTTEP AA has not accepted the claim as PTTEP AA believes that it is notsupported by scientifically valid evidence. PTTEP AA continues to actively engage the Government of Indonesia,but has not accepted any legal liability to pay compensation to the Government of Indonesia. In December 2010,PTTEP AA and the Government of Indonesia agreed to provide each other with additional documents and toconduct a joint survey to verify the Government of Indonesia’s data on the claimed damage to its fishing industry.PTTEP AA and the Government of Indonesia met again for discussions in February 2011. As of the date of thisOffering Memorandum, no conclusion has been reached regarding any claims for compensation.

20

The full extent of any claims and liabilities in connection with the Montara Incident are uncertain at thistime. PTTEP cannot guarantee that these or any other claims and liabilities will not materially and adversely affectPTTEP’s business, financial condition, results of operations and prospects. See “Management’s Discussion andAnalysis of Financial Condition and Results of Operations — Factors Affecting Results of Operations — TheMontara Incident,” “Business — Principal Properties — Principal Properties Under Production — Overseas —PTTEP Australasia — Montara Project” and “Business — Legal Proceedings.”

PTTEP AA and PTTEP may face material adverse consequences as a result of ongoing and futureinvestigations into the Montara Incident conducted by various Australian governmental agencies

In November 2009, the Australian Minister for Resources, Energy and Tourism announced a Commissionof Inquiry (the “Commission”) into the Montara Incident. The Commission was charged with investigating severalmatters, including: (i) the likely causes of the incident; (ii) the adequacy and effectiveness of the regulatoryregime, including approved safety, environment and resource management arrangements; (iii) the performance ofrelevant persons in carrying out their obligations under the regulatory regime; (iv) the adequacy of responserequirements and the actual response to the incident; (v) the environmental impacts as a result of the incident,including reviewing environmental monitoring plans; and (vi) the offshore petroleum industry’s response to theincident and the provision and accessibility of information concerning the incident to stakeholders and theAustralian community.

The Commission had the power to summon witnesses, take evidence on oath and require individuals andcorporations to give the Commission documents relevant to its terms of reference. The witness testimony focusedon numerous matters, including a detailed review of the technical facts and circumstances leading up to theblowout. In addition, the inquiry focused on the actions of various persons within PTTEP AA and PTTEP, bothon an operational level on- and off-site, and on a senior management level, in the oversight of day-to-day drillingoperations. Persons called to provide testimony included senior PTTEP AA management and drilling personnel aswell as other drilling subcontractors and managers. Certain testimony identified material deficiencies in theprocedures followed by PTTEP AA employees in connection with the Montara Incident and was critical of thegeneral management of the operations as well as specific actions both taken and not taken by the company leadingup to and following the spill. In addition, many of the submissions were critical of the mechanics and managementof the drilling operations, as well as the subsequent spill containment efforts.

The Commission does not have the power to impose any liability, whether civil or criminal, on any person.The Commission prepared a report of its findings, one of the purposes of which was to make recommendationsto the Minister for Resources, Energy and Tourism on measures that might reduce the possibility of similarincidents occurring in the future and alleviate the safety, environmental and resource impacts arising from suchan incident.

The Commission’s report was submitted to the Minister of Resources, Energy and Tourism on June 18, 2010and was released to the public on November 24, 2010. The Commission’s report found that the blowout occurredbecause the primary well control barrier failed to stop a surge of oil and gas in the well due to defects in installationof primary control barrier. Furthermore, the secondary control barriers were not in place at the time of the surge.The Commission identified material deficiencies in the procedures followed by PTTEP AA employees inconnection with the Montara Incident and was critical of the general management of the operations as well asspecific actions taken and not taken by PTTEP AA and PTTEP leading up to and following the spill, includingthe mechanics and management of the drilling operations as well as the subsequent spill containment efforts.

In Australia, petroleum titles in respect of offshore petroleum resources are granted and administered underthe Offshore Petroleum and Greenhouse Gas Storage Act 2006 (“OPGGS Act”). The Minister for Energy,Resources and Tourism has broad powers under the OPGGS Act to review, vary, suspend or cancel petroleumtitles, including those with respect to the Montara project and PTTEP AA’s other projects in Australia. TheCommission’s report did not recommend a specific outcome for a review of PTTEP AA’s licenses. However, itdid recommend that the Minister conduct such a review and if he determines that there were violations of theOPGGS Act that he should consider revoking the licenses.

PTTEP AA, in conjunction with industry experts and the relevant Australian regulatory bodies, developedan action plan as a coordinated response to the issues identified in the Commission’s Report (the “Action Plan”).The Action Plan addressed both technical and governance issues and PTTEP AA began implementing the plan inJune 2010. Following the recommendation of the Commission’s report, the Minister for Energy, Resources andTourism conducted a review of PTTEP AA’s petroleum titles for the Montara Project and all of its other Australianoperations. The review process included an independent third-party review of the Action Plan.

21

On February 4, 2011, the Minister for Energy, Resources and Tourism announced his determination that theAction Plan effectively responded to the issues identified by the Commission. As a result, the Minister decidednot to pursue further inquiries or reviews of PTTEP AA’s petroleum titles. This decision was conditioned onPTTEP AA implementing the plan under an 18-month monitoring program overseen by independent industryexperts appointed by the Government of Australia. PTTEP, PTTEP AA and the Government of Australia enteredinto a Deed of Agreement in respect of PTTEP AA’s operations and the monitoring plan on February 22, 2011.If the independent monitors determine that PTTEP and PTTEP AA have failed to implement the Action Plan orfulfill their obligations under the Deed of Agreement, the Minister for Energy, Resources and Tourism has reservedthe right to further review PTTEP AA’s petroleum licenses.

Independent of the Commission, other regulatory authorities are conducting, or are likely to conduct,investigations into the incident with the objective of assessing compliance with applicable safety, environmentaland well management legislation. The National Offshore Petroleum Safety Authority is currently investigatingcompliance with the occupational health and safety duties of care imposed under the OPGGS Act and on June 16,2010 provided a brief to the Commonwealth Department of Public Prosecutions for its consideration as to whetherto bring any prosecutions. The Department of Sustainability, Environment, Water, Population and Communitiesis undertaking an audit of compliance with the conditions of the approval for the Montara Development drillingunder the Environment Protection and Biodiversity Conservation Act 1999 (the “EPBC Act”) (and the EPBC Actgenerally). The approvals were conditioned on compliance with environmental and technical documents filed withthe department and the audit is focused on reviewing the operations of the project in light of those filings. Theaudit has been completed, but it is unknown when the results will be released or whether a formal investigationwill be conducted. The Commonwealth Department of Resources, Energy and Tourism has appointed inspectorsto investigate compliance with the environmental and well operations regulatory regimes applied under theOPGGS Act. These investigations may result in criminal prosecutions and the imposition of fines on PTTEP AA.

The investigations, potential regulatory actions and third-party claims referred to above are not exhaustiveand other investigations, actions and third-party claims may arise in connection with the Montara Incident. Whenconcluded, certain of these proceedings could result in direct fines, other sanctions (including civil and criminalpenalties, and revocation or modification of petroleum titles), liabilities and damages which could have a materialadverse effect on the business, financial condition, results of operations and prospects of PTTEP AA and PTTEP.

PTTEP’s relationship with PTT and the Government makes it heavily dependent on those entities, and theinterests of PTT may conflict with yours as a Noteholder

As of February 15, 2011, PTT (which is 51.36% owned by the Government) owned 65.32% of the OrdinaryShares of PTTEP. The Cabinet has adopted a resolution setting forth a policy requiring PTT to retain a minimumof 51% of the issued and outstanding ordinary shares of PTTEP. Accordingly, PTT currently has the ability to electa majority of PTTEP’s directors and determine the outcome of most actions requiring shareholder approval, andtheir interests may not be aligned with yours as a Noteholder. PTTEP, as a State Enterprise, is also subject tocertain restrictions in the conduct of its business to which other companies in Thailand may not otherwise besubject.

Further, conflicts of interest may arise between PTT and PTTEP in a number of areas relating to their pastand ongoing relationships, including the natural gas sales agreements between PTT and PTTEP and PTT’sdevelopment of the infrastructure necessary for the delivery of natural gas. There can be no assurance that PTTand PTTEP will be able to resolve any potential conflict or that, if resolved, PTTEP would not receive a morefavorable resolution if it were dealing with an unaffiliated party.

PTTEP relies heavily on its primary customers to maintain profitability

In addition to its role as PTTEP’s controlling shareholder, PTT is also the primary purchaser of PTTEP’snatural gas, crude oil and condensate. In 2010, PTT provided approximately 98% of PTTEP’s natural gas revenue,approximately 64% of its crude oil revenue and approximately 92% of its condensate revenue. PTTEP generallymakes natural gas sales to PTT under long-term take-or-pay sales agreements. As a result, the inability of PTTEP,or of a joint venture operator of a new property in which PTTEP has a working interest, to successfully negotiatea sales agreement with PTT, or the failure of PTT to comply with the terms of the existing sales agreements, couldhave a material adverse effect on PTTEP’s business, financial condition, results of operations and prospects. See“Risk Factors — Risks Relating to PTTEP’s Business — PTTEP’s relationship with PTT and the Governmentmakes it heavily dependent on those entities, and the interests of PTT may conflict with yours as a Noteholder.”

22

Although PTT is responsible for taking and paying for the majority of PTTEP’s gas production, PTT isdependent on the Electricity Generating Authority of Thailand (“EGAT”) and other customers making paymentpursuant to their own gas sales arrangements with PTT in order for PTT to generate sufficient cash flow and meetits obligations to PTTEP. In addition, while the gas sales agreements between the parties include provisions forprice adjustments based on market prices and other factors, PTT (and indirectly, PTTEP) is dependent on, amongother things, the ability of EGAT to adjust the electricity tariff charged to its customers. However, priorgovernment approval is required for any adjustment to EGAT’s tariffs. The settlement terms of PTT’s take-or-payobligations to PTTEP in respect of gas sales agreements between the parties provide for the billing and settlementin respect of any gas not taken by PTT only after the end of the contract year during which such obligations arose.Consequently, PTTEP’s revenues, results of operations and cash flow with respect to any period during which PTTis not taking delivery of gas may be materially adversely affected because payment in respect of gas which PTThas not taken will not be received until the following year.

PTTEP depends on third-party operators for a significant number of its projects

PTTEP holds its interests in the majority of its development and production projects through joint ventureswith international oil and gas companies. PTTEP does not act as operator of many of these joint ventures.Therefore, PTTEP has limited control over the manner in which operations are conducted and the safety andenvironmental standards used in connection with these joint ventures. The failure of any operator to perform itsobligations could have a material adverse effect on the development of or production from a project, which in turncould have a significant effect on PTTEP’s anticipated exploration and development activities. See “Business —Production and Sales — Joint Venture Agreements.”

In addition, many of the operators of these joint ventures use equipment employing advanced technologies,such as turbo compressors, turbo generators and supervisory control and data acquisition systems, or SCADAsystems, which continues to evolve, and accordingly, the equipment could become out-of-date or obsolete priorto the time that the operator may have originally intended to replace it. For instance, the computer processors forequipment control systems are generally replaced every 15 years. If this were to occur, the operators may needto purchase substantial amounts of new capital equipment, which could have a material adverse effect on theoperator’s ability to perform its obligations to develop or carry on production at a project, which in turn could havea material adverse effect on PTTEP’s anticipated exploration and development activities.

PTTEP is reliant on infrastructure development and equipment provided by third parties in Thailand and othercountries in which it conducts its business

The expansion of natural gas production in Thailand and neighboring countries is currently constrained bythe capacity limits of existing transportation facilities. In Thailand, substantially all such facilities are owned andoperated by PTT, which is currently undertaking projects to expand Thailand’s existing transportation capabilities.In addition, the ability of PTTEP to pursue opportunities to develop and produce natural gas resources inneighboring countries depends upon the development in such countries of adequate infrastructure for thetransportation of natural gas. The failure of PTT or the relevant companies in these other countries to completeproposed pipeline projects on a timely basis or to expand other natural gas infrastructure may adversely affectPTTEP’s business, financial condition, results of operations and prospects, or may require PTTEP to makesignificant expenditures on constructing its own pipelines or other infrastructure.

As an oil and gas exploration and production company, most of the infrastructure that PTTEP uses totransport oil and gas to its customers is not owned by PTTEP. Such infrastructure, which includes pipelines andstorage tanks, is leased from third-party providers, and PTTEP has no control over the quality and availability ofthis infrastructure. As part of its business, PTTEP also has to assume some of the risk of damage or loss of theconstruction services and equipment provided to it by third-party contractors (such as drilling rigs, seismicacquisition vessels, service boats, tankers and floating storage and offloading vessels). PTTEP’s developmentprojects have in the past also required it to commit to long-term leases and other financial arrangements.

In addition, PTTEP competes with other oil and gas companies for equipment and human resources such asoil and gas drilling rigs, which are a limited resource given the competitive market in the oil and gas sector. Theincreased demand for such equipment and people has resulted in increased competition for available resources andhigher prices that PTTEP has had to pay in order to secure its access to such equipment and human resources. IfPTTEP is unable to obtain the equipment that it needs to carry out its development plans with respect to itsproduction assets, it may have to delay or restructure its development plans, which may have an adverse effect on

23

PTTEP’s ability to commercialize its oil and gas reserves on a timely basis. Further, depending on the complexityof its development projects, the competitive dynamics of the market, movements in prices of raw materials suchas steel, and the availability and prices of its contractors and equipment, PTTEP may have to pay significantlymore than it currently anticipates to implement its development plans for its blocks.

From time to time, PTTEP may face interruptions in the functioning of its production and deliveryinfrastructure due to logistical complications outside its control. In the event of a disruption or delay in theavailability of this infrastructure, PTTEP would be unable to sell its products until the problem is corrected or untilit finds alternative means to deliver its products to its customers. Such alternative means, if available, would likelyresult in increased costs to PTTEP, and could have a material adverse effect on PTTEP’s business, financialcondition, results of operations and prospects.

Competition and deregulation of Thai energy markets may have significant effects on PTTEP’s business

PTTEP’s competitors for the acquisition, exploration, development and production of crude oil and naturalgas properties in Thailand, and for the capital to finance such activities, include companies that have greaterfinancial and other resources. PTTEP’s ability to successfully bid on new concessions or otherwise acquireadditional property rights, to explore for and develop reserves and to enter into commercial arrangements withcustomers will be dependent upon the continuation of its close working relationships with its joint venture partnersand operators, the status of PTT as the primary purchaser and transporter of natural gas in Thailand, and PTTEP’sability to select and evaluate suitable projects and consummate transactions in a highly competitive environment.

In addition, in recent years the Energy Policy and Planning Office of Thailand has been making changes tothe current regulatory structure of the natural gas industry in Thailand that are intended to increase the level ofcompetition in the gas industry. These changes include the implementation of “third-party access” to transmissionpipelines, which could significantly impact the terms of PTTEP’s future gas sales arrangements. In particular, theintroduction of “third-party access” to PTT’s natural gas pipeline transportation network would allow upstreamproducers such as PTTEP, its working interest partners and others, to enter into gas sales agreements with endusers without involving PTT as an intermediary. This may result in a reduction in PTT’s role as Thailand’s primarygas supplier. Consequently, this may impact PTTEP’s ability to secure additional natural gas properties throughits relationship with PTT. Although PTTEP does not expect the implementation of “third-party access” to havesignificant effects on its business for the next several years, the precise impact of its implementation is stilluncertain.

PTTEP’s petroleum exploration and production activities in foreign countries subject it to unforeseen risks

To increase its reserves and to improve its position in the world market, PTTEP has expanded its investmentbase to petroleum exploration and production activities in a number of foreign countries in the Asia-Pacific region,the Middle East and North Africa. These international operations are subject to special risks that can materiallyaffect PTTEP’s results of operations. These risks include:

• increased reliance on oil and gas revenues and potential exposure to increased price volatility;

• unsettled political conditions, war, civil unrest, and hostilities in some gas or petroleum producing andconsuming countries and regions where PTTEP operates or seeks to operate;

• undeveloped legal systems;

• restrictions on drilling and production in certain jurisdictions;

• political and economic instability in foreign markets;

• the impact of inflation;

• natural disasters;

• fluctuations and changes in currency exchange rates; and

• governmental action such as expropriation of assets, general legislative and regulatory environmentchanges, exchange controls, the cancellation of contract rights, and changes in global trade policiessuch as trade restrictions and embargoes imposed by the United States and other countries.

24

To date, instability in the overseas political and economic environment has not had a material adverse effecton PTTEP’s business, financial condition, results of operations and prospects. PTTEP cannot predict, however, theeffect that the current conditions affecting various foreign economies or future changes in economic or politicalconditions abroad could have on the economics of conducting exploration and production activities overseas. Anyof the foregoing factors may have a material adverse effect on PTTEP’s international operations and, therefore,its business, financial condition, results of operations and prospects.

The political unrest in Algeria, Egypt and Bahrain may have negative consequences for PTTEP’s projects inthese countries

PTTEP participates in projects in Algeria, Bahrain and Egypt, which, like many countries in the Middle Eastand North Africa, have recently experienced mass political movements, protests and changes in government.These movements began in Tunisia on December 18, 2010 and led President Zine El Abidine Ben Ali to fleeTunisia on January 14, 2011. Due to similar hardships in the region and the success of protests in Tunisia, a chainof protests in Algeria, Egypt and Bahrain, amongst others, followed.

In Algeria, a wave of protests and riots started on December 28, 2010 provoked by the events of Tunisia andsudden rises in staple food prices. These protests were quelled by government measures to lower food prices butwere followed by a continuing wave of demonstrations that were illegal under a 19-year-old state of emergency.On February 24, 2011, the state of emergency in Algeria was officially lifted in response to the demonstrations.In Egypt, massive protests focused on legal, political, and economic issues began on January 25, 2011. Theseprotests ended when President Hosni Mubarak, resigned on February 11, 2011. On February 13, 2011, theconstitution of Egypt was suspended and military rule was established for six months until elections can be held.In Bahrain, a series of demonstrations began on February 14, 2011. In response, King Hamad first addressed somereform issues and later employed state security forces and the forces of Saudi Arabia to quell the protests.

The effects of these events on political, economic and legal conditions in Algeria, Egypt and Bahrain remainuncertain. To operate in these countries, PTTEP works with the governments and government controlled entities.Prolonged political instability in Algeria, Egypt and Bahrain or further changes in government may underminePTTEP’s operations in these countries, which in turn could have an adverse effect on PTTEP’s business, financialcondition, results of operations and prospects.

There are certain risks associated with doing business with Myanmar

For both 2009 and 2010, approximately 13% of PTTEP’s production volume, respectively, came fromMyanmar territorial waters in the Gulf of Mataban. Since November 1997, Myanmar has been governed by theState Peace and Development Council, formerly known as the State Law and Order Restoration Council, amilitary-dominated regime that previously governed Myanmar from 1988 to November 1997. Myanmar hasexperienced opposition from pro-democracy, religious and ethnic groups in recent years. Such opposition has attimes included armed resistance. Although the government of Myanmar has in recent years instituted certainmarket-based economic and financial reforms, such as the sale of state owned assets, much of the economyremains state-dominated as a result of past socialist economic initiatives. A new constitution was ratified in May2008 through a nationwide referendum. In November 2010, Myanmar held its first elections in two decades,although key opposition leaders boycotted the election. PTTEP cannot assure you that political or economicdevelopments in Myanmar will not have a material adverse effect on PTTEP’s business, financial condition,results of operations and prospects.

Risks Relating to the Acquisition of an interest in SCP

On January 21, 2011, PTTEP, through its subsidiary PTTEP CA, acquired from two indirect subsidiaries ofStatoil a 40% interest in SCP in Alberta, Canada for consideration of U.S.$2.28 billion. Statoil owns the remaining60% interest in the partnership and is the managing partner. See “Business — Recent Developments —Acquisition of an Interest in the Kai Kos Dehseh Project.” PTTEP’s acquisition of an interest in SCP is subjectto, and exposes the Company to, significant risks and uncertainties, including but not limited to those set outbelow.

PTTEP’s acquisition of an interest in SCP constitutes a highly significant investment and additional investmentwill be required in the future

PTTEP’s acquisition of an interest in SCP constitutes a highly significant investment. PTTEP has investedU.S.$2.28 billion. Approximately 61% of the aggregate purchase price was financed from PTTEP’s internal cashflows. Approximately 39% of the aggregate purchase price was financed through indebtedness under loanagreements with a variety of lenders.

25

From time to time, PTTEP will be required to provide additional funds to SCP for capital expenditures oroperating expenses as required under the Partnership Agreement with Statoil. See “Business — Acquisition of anInterest in the Kai Kos Dehseh Project — Recent Developments — Material Agreements.” These cash calls mayreduce PTTEP’s cash reserves or require PTTEP to incur significant amounts of new debt or make new issuancesof securities. See “Risks Relating to Our Business — PTTEP’s exploration, development and production activitieswill require substantial capital expenditures and it may not be able to raise adequate financing on an ongoingbasis.” Accordingly, these obligations and the failure to find adequate financing, on terms commercially favorableto PTTEP or at all may materially and adversely affect PTTEP’s business, financial condition, results of operationsand prospects.

PTTEP may not be able to realize anticipated benefits from the acquisition of an interest in SCP

PTTEP expects that the acquisition of an interest in SCP will enable it to grow its total reserves, diversifygeographically, improve its long-term production and improve its overall competitiveness, among other benefits.However, the acquisition of the interest in SCP may not meet PTTEP’s expectations and the realization of theanticipated benefits may be blocked, delayed or reduced as a result of numerous factors, some of which are outsideof PTTEP’s control. These factors include, among others:

• unforeseen contingent risks or latent liabilities relating to the acquisition that may become apparentin the future;

• failure to secure key licenses or regulatory approvals;

• failure to develop the project on schedule or on budget, or to achieve the expected production orreturns on the project; and

• loss of key personnel.

In the event that any of the above events, or other unforeseen adverse events, materialize, PTTEP’santicipated benefits from the acquisition could be delayed, reduced or not occur at all, any of which couldmaterially and adversely affect PTTEP’s business, financial condition, results of operations and prospects.

SCP has only recently begun production and may not meet expectations for schedule or budget

The first of SCP’s five KKD fields, the Leismer field, began commercial production in January 2011, andhas no history of earnings, and there is no assurance that the Leismer field or any other future field developmentwill generate earnings, operate profitably or provide a return on investment in the future. Further, there can be noassurance that any future phase of development will commence operation on schedule. Expansions of the Leismerfield and development of the Corner field are currently both in the early stages of their planned developmentschedules. There is a risk that one or all of SCP’s fields or any other proposed commercial development of SCP’sassets will not be completed on time or within the applicable capital cost estimates or at all.

Additionally, there is a risk that one or all of SCP’s fields or any other proposed commercial developmentof SCP’s assets may have delays, interruptions of operations or increased costs due to many factors, including,without limitation: breakdown or failure of equipment or processes; construction performance falling belowexpected levels of output or efficiency; design errors; contractor or operator errors; non-performance bythird-party contractors; labor disputes, disruptions or declines in productivity; increases in materials or labor costs;inability to attract sufficient numbers of qualified workers; delays in obtaining or conditions imposed by,regulatory approvals; changes in project scope; violation of permit requirements; disruption in the supply ofenergy and other inputs, including natural gas and diluents; and catastrophic events such as fires, earthquakes,storms or explosions.

Given the stage of development of SCP’s KKD project, various changes are likely to be made prior to thecompletion of the project’s full development plan. KKD’s long term development plan extends beyond 2030 andmay be subject to re-evaluation. Any such material changes or delays in development that occur may result inincreased costs to PTTEP, and could have a material adverse effect on PTTEP’s business, financial condition,results of operations and prospects.

The price of bitumen is correlated with the market prices of heavy crude oil

SCP’s, and by extension PTTEP’s, results of operations and financial condition will be dependent upon,among other things, the prices that SCP receives for the bitumen, bitumen blend or other bitumen products that

26

SCP sells, and the prices that it receives for such products will be closely correlated to the price of crude oil.Historically, crude oil markets have been volatile and they are likely to continue to be volatile in the future. Crudeoil prices have fluctuated widely during recent years and are subject to fluctuations in response to relatively minorchanges in supply, demand, market uncertainty and other factors that are beyond SCP’s and PTTEP’s control.These factors include, but are not limited to: global energy policy, including the ability of the Organization of thePetroleum Exporting Countries (“OPEC”) to set and maintain production levels and influence prices for crude oil;political instability and hostilities and the risk of hostilities, particularly in the Middle East; domestic and foreignsupplies of crude oil; weather conditions; the overall level of energy demand; government regulations and taxes;currency exchange rates; the availability of transportation infrastructure; the effect of worldwide environmentaland/or energy conservation measures; the price and availability of alternative energy supplies; and the overalleconomic environment.

Any prolonged period of low crude oil prices could result in a decision by SCP and its investors to suspendor slow development activities, to suspend or slow the construction or expansion of bitumen recovery projects, or(following the commencement of production) to suspend or reduce production levels. Any of such actions couldhave a material adverse affect on PTTEP’s results of operations and financial condition.

There is no generally recognized approach to determine the constant price for bitumen because the bitumenmarket is not yet mature and there are no published reference prices for bitumen. To price bitumen, marketersapply formulas that take as a reference point the prices published for crude oil of particular qualities such asEdmonton Light, Lloydminster Blend, or the more internationally known WTI. The price of bitumen fluctuateswidely during the course of a year, with the lowest prices typically occurring at the end of the calendar yearbecause of decreased seasonal demand for asphalt and other bitumen-derived products coupled with higher pricesfor diluents added to facilitate pipeline transportation of bitumen.

The market prices for heavy oil (which includes bitumen blends) are lower than the established marketindices for light and medium grades of oil, which PTTEP generally produces, due principally to diluent prices andthe higher transportation and refining costs associated with heavy oil. Also, the market for heavy oil is morelimited than the markets for light and medium grades of oil, making it more susceptible to supply and demandfundamentals. Future price differentials are uncertain and any increase in the heavy oil differentials could have anadverse effect on SCP’s results of operations and financial condition.

As of December 31, 2010, SCP conducted an assessment of the carrying value of its assets to the extentrequired by IFRS and will continue to do so in the future. If crude oil prices decline, the carrying value of SCP’sassets could be subject to downward revision, and SCP’s earnings could be adversely affected. Accordingly, thesepossibilities may materially and adversely affect PTTEP’s business, financial condition, results of operations andprospects.

The steam assisted gravity drainage bitumen recovery process is subject to uncertainty

One method by which SCP may recover bitumen is through the steam assisted gravity drainage process(“SAGD”), a process which is subject to uncertainty. The SAGD bitumen recovery process has had a limitedoperating history in commercial projects and there can be no assurance that SCP’s operations will producebitumen at the expected levels, costs or on schedule. Current SAGD technologies require a significant amount ofnatural gas in the production of steam that is used in the recovery process. The amount of steam required in theproduction process can also vary and affect costs. SCP has no operating history with respect to the averageoperating steam to oil ratio for its projects. Should the actual average operating steam to oil ratio in commercialoperations be higher than SCP’s estimates, it may result in one or more of the following: an increase in operatingcosts; lower bitumen production; or, the requirement for additional facilities.

In addition, should SCP encounter adverse reservoir conditions during the development of the project,ultimate bitumen recovery levels achieved by SCP utilizing the SAGD recovery process may be negativelyimpacted. Such adverse reservoir conditions could include, but are not limited to, the following: regional poorquality geological features; depleted or partially depleted associated gas caps due to prior gas production; theexistence of bottom or top water, inter-formation water, or any other formations into which bitumen can be lost;or the absence of an overlying cap rock.

Any of the foregoing events could have a material impact on the future operating activities conducted at, andthe economic performance of, SCP’s projects, which in turn could have a material effect on PTTEP’s business,financial condition, results of operations and prospects.

27

The SCP land leases are subject to renewal in the near future

SCP operates on lands leased from the Government of Alberta through the Alberta Department of Energy(“Alberta Energy”). These lease agreements convey the right to drill for, work, recover and remove oil sands thatare owned by the Government. Existing oil sands agreements can be transferred between parties. There are twotypes of leases, primary and continued. Primary leases are original leases, while continued leases are primaryleases that have been renewed. SCP’s primary leases for various parcels of land expire between 2014 and 2022.

There is no automatic right of extension or renewal for oil sands leases. The lessee must apply to AlbertaEnergy to have the lease extended. If no application for continuation is made, the oil sands lease will automaticallyexpire. The written application must include detailed information on the lease number, technical evaluation orproduction data, the evaluation criteria used, maps, and the amount of annual rent due. No additional fees arerequired when applying for a lease continuation. Lease continuation is governed by the Oil Sands TenureRegulation (under the Mines and Minerals Act (Alberta)) (the “OSTR”). The main criteria that is used to determinewhether a primary lease will be continued depends on whether the lessee has begun production on the lease or not.If there is no production from a primary lease, the OSTR requires the lessee to achieve a minimum level ofevaluation (“MLE”) to renew the lease. The MLE can be achieved in two ways: (i) one evaluation well must bedrilled on each section included in the lease in a pattern that evaluates the lease and core data must be obtainedfor 25% of the wells drilled; or (ii) wells must be drilled on 60% of the sections included in the lease in a patternthat evaluates the lease, core data must be obtained for 25% of the wells drilled and appropriate seismic data isobtained from each undrilled section. An additional consideration is whether the lease rental fees have been paidon time.

There can be no assurance that SCP will be able to renew its leases on a timely manner or at all. If SCP isnot able to renew its leases, it could have a material adverse effect on PTTEP’s business, financial condition,results of operations and prospects.

The pro forma combined financial information for the year ended December 31, 2010 included in this OfferingMemorandum may not be indicative of actual results

PTTEP has included audited financial statements of SCP as of and for the year ended December 31, 2010and unaudited pro forma combined financial information for PTTEP as of and for the year ended December 31,2010 elsewhere in this Offering Memorandum. The pro forma combined results of operations included herein arenecessarily based on certain assumptions, including those identified in the notes to the unaudited pro formacombined financial information, and such information is not necessarily indicative of the operating results thatwould have been achieved had the acquisition of the interest in SCP been completed prior to January 1, 2010, noris it indicative of future operating results and it should not be relied upon as being so indicative.

This Offering Memorandum includes limited historical financial statements with respect to PTTEP’s recentlyacquired interest in SCP

PTTEP believes that the acquisition of an interest in SCP and the ongoing operations of SCP will have amaterial impact on PTTEP’s business, financial condition, results of operations and prospects in the future.Although PTTEP has included elsewhere in this Offering Memorandum audited financial statements of SCP as ofand for the year ended December 31, 2010 and unaudited pro forma combined financial information as of and forthe year ended December 31, 2010 giving effect to the acquisition of its interest in SCP as if the acquisition hadoccurred as of January 1, 2010, PTTEP has not included in this Offering Memorandum any other audited historicalfinancial information of SCP as a separate entity prior to the acquisition. As noted above, the unaudited pro formafinancial statements do not necessarily indicate the results of operations or the combined financial position thatwould have resulted had PTTEP acquired its interest in SCP as of January 1, 2010. Therefore, the non-inclusionof such other historical audited financial statements could affect investors’ ability to properly evaluate the effectof these acquisitions on PTTEP’s business, financial condition, results of operations and prospects.

28

Risks Relating to Thailand

Most of PTTEP’s assets and operations are located in Thailand and PTTEP is subject to economic, legal andregulatory uncertainties in Thailand

Most of PTTEP’s assets and operations, including its headquarters, are located in Thailand. Consequently,PTTEP is subject to political, legal and regulatory conditions in Thailand that differ in certain significant respectsfrom those prevailing in other countries with more developed economies. There is no assurance that the Thaieconomy will meet current projections or improve in the future. Any downturn in the Thai economy could havea material adverse effect on PTTEP’s business, financial condition, results of operations and prospects and themarket price of the Notes. Furthermore, prior Governments have, in the past, intervened in the Thai economy andoccasionally made significant changes in policy including, among other things, foreign exchange control, policiesconcerning wage and price controls, capital controls and limits on imports, at times partially reversing suchpolicies soon after the new policies were announced.

PTTEP’s businesses and operations in Thailand are subject to the changing economic conditions prevailingfrom time to time in Thailand. From 1996 to 1998, Thailand’s GDP growth slowed significantly in relation tohistorical levels and the country entered a recession. Since 1999, Thailand’s economy has been recovering,recording positive GDP growth each year until the global economy began to worsen in 2008. According to theBank of Thailand, Thailand’s GDP grew by 5.0% in 2007 and 2.5% in 2008, but declined by 2.3% in 2009. Despitethe political unrest in the early part of 2010, according to the Bank of Thailand, Thailand’s GDP grew by 7.8%in 2010. This growth is linked to the global economic recovery and the growth of Thai exports, which grew by28.1% in 2010. Nevertheless, the continued prospects for the global and regional economy are uncertain. Thedemand for energy is generally correlated with GDP, and a contraction in Thailand’s GDP could lead to a reductionin the demand for energy, which could have a material adverse effect on PTTEP’s business, financial condition,results of operations and prospects.

From 1996 to 1998, international credit rating agencies, including Moody’s and S&P, lowered Thailand’ssovereign rating as well as various Thai corporate debt ratings. With the improved performance of the Thaieconomy in 1999 through 2003, there was corresponding improvement in these credit ratings. Political unrest inlate 2008 and early 2009 again put downward pressure on Thailand’s sovereign ratings. Thailand’s sovereignforeign currency long term ratings are currently rated “Baa1” with a negative outlook by Moody’s and “BBB+”with a negative outlook by S&P. Future lowering of the credit ratings for Thai sovereign debt may make it moreexpensive for PTTEP to obtain additional debt financing for its working capital and capital expenditures, whichcould have an adverse effect on its financial condition.

Additionally, prior Governments have, in the past, intervened in the Thai economy and occasionally madesignificant changes in policy. Policy changes made by the Government and the Bank of Thailand have includedthe imposition (and subsequent reversal) of a one-year 30% unremunerated reserve requirement on foreignexchange inflows, under which any foreigner buying stock in Thailand had to place an extra non-interest-bearingdeposit. There is no assurance that the Government will not in the future re-impose restrictive foreign exchangecontrols that may affect the outward remittance of funds, including dividends payable on PTTEP’s shares.PTTEP’s business, financial condition, results of operations and prospects and the market price of the Notes maybe adversely affected by future changes in Government policies.

There is no assurance that the Thai economy will meet current projections or improve in the future. Anyinstability or economic downturn in Thailand could have a material adverse effect on PTTEP’s business, financialcondition, results of operations and prospects and the market price of the Notes.

Political conditions in Thailand will have a direct impact on PTTEP’s business and the market price of theNotes

PTTEP is subject to a political, economic, legal and regulatory environment in Thailand that differs incertain significant respects from that prevailing in countries with more developed economies. PTTEP’s business,financial condition, results of operations and prospects may be influenced in part by the political situation inThailand, which has been unstable from time to time. In 2006, there was a military coup against the country’scivilian political leadership. The coup leaders declared martial law and abrogated the 1997 Constitution. In 2007,the new Constitution came into force and a general election was subsequently held. Two new coalitiongovernments took office in February and September 2008, respectively. There were a series of anti-governmentprotests in 2008, including an occupation by protestors of the Government House and the seizure of Thailand’stwo key airports.

29

In December 2008, the Thai Constitutional Court issued a verdict that disbanded certain governmentpolitical parties, which dissolved the existing coalition government and removed the Prime Minister from office.The leader of the Democrat-led coalition was voted in as the new Prime Minister by the Thai Parliament inDecember 2008. There have been a series of protests and demonstrations evidencing resistance to the currentcoalition government.

In March 2010, anti-government protestors (being supporters of the former Prime Minister ThaksinShinawatra, who was ousted in a military coup in 2006) launched new protests aimed at removing the coalitiongovernment and holding new elections. Over the course of two months, the demonstrations turned violent, causingthe government to declare a state of emergency in Bangkok on April 7, 2010 and later in 23 other provinces incentral, northern and northeastern Thailand. In an effort to clear the protest sites, the Government imposed curfewsand restricted numbers at gatherings. A number of buildings, including a major shopping center, governmentbuildings and the stock exchange, were set on fire by certain demonstrators, causing serious damage. A numberof people were also killed and injured. After the end of the demonstrations, the curfews were gradually lifted. Thestate of emergency ended on December 21, 2010. The Government is currently pursuing a five point nationalreconciliation program to address the social and economic disparities and inequalities cited by the demonstratorsand mend political divisions. There can be no assurance that such national reconciliation plan will successfullyresolve such divisions or that protests or other violent demonstrations will not recur.

The effect of these events on political, economic and legal conditions in Thailand remains uncertain.Prolonged political instability in Thailand could have a material adverse effect on economic and legal conditionsin Thailand, which in turn could have a material adverse effect on PTTEP’s business, financial condition, resultsof operations and prospects.

Continued violence in southern Thailand, terrorist attacks and international and regional instability couldadversely affect PTTEP’s business, financial condition, results of operations and prospects

In 2004, the Government declared martial law in certain southern provinces. The region recently hasexperienced increasingly serious and frequent incidents of violence, including bombings of power stations, whichcaused blackouts in the provinces. On July 19, 2005, the Government invoked an emergency decree to declare astate of emergency in the three southernmost provinces of Yala, Narathiwat and Pattani. The state of emergencyimposed further controls in those provinces and allows the authorities to detain suspects without charge, ban publicprotests and censor the news media. Since January 2004, there have been a large number of casualties and injuriesarising from violence in the region, including, most recently, bombings of commercial banks in the Yala province.On December 31, 2006, several bombs exploded in Bangkok, killing three people, and in February 2007 acoordinated series of explosions in Southern Thailand, including in schools, killed at least eight people. In March2010, anti-government protestors launched new protests aimed at removing the coalition government and holdingnew elections, which eventually required the government to declare a state of emergency in Bangkok on April 7,2010. A number of countries, including the United States, the United Kingdom, Australia and Canada have issuedtravel advisories relating to travel to Thailand in recent years. Continued violence could lead to widespread unrestin Thailand or a major terrorist incident in Thailand similar to those in other parts of Southeast Asia. If the securitycondition deteriorates and violence spreads to the Northern provinces of Thailand, PTTEP’s business, financialcondition, results of operations and prospects may be materially and adversely affected.

In addition, political events in the Middle East, including future terrorist attacks against targets in the MiddleEast, Southeast Asia or other regions, rumors or threats of terrorist attacks or war, actual conflicts involving theMiddle East and trade disruptions, all of which may impact PTTEP’s suppliers or customers, may adverselyimpact its operations. Political or economic developments related to these crises could adversely affect the Thaieconomy and the global economy and could have a material adverse effect on PTTEP’s business, financialcondition, results of operations and prospects.

30

PTTEP faces risks related to public health epidemics in Thailand

PTTEP’s business could be materially and adversely affected by the outbreak of public health epidemics inThailand. In April 2009, an outbreak of the H1N1 virus, commonly referred to as “swine flu,” occurred in Mexicoand spread to other countries, including Thailand. If the outbreak of swine flu were to become widespread inThailand or increase in severity, it could have an adverse effect on economic activity in Thailand, and couldmaterially and adversely affect PTTEP’s business, financial condition and results of operations. Any future publichealth epidemics in Thailand could materially and adversely affect PTTEP’s business, financial condition, resultsof operations and prospects.

Fluctuations in the value of the Baht could adversely affect demand for PTTEP’s products and its financialcondition and results of operations

Since the Asian financial crisis of 1997, the value of the Baht against the U.S. dollar has fluctuated from timeto time, from a high of Baht 22.20 on June 18, 1997 to a low of Baht 56.45 on January 13, 1998, according toBloomberg. The Bank of Thailand weighted-average interbank exchange rate equaled Baht 30.611 per U.S. dollaron December 31, 2010. PTTEP cannot assure you that the value of the Baht will not decline or continue tofluctuate significantly against the U.S. dollar or other currencies in the future.

Substantially all of PTTEP’s revenues and costs, although denominated in Baht, are directly or indirectlylinked to, or affected by, the U.S. dollar. Depreciation in the value of the Baht tends to have a beneficial effecton PTTEP’s revenues and a detrimental effect on PTTEP’s costs. Conversely, appreciation in the value of the Bahttends to have a detrimental effect on PTTEP’s revenues measured in Baht. In addition, adverse economicconditions in Thailand incidental to the depreciation of the value of the Baht could increase energy prices inThailand and reduce overall demand for PTTEP’s products and those of PTTEP’s customers which may partiallyoffset the benefits of depreciation. Significant fluctuations in the Baht against the dollar could have an adverseeffect on PTTEP’s revenues and results of operations.

As of December 31, 2010, PTTEP had outstanding long-term foreign debt and it is possible that a substantialportion of PTTEP’s capital expenditures for future expansion programs may be incurred and/or financed in foreigncurrencies. Any depreciation in the Baht against the dollar would increase PTTEP’s financing costs, and there canbe no assurance that PTTEP would be able to generate revenue increases sufficient to offset such increasedfinancing costs. As a result, fluctuations in the value of the Baht against other foreign currencies may adverselyaffect PTTEP’s financial condition and results of operations.

As of January 1, 2011, PTTEP adopted the U.S. dollar as its official reporting currency. While this willreduce the effect of exchange rates on sales denominated in U.S. dollars, PTTEP still has some costs denominatedin Baht and faces some currency exchange effects. Further, the preparation for the transition, as well as actualtransition, is likely to result in significant costs for PTTEP and may have a material adverse effect on its resultsof operations. See, also “ PTTEP may incur significant costs in preparing for and complying with IFRS and maynot be able to fully comply with such standards.”

Non-enforceability of non-Thai judgments may limit your ability to recover damages from PTTEP

Under Thai law, judgments entered by a United States court or any other non-Thai court, including actionsunder the civil liability provisions of the U.S. federal securities laws, are not enforceable in Thailand. An investorwould have to bring a separate action or claim in Thailand. Although a non-Thai judgment could be introducedas evidence in a court proceeding in Thailand, a Thai court would be free to examine de novo issues arising in thecase.

Under the Petroleum Act B.E. 2514 (1971), the rights to hold the petroleum concession shall not be subjectto the execution of judgment. Thus, to the extent investors are entitled to bring a legal action against PTTEP, theymay be limited in their remedies and any recovery and any Thai proceeding may be limited depending on therelevant court’s discretion.

PTTEP’s auditor is the Office of the Auditor General of Thailand, which may not be considered independentunder IFRS

As required by Thai law for state-owned enterprises, PTTEP’s auditor is the Office of the Auditor Generalof Thailand. The Office of the Auditor General of Thailand is an independent auditor with respect to PTTEP withinthe meaning of the standards established for independent auditors in Thailand. PTTEP cannot assure you, however,that it would be considered to be an independent auditor with respect to PTTEP within the meaning of thestandards established under IFRS, in the United States or elsewhere.

31

PTTEP’s most recent financial statements were prepared in accordance with Thai GAAP, which differs fromIFRS

PTTEP is subject to financial reporting requirements of publicly listed companies in Thailand that differ insignificant respects from those applicable to companies in certain other countries, including the United States andthe United Kingdom. PTTEP’s financial statements have historically been prepared in accordance with ThaiGAAP, which differs in certain material respects from IFRS. See “Summary of Principal Differences BetweenThai GAAP and IFRS.”

In addition, the Office of the Auditor General of Thailand has only audited the financial informationappearing in the Offering Memorandum in accordance with Thai GAAP and is not qualified to prepare a summaryof differences between Thai GAAP and IFRS. In accordance with generally accepted accounting practices inThailand, neither PTTEP nor the Office of the Auditor General of Thailand has (i) performed a reconciliation ofthe financial statements included in this Offering Memorandum to IFRS or (ii) quantified the differences betweenThai GAAP and IFRS with respect to such financial statements. If such a reconciliation or quantification had beenperformed, other material differences might have been identified and disclosed in the Summary of PrincipalDifferences Between Thai GAAP and IFRS. Accordingly, there is no assurance that the identified differences inthe Summary of Principal Differences Between Thai GAAP and IFRS represent all material differences related toPTTEP and PTTEP’s subsidiaries as of and for the years ended December 31, 2008, 2009 and 2010.

As of January 1, 2011, PTTEP will report its financial results in accordance with IFRS requirements, therebydetermining its functional currency to be U.S. dollars. See “PTTEP may incur significant costs in preparing forand complying with IFRS and may not be able to fully comply with such standards” and “Management’sDiscussion and Analysis of Financial Condition and Results of Operations — Adoption of New AccountingStandards.”

PTTEP may incur costs in preparing for and complying with IFRS and may not be able to fully comply withsuch standards

The Stock Exchange of Thailand and the Federation of Accounting Professions have announced that Thaicompanies should adopt the revised Thai Accounting Standards, which are comprised of amendments to ThaiAccounting Standards, new Thai Accounting Standards, new Thai Financial Reporting Standards and new ThaiFinancial Reporting Interpretations. These Thai standards, which were published in the Government Gazette, aresubstantially the same as IFRS. In addition, PTTEP applied International Accounting Standards (IAS) 32“Financial Instruments: Presentation,” IAS 39 “Financial Instruments: Recognition and Measurement” andInternational Reporting Standards (IFRS) 7 “Financial Instruments: Disclosures.” For Thailand’s 50 most activelytraded public companies, including PTTEP, compliance began on January 1, 2011. Currently, IFRS are thefinancial reporting standards adopted or allowed in more than 120 countries and approximately 90 countries havefully conformed with IFRS. IFRS has requirements that are substantially different from those under Thai GAAP.The preparation for compliance, as well as actual compliance, is likely to result in costs for PTTEP and may havea material adverse effect on its results of operations. See “Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Adoption of New Accounting Standards.”

Risks Relating to this Offering

PTTEP’s business activities in Myanmar may restrict the ability of U.S. persons to invest in the Notes

In 1996, the U.S. Congress enacted legislation (Section 570 of the Foreign Operations Export Financing, andRelated Programs Appropriations Act, 1997 (Public Law 104-208)) authorizing the President of the United Statesto impose economic sanctions on Myanmar to foster the protection of human rights and democratic government.On May 20, 1997, the U.S. government issued an order which prohibits “new investment” in Myanmar by U.S.persons and the facilitation by U.S. persons of new investment in Myanmar by foreign persons. The U.S.government has renewed the investment ban every six months since 1997. The Burmese Sanctions Regulations(“BSR”), which implement the executive order, define new investment to include activities undertaken pursuantto agreements with the government of Myanmar or non-governmental entities in Myanmar that involve: (a) entryinto a contract that includes the economic development of resources located in Myanmar; (b) entry into a contractthat provides for the general supervision and guarantee of another person’s performance of such a contract; (c)entry into a contract providing for the participation in royalties, earnings, or profits in the economic development

32

of resources located in Myanmar, regardless of the form of participation; or (d) purchase of an equity interest orshare of ownership in the economic development of resources located in Myanmar. In 2003 and 2008, the UnitedStates imposed or extended new economic sanctions against Myanmar which prohibit the importation to the U.S.of Burmese products and the exportation to Myanmar of U.S. financial services.

Although PTTEP’s subsidiary, PTTEPI has entered into agreements to develop natural gas reserves locatedin Myanmar, PTTEP does not believe that a purchase of the Notes by a U.S. person would constitute a prohibited“new investment” in Myanmar under the BSR predominately because PTTEP’s profits are (a) generated byPTTEP’s economic development resources located in Myanmar (per Section 560.412 of the BSR) and (b) notpredominately derived from the efforts of U.S. persons employed by PTTEP. However, PTTEP cannot assure youthat a U.S. court or regulatory agency would agree with this conclusion. A contrary determination could adverselyaffect PTTEP’s ability to raise funds from the U.S. capital markets and U.S. persons owning the Notes potentiallycould be required to divest themselves of the Notes, among other potential regulatory and legal implications,including an enforcement action by U.S. authorities.

In addition, the BSR prohibit the approval or other facilitation by U.S. persons of a transaction by a non-U.S.person that would constitute a new investment in Myanmar as defined in the BSR. If the Initial Purchaser werea U.S. Person or included U.S. persons in the relevant activity and found to have contravened the BSR by“facilitating” a new investment in Myanmar through the offering of the Notes, any regulatory action against theInitial Purchaser resulting from such finding could adversely affect holders of the Notes as a result of a declinein the price of the Notes or otherwise.

The Notes are subject to transfer restrictions

The Notes will not be registered under the Securities Act or any state securities laws and may not be offeredor sold within the United States or to, or for the account or benefit of, U.S. persons, except to QIBs in relianceon the exemption provided by Rule 144A, to certain persons in offshore transactions in reliance on Regulation S,or pursuant to another exemption from, or in another transaction not subject to, the registration requirements ofthe Securities Act and in accordance with applicable state securities laws. Neither may the Notes be offered or soldin Canada or to or for the benefit of any residents thereof except to Accredited Investors or, as the case may be,Permitted Clients. For a further discussion of the transfer restrictions applicable to the Notes, see “TransferRestrictions.”

There is no public market for the Notes

The Notes will be a new issue of securities with no existing trading market. Approval-in-principle has beenreceived for a listing of the Notes on the SGX-ST. However, PTTEP cannot assure you that it will be able to obtainor maintain such listing or that, if listed, a liquid trading market will develop for the Notes. The Initial Purchaserhas informed PTTEP that they currently intend to make a market in the Notes, although they are not obligated todo so and any such market making activities may be discontinued at any time without notice. Accordingly, eventhough the Notes may be listed on an exchange, PTTEP cannot assure you that an active market will develop forthe Notes or as to the liquidity of, or the trading market for, the Notes. If an active market does develop, futuretrading prices of the Notes will depend on many factors, including, among others, prevailing interest rates,PTTEP’s operating results and the market for securities similar to the Notes.

The Notes will initially be held in book-entry form, and therefore you must rely on procedures of the relevantclearing systems to exercise any rights and remedies

Unless and until Notes in definitive registered form, or definitive registered Notes are issued in exchangefor book-entry interests (which may occur only in limited circumstances), owners of book-entry interests will notbe considered owners or Noteholders. The common depository (or its nominee) for DTC will be the sole registeredholder of the global notes. Payments of principal, interest and other amounts owing on or in respect of the relevantglobal notes representing Notes will be made to The Bank of New York Mellon, as principal paying agent, whichwill make payments to DTC. Thereafter, these payments will be credited to participants’ accounts that holdbook-entry interests in the global notes representing the Notes and credited by such participants to indirectparticipants. After payment to the common depository for DTC, the Issuer will have no responsibility or liabilityfor the payment of interest, principal or other amounts to the owners of book-entry interests. Accordingly, if youown a book-entry interest in the Notes, you must rely on the procedures of DTC and if you are not a participantof DTC, on the procedures of the participant through which you own your interest, to exercise any rights andobligations of a holder of the Notes under the Indenture.

33

Unlike holders of the Notes themselves, owners of book-entry interests will not have any direct rights to actupon any solicitations for consents, requests for waivers or other actions from holders of the Notes. Instead, if youown a book-entry interest, you will be permitted to act only to the extent you have received appropriate proxiesto do so from DTC or, if applicable, from a participant. There can be no assurance that procedures implementedfor the granting of such proxies will be sufficient to enable you to vote on any matters on a timely basis.

Similarly, upon the occurrence of an event of default under the Indenture, unless and until the relevantdefinitive registered Notes are issued in respect of all book-entry interests, if you own a book-entry interest, youwill be restricted to acting through DTC. The Issuer cannot assure you that the procedures to be implementedthrough DTC will be adequate to ensure the timely exercise of rights under the Notes.

The Issuer is a special purpose finance company with limited assets and is dependent on intercompany loansfrom PTTEP

The Issuer is a special purpose finance company which is an indirect subsidiary of PTTEP. The Issuer willon-lend the proceeds from the sale of the Notes to one or more subsidiaries of PTTEP (the “Intercompany Loan”).The Issuer will depend on payments on the Intercompany Loan to provide it with funds to meet its obligationsunder the Notes, including payments of interest and principal thereon.

The Issuer has limited assets, no subsidiaries, and a limited ability to generate revenues. See “The Issuer.”Upon completion of the offering of the Notes, the only significant assets of the Issuer will be the receivables underthe Intercompany Loan. The Issuer’s material liabilities will be the Notes. As such, the Issuer will be dependentupon payment under the Intercompany Loan to make any payments due on the Notes. Should any of the borrowingsubsidiaries be unable to fund the Intercompany Loan in the future, the Issuer would be unable to meet itsobligations under the Notes.

The Notes and the Guarantee are unsecured obligations

As the Notes and the Guarantee are unsecured obligations of the Issuer and PTTEP, respectively, theirrepayment may be compromised if:

1. the Issuer and/or PTTEP enters into bankruptcy, liquidation, reorganization or other winding-upproceedings;

2. there is a default in payment under the Issuer’s and/or PTTEP’s future secured indebtedness or otherunsecured indebtedness; or

3. there is an acceleration of any of the Issuer’s and/or PTTEP’s indebtedness;

and the Issuer’s or PTTEP’s assets are not sufficient to pay amounts due on the Notes.

Investors may have difficulty enforcing judgments against the Issuer, PTTEP or their management

The Issuer is a private company with limited liability incorporated in the Province of Alberta, Canada.PTTEP is a company established under the laws of the Kingdom of Thailand. All of the directors of the Issuer andPTTEP reside outside the United States. Substantially all of the assets of the Issuer and PTTEP and these otherpersons are located outside the United States. As a result, it may be difficult for investors to effect service ofprocess upon the Issuer, PTTEP or such persons within the United States or other jurisdictions, or to enforceagainst the Issuer, PTTEP or such persons in such jurisdiction, judgments obtained in courts of that jurisdiction,including judgments predicated upon the civil liability provisions of the federal securities laws of the United Statesor any state thereof. In particular, investors should be aware that judgments of United States courts based uponthe civil liability provisions of the federal securities laws of the United States or any state thereof may not beenforceable in Thai and Canadian courts and Thai and Canadian courts may not enter judgments in original actionsbrought in those courts based solely upon the civil liability provisions of the securities laws of the United Statesor any state thereof. See “Enforcement of Civil Liabilities.”

34

The interests of PTTEP’s principal shareholder may conflict with the interests of Noteholders

The majority of PTTEP’s shares are owned by PTT, and through its share ownership in PTTEP, PTT hassignificant influence over PTTEP, including, depending on the number of shareholders who attend PTTEP’sshareholders’ meetings, the power to elect a majority of PTTEP’s board of directors and determine the outcomeof any action requiring shareholder approval, as well as the power to affect PTTEP’s legal and capital structureand PTTEP’s day-to-day operations. PTT, through PTTEP and otherwise, has other business interests outsidePTTEP and its subsidiaries and may take actions that favor the interests of such other companies over the interestsof PTTEP and its subsidiaries or that may conflict with the interests of Noteholders.

35

USE OF PROCEEDS

The net proceeds from the sale of the Notes, which are estimated to be approximately U.S.$699,720,000million after payment of commissions to the Initial Purchaser but before expenses payable by the Issuer and theCompany, will be used for general corporate purposes, including, but not limited to, funding the Company’sexploration, development and production activities.

36

EXCHANGE RATE INFORMATION

Prior to July 2, 1997, the Bank of Thailand maintained the value of the Baht based on a basket of foreigncurrencies, the composition of which was not made public, but of which the dollar was believed to be the principalcomponent. On July 2, 1997, the Government announced that it would no longer intervene to maintain theexchange rate at any particular level, which resulted in a substantial decrease in the value of the Baht against thedollar.

The following table presents, for the periods indicated, exchange rate information relating to the conversionof Thai Baht into U.S. dollars. PTTEP is providing this information solely for your convenience. These are notnecessarily the rates PTTEP used in the preparation of its financial statements and PTTEP makes no representationthat the Baht or U.S. dollar amounts set forth herein or referred to elsewhere in this Offering Memorandum couldhave been, or could be, converted into U.S. dollars or Baht, as the case may be, at the rates indicated, at anyparticular rates, or at all.

(Bt per dollar) At Period End(1) Average(2) Low(1) High(1)

Period2006 .................................................................... 36.231 37.934 35.288 41.0412007 .................................................................... 33.885 34.564 33.390 36.2342008 .................................................................... 35.082 33.382 31.277 35.8622009 .................................................................... 33.517 34.318 33.258 36.3492010 .................................................................... 30.296 31.701 29.705 33.4392011

January............................................................ 31.283 30.584 30.190 31.283February.......................................................... 30.757 30.716 30.689 31.024March (through March 24) ............................ 30.437 30.362 30.339 30.732

Source: Bank of Thailand

(1) Amounts are based on daily average selling price.

(2) Averages are based on daily reference rates.

On February 28, 2011, the weighted-average interbank exchange rate was Baht 30.611 = U.S.$1.00.

37

THE ISSUER

General

The Issuer is a company incorporated in Alberta, Canada on February 25, 2011. The Issuer is an indirectwholly-owned subsidiary of PTTEP, incorporated for the primary purpose of borrowing and raising other financialaccommodations on behalf of PTTEP and its subsidiaries and advancing the net proceeds of such borrowings andraising to PTTEP and its subsidiaries. Prior to the issue of the Notes, the Issuer had limited assets, no liabilitiesand no operations.

Directors

The current directors of the Issuer and their business addresses are as follows:

Mr. Michael Laffin855-2nd Street S.W.Suite 3500, Bankers Hall East TowerCalgary, AB T2P 4J8Canada

Ms. Penchun JarikasemEnergy Complex Building A 6th Floor & 19th � 36th Floor555/1 Vibhavadi-Rangsit RoadBangkok 10900Thailand

Mr. Yothin TongpenyaiEnergy Complex Building A 6th Floor & 19th � 36th Floor555/1 Vibhavadi-Rangsit RoadBangkok 10900Thailand

The address of the Issuer’s registered office is at 3500, 885 � 2 Street SW, Calgary Alberta T2P 4J8,Canada.

The Issuer has full power and authority to carry out any object not prohibited by the laws of Canada.

No part of the equity securities of the Issuer is listed or dealt on any stock exchange and no listing orpermission to deal in such securities is being or is proposed to be sought. As of the date of this OfferingMemorandum, the Issuer does not have any debt outstanding.

The Issuer has no subsidiaries. The Issuer has not audited or published, and does not propose to audit orpublish, any of its accounts and it is not, except in unusual circumstances, required to do so under the laws ofCanada. The Issuer’s non-audited financial statements are not published and are prepared only for internalpurposes. The Issuer is, however, required to keep such accounts and records as are necessary to give a true andfair view of the Issuer’s affairs and to explain its transactions. If the Issuer publishes any of its accounts, suchpublished accounts of the Issuer will, in the event that and for as long as the Securities are listed on the SGX-STand the rules of the SGX-ST so require (or for as long as the Securities are listed on another stock exchange andits rules so require), be made available free of charge at the offices of the Trustee.

38

CAPITALIZATION

The following table sets out PTTEP’s consolidated capitalization as of December 31, 2010, and as adjustedto give effect to the issuance of the Notes and the use of the proceeds as discussed in “Use of Proceeds.”

As of December 31, 2010 Adjusted for the offering

(Bt) (U.S.$)(1) (Bt) (U.S.$)(1)

(in millions)

Short-term debt:Current portion of long-term debt .................... — — — —Short-term loans ................................................. 7,945 262 7,945 262Long-term debt:Long-term loans ................................................. 69,893 2,307 69,893 2,307The Notes ........................................................... — — 21,207 700

Total debt........................................................... 77,838 2,569 99,045 3,269

Shareholder’s equity:Share capital (registered) ................................... 3,322 110 3,322 110Share capital (issued and paid-up)..................... 3,317 109 3,317 109Share premium ................................................... 14,183 468 14,183 468Retained earnings ............................................... 157,746 5,207 157,746 5,207Currency translation differences ........................ (2,952) (97) (2,952) (97)

Total shareholder’s equity ............................... 172,294 5,687 172,294 5,687

Total capitalization ........................................... 250,132 8,256 271,339 8,956

(1) The U.S. dollar translations are provided for indicative purposes only and are unaudited. These translations were calculated based on

an exchange rate as of December 30, 2010 of Baht 30.296 to U.S.$1.00.

On November 24, 2010, PTTEP Offshore Investment Company Limited (“PTTEPO”) entered into aU.S.$500 million unsecured, unsubordinated loan agreement, fully guaranteed by PTTEP, with the Bank ofTokyo-Mitsubishi UFJ, Ltd., Mizuho Corporate Bank, Ltd., Oversea-Chinese Banking Corporation Limited andSumitomo Mitsui Banking Corporation. On December 1, 2010, PTTEPO entered into a U.S.$75 millionunsecured, unsubordinated loan agreement, fully guaranteed by PTTEP, with Mizuho Corporate Bank, Ltd. OnDecember 9, 2010, PTTEP entered into a U.S.$50 million unsecured, unsubordinated loan agreement withThanachart Bank Public Company Limited. On January 14, 2011, PTTEP and PTTEPO drew down the entire loanamount of these three loans, U.S.$625 million of which amount was used for partial payment of PTTEP’s 40%interest in SCP. Each of these loan facilities is repayable in 2015 and none are subject to financial covenants.

On March 11, 2011, PTTEP entered into a Baht 20,000 million unsecured, unsubordinated loan agreementwith Krung Thai Bank Public Company Limited. The loan is not subject to any financial covenants and isrepayable within one year of the first drawdown. PTTEP plans to draw down Baht 5,000 million on March 31,2011 and expects to draw down the remaining Baht 15,000 million by the end of May 2011.

Except as otherwise disclosed in this Offering Memorandum, there has been no material adverse change inPTTEP’s capitalization or indebtedness since December 31, 2010.

39

MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with PTTEP’s consolidated financial statements,selected historical financial and operating and reserves data, in each case together with the accompanying notesincluded elsewhere in this Offering Memorandum. The consolidated financial statements have been prepared inaccordance with Thai GAAP, which differs in certain material respects from IFRS. For a description of certaindifferences between Thai GAAP and IFRS, see “Summary of Principal Differences Between Thai GAAP andIFRS.”

Commencing January 1, 2011, PTTEP adopted the amendments to Thai Accounting Standards, new ThaiAccounting Standards, new Thai Financial Reporting Standards and new Thai Financial ReportingInterpretations, as mandated by the Stock Exchange of Thailand and the Federation of Accounting Professions.These Thai standards, which were published in the Government Gazette, are substantially the same as IFRS. Inaddition, PTTEP applied International Accounting Standards (IAS) 32 “Financial Instruments: Presentation,”IAS 39 “Financial Instruments: Recognition and Measurement” and International Reporting Standard (IFRS) 7“Financial Instruments: Disclosures.” The audited consolidated financials statements included in this OfferingMemorandum were prepared in accordance with Thai GAAP and were not restated according to IFRS. PTTEP’smanagement has determined that, there will not be any significant impact of the amendments to accountingstandards except as disclosed in Note 4 on page F-14 of the Financial Statements. See “PTTEP may incursignificant costs in preparing for and complying with IFRS and may not be able to fully comply with suchstandards.”

Overview

PTTEP derives substantially all of its sales revenue from the sale of natural gas, crude oil and condensateproduced from petroleum projects in which PTTEP has a working interest. PTTEP also derives revenue from itspipeline transportation business. PTTEP’s results of operations depend upon the natural gas, crude oil andcondensate production volumes at each of the projects in which it has a working interest, the price of such naturalgas and crude oil, and the exploration and production expenses of each petroleum right joint venture. PTTEP’stotal sales for each of the years ended December 31, 2008, 2009 and 2010 were Baht 132,621 million, Baht115,547 million and Baht 138,474 million (U.S.$4,571 million), respectively. During these same years, PTTEP’snet increase in cash and cash equivalents was Baht 19,753 million, Baht 4,834 million and Baht 11,224 million,respectively.

In 2010, sales of each of natural gas, crude oil, condensate and LPG were Baht 72,866 million, Baht 33,958million, Baht 30,939 million and Baht 711 million, respectively, and constituted 53%, 24%, 22% and 1% ofPTTEP’s total sales, respectively. In 2010, 71% of PTTEP’s total sales volume was represented by natural gassales, which is priced lower than oil. Arthit and Bongkot are PTTEP’s two largest natural gas fields in terms ofsales volume. Crude oil and condensate accounted for 15% and 14% of the total sales volume in 2010,respectively.

Factors Affecting Results of Operations

Sales of Natural Gas, Oil and Condensate

International supply and demand for petroleum products generally affect the price that PTTEP receives forits natural gas, crude oil and condensate production and, accordingly, PTTEP’s profitability. See “Risk Factors —Risks Relating to PTTEP’s Business — The volatility of prices for natural gas, crude oil and condensate and thecyclical nature of the oil and gas industry affect PTTEP’s results of operations.” In addition, a decrease in the rateof growth of demand for natural gas in Thailand may have a negative impact on PTTEP’s ability to negotiatefuture gas sales agreements.

Revenues from the sale of PTTEP’s petroleum products are paid directly to PTTEP by the purchaser of suchproducts proportionate to PTTEP’s attributable working interest in its joint venture projects.

Natural gas sales. In 2010, 98% of PTTEP’s natural gas sales revenue came from PTT through long termsales agreements. These agreements set minimum natural gas delivery schedules at prices that are adjustedperiodically to reflect changes to a stated benchmark price based on an average price per barrel of medium-sulphur(and in certain instances, low sulphur) fuel oil ex. Singapore and other adjustment factors, including Baht/U.S.dollar exchange rates, the U.S. Producer Price Index for Oilfield and Gasfield Machinery and Tools published bythe U.S. Department of Labor, inflation and taxes. See “Business — Production and Sales.”

40

The weighted average sales price per MMBtu at which PTTEP sold its natural gas production for each ofthe years ended December 31, 2008, 2009 and 2010 was U.S.$5.17, U.S.$5.17 and U.S.$5.52, respectively. Theaverage daily price per barrel of medium-sulphur fuel oil ex. Singapore for each of the years ended December 31,2008, 2009 and 2010 was U.S.$78.61, U.S.$57.03 and U.S.$72.36, respectively.

Oil sales. In 2010, 64% of PTTEP’s crude oil sales revenue came from PTT under long-term salesagreements. For S1’s long-term sales agreements, oil was sold at prices that are adjusted monthly to reflectchanges in specified market prices for certain types of crude oil, including Ardjuna, Minas, Oman Blend 1 SeriaLight, Mid Light and Arabian Light crude oils. The weighted average sales price per Bbl at which PTTEP soldits crude oil production for each of the years ended December 31, 2008, 2009 and 2010 was U.S.$90.08,U.S.$58.84 and U.S.$74.24, respectively. As of December 31, 2010, the price of Dubai Crude Oil is U.S.$89.14.The Company believes the higher price of oil is due to uncertainties regarding the supply of oil from the MiddleEast and North Africa and that it will remain at higher levels for the foreseeable future and which the Companyexpects will increase PTTEP’s revenues.

Condensate and LPG sales. PTTEP is party to condensate sales agreements with respect to its workinginterests in Bongkot, Arthit, Arthit North, Contract 3 (formerly Unocal III), Contract 4 (formerly Pailin), Oman44 and Sinphuhorm, and a liquefied petroleum gas (“LPG”) sales agreement with respect to its working interestin S1. The agreements provide for the sale to PTT of all of the condensate and LPG from the respective fields.Condensate prices are based on specified quoted condensate and light crude prices in U.S. dollars. The weightedaverage sales price per Bbl at which PTTEP sold its condensate production for each of the years ended December31, 2008, 2009 and 2010 was U.S.$92.88, U.S.$57.01 and U.S.$73.26, respectively. The LPG price is set in thecontract and is subject to adjustments to reflect changes in the posted price of LPG in Singapore, changes ingovernment policy and amendment by the parties. The weighted average sales price per metric ton at whichPTTEP sold its LPG production for each of the years ended December 31, 2008, 2009 and 2010 was U.S.$301.49,U.S.$294.24 and U.S.$308.58, respectively.

Expenses

PTTEP’s production, exploration and general administrative and other expenses reflect both expendituresincurred by PTTEP for activities at petroleum rights for which it is the sole concessionaire and directly conductsexploration and production activities, as well as its pro rata share of expenditures incurred by joint ventureoperators of petroleum rights in which PTTEP has a working interest. Under the terms of the joint ventureagreements to which PTTEP is a party, PTTEP generally is required to meet periodic cash calls by the joint ventureoperator to fund exploration, development and production activities agreed to by the respectiveco-concessionaires. PTTEP’s expenses are apportioned to PTTEP on a project-by-project basis in accordance withPTTEP’s respective working interest in each project, as reported by each joint venture’s operator. For projects inwhich PTTEP is not the operator, PTTEP’s auditors rely on financial information audited by other independentauditors appointed by the joint venture partners.

Consistent with PTTEP’s goal to maintain its position as a leading regional petroleum exploration andproduction company, PTTEP has increased its participation in petroleum exploration activities and, accordingly,expects its expenses in respect of such activities to continue to increase in the future. PTTEP’s principalexploration, development and production activities are being conducted at Myanmar Zawtika, Bongkot, PTTEPAustralasia, Arthit, S1, Contract 4, and the MTJDA. For a description of PTTEP’s current exploration activities,see “Business — Principal Properties.”

Effect of Exchange Rates on Net Sales

Substantially all of PTTEP’s revenues and costs, although denominated in Baht, are directly or indirectlylinked to, or affected by, the U.S. dollar. Depreciation in the value of the Baht tends to have a beneficial effecton PTTEP’s revenues and a detrimental effect on PTTEP’s costs. Conversely, appreciation in the value of the Bahttends to have a detrimental effect on PTTEP’s revenues measured in Baht. In addition, adverse economicconditions in Thailand incidental to the depreciation of the value of the Baht could increase energy prices inThailand and reduce overall demand for PTTEP’s products and those of PTTEP’s customers which may partiallyoffset the benefits of depreciation. Significant fluctuations in the Baht against the dollar could have an adverseeffect on PTTEP’s revenues and results of operations.

41

Certain of PTTEP’s gas sales agreements provide for an adjustment if the Baht/U.S. dollar exchange ratehas fluctuated by more than 5% in a given month. Such price adjustments operate as a partial hedging mechanismagainst fluctuations in the Baht/U.S. dollar exchange rate and have the effect of increasing or decreasing PTTEP’ssales revenues measured in Baht.

On January 1, 2011, PTTEP adopted the U.S. dollar as its official reporting currency. While this will reducethe effect of exchange rates on sales denominated in U.S. dollars, PTTEP still has some costs denominated in Bahtand faces some currency exchange effects. See “Business — Production and Sales — Natural Gas Sales” and“Risk Factors — Risks Relating to Thailand — Fluctuations in the value of the Baht could adversely affectdemand for PTTEP’s products and its financial condition and results of operations.”

The Montara Incident

In February 2009, PTTEP expanded its base of operation in Australia with the purchase of 100% of theequity of Coogee Resources Limited, which was engaged in oil and gas exploration and production projects,including the Jabiru, Challis and Montara fields. In August 2009, an oil and gas leak began during the MontaraH1’s development well drilling which continued until PTTEP AA stopped the leak in November 2009. The causesof the uncontrolled oil and gas release include deficiencies in the Montara H1 well cementing operation and wellbarrier testing and the failure to install all required pressure containing corrosion caps. In addition, other causativefactors in the uncontrolled oil and gas release may have included inadequate supervision and monitoring ofoperations and personnel and deficiencies in well management documentation and systems. During operations tostop the leak, PTTEP AA’s wellhead platform and the contractor-operated West Atlas drilling rig caught fire,causing substantial damage to both the wellhead platform and the West Atlas rig. This affected the production startup. In order to maintain control of the well and fix the damaged production facilities, PTTEP AA temporarilysuspended the Montara H1 well. The West Atlas rig has been removed from the Montara field. PTTEP AA hascontracted to remove and replace the damaged topside of the wellhead platform. See “Business — PrincipalProperties — Principal Properties Under Production — Overseas.”

In the third quarter of 2009, PTTEP recorded expenses, after the oil and gas leak but prior to the fire incident,of Baht 5,174 million in connection with the incident. In the fourth quarter of 2009, PTTEP estimated an additionalBaht 5,253 million in expenses to cover the long-term monitoring and the expenses relating to the fire. The writeoff in the fourth quarter of 2009 includes a write off of Baht 3,325 million in connection with the damagedwellhead platform. As this incident was covered by insurance, PTTEP’s insurers have made interim paymentsunder PTTEP’s insurance policies of Baht 1,341 million, which PTTEP recorded in the fourth quarter of 2009 andBaht 1,369 million, which PTTEP recorded in the third quarter of 2010 and which partially offset the total incidentexpenditures. PTTEP AA is continuing the claims process with the insurers and loss adjustor.

As of December 31, 2010, PTTEP preliminarily estimated the maximum amount to be recovered under theinsurance policies to be approximately Baht 6,700 million (U.S.$222 million). Of which, Baht 1,341 million wasrecognized in the fourth quarter of 2009 and Baht 1,369 million was recognized in the third quarter of 2010.However, the actual amount ultimately recoverable under the insurance policies is dependent upon costs actuallyincurred and the terms and conditions of the policies. PTTEP is now in the claims process with its insurers todetermine the remaining recoverable amounts. Further, PTTEP and PTTEP AA are subject to a number ofregulatory investigations and potential third-party claims for damages in connection with the Montara Incident,such as a claim of U.S.$2.5 billion by the Government of Indonesia. See “Risk Factors — Risks Relating toPTTEP’s Business — PTTEP and PTTEP AA are subject to claims and liabilities in relation to the MontaraIncident” and “— PTTEP AA and PTTEP may face material adverse consequences as a result of ongoing andfuture investigations into the Montara Incident conducted by various Australian governmental agencies.” “—Capital Commitments and Contingent Liabilities — Contingent Liabilities.” The full extent of PTTEP AA’spotential liability in connection with these matters is unknown at this time.

Adoption of New Accounting Standards

Commencing on January 1, 2011, PTTEP adopted the amendments to Thai Accounting Standards, new ThaiAccounting Standards, new Thai Financial Reporting Standards and new Thai Financial Reporting Interpretations,as mandated by the Stock Exchange of Thailand and the Federation of Accounting Professions. These Thaistandards, which were published in the Government Gazette, are substantially the same as IFRS. In addition,PTTEP applied International Accounting Standards (IAS) 32 “Financial Instruments: Presentation,” IAS 39“Financial Instruments: Recognition and Measurement” and International Reporting Standard (IFRS) 7 “FinancialInstruments: Disclosures.” The audited consolidated financials statements included in this Offering Memorandum

42

were prepared in accordance with Thai GAAP and were not restated according to IFRS. PTTEP’s managementhas determined that, there will not be any significant impact of the amendments to accounting standards exceptas disclosed in Note 4 on page F-14 of the Financial Statements. See “PTTEP may incur significant costs inpreparing for and complying with IFRS and may not be able to fully comply with such standards.”

Critical Accounting Estimates and Judgments

PTTEP management continually evaluates the estimates and judgments used in preparing the financialstatements which are based on the management’s historical experience and other factors, including theexpectations of future events that are believed to be reasonable under the circumstances. PTTEP’s managementmakes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition,seldom equal the related actual results. The estimates and assumptions that have a significant effect on the carryingamounts of assets and liabilities are discussed below.

Estimate for Oil and Gas Reserves

Oil and gas reserves are key elements in PTTEP’s investment decision-making process, which is focused ongenerating value and are also important elements in testing for impairment. Changes in proved oil and gas reserveswill also affect the present value of the net cash flows and the unit-of-production depreciation.

Proved reserves are the estimated quantities of petroleum that geological and engineering data demonstratewith reasonable certainty to be recoverable in future years from known reservoirs under existing economic andoperating conditions, including government’s rules and regulations. The proved reserves have to be examined andassessed annually by PTTEP’s geologists and reservoir engineers. Changes in reserve estimates are recognizedprospectively. The proved reserve data set out in this Offering Memorandum represents estimates of a highconfidence, which according to the SPE Petroleum Resources Management System, means at least a 90% chancethat quantities actually recovered will equal or exceed the estimates.

Exploration Costs

Capitalized exploration drilling costs that are more than 12 months old are expensed, unless (i) provedreserves are booked or (ii) PTTEP has found commercially producible quantities of reserves, which are subject tofurther exploration or appraisal activity. In making decisions about whether to continue capitalizing explorationdrilling costs for a period of longer than 12 months, it is necessary to make judgments about the satisfaction ofeach condition during the current period. If there is a change in one of these judgments in a subsequent period,the related capitalized exploration drilling costs would be expensed in that period. If exploratory wells have notidentified proved reserves or have identified proved reserves but have not found them to be commerciallyproducible, such drilling costs are expensed in the income statement. For abandoned wells, PTTEP recognizesprovision for decommissioning costs, which is provided at the onset of completion of the project for the estimatedeventual costs of removing the production facilities.

Impairment of Assets

The value in use of assets under consideration for impairment is assessed by estimating discounted futurecash flows. Expected future cash flows is based on management’s estimates in relation to the asset’s future sellingprice, demand and supply in the market, margin rate and estimated future production volume.

Expected future production volumes, which include both proved reserves as well as volumes that areexpected to constitute proved reserves in the future, are used for impairment testing because management believesthis is the most appropriate indicator of expected future cash flows, used as a measure of value in use. Thediscounted rate for the impairment testing reflects the current market assessment of the time value of money andthe risk specific to the assets for which the future cash flow estimates have not been adjusted.

43

Goodwill and Intangible Assets

For the recognition and measurement of goodwill and intangible assets as of their acquisition date, includingsubsequent impairment testing, management uses estimated future cash flow from assets or cash generating unitsand the appropriate discount rate to calculate the present value of future cash flow.

Income Tax

PTTEP is subject to income taxes in numerous jurisdictions. Significant judgments are required to determinethe worldwide provision for income taxes, due to the fact that there are many transactions and calculations forwhich the ultimate tax determination is uncertain during the ordinary course of business. PTTEP recognizesliabilities for anticipated tax based on estimates of whether additional taxes will be due. Where the final taxoutcome of these matters is different from the amounts that were initially recorded, such differences will affectthe income tax and deferred tax provisions in the period in which such determination is made.

Deferred tax assets are recognized to the extent that it is probable that future taxable profits will be availableagainst which the temporary differences can be utilized. The management is required to make an estimate of thenumber of deferred income tax assets that should be recognized by considering the assumptions about the probablefuture tax benefits in each period. There may be uncertainty associated with the assumptions used for the futuretaxable income in terms of whether any charge will affect the recognition of the deferred tax asset.

Lease

In considering whether a lease agreement is an operating lease or a finance lease, management exercisesjudgment in assessing terms and conditions of the agreement to determine whether the risks and rewards of assetsare transferred to PTTEP or not.

Employee Retirement Plans

PTTEP’s obligation regarding retirement benefit plans is calculated by estimating the amount of futurebenefits that employees will have earned in return for their services to the Company and subsidiaries in the currentand in future periods. The calculation is performed by an independent actuary using the Projected Unit CreditMethod and the relevant assumptions, which include financial and demographic assumptions, as set out in Note25 to the Audited Financial Statements appearing beginning on page F-41.

When benefits under the plans are changed, the portion of the increased benefits relating to the past serviceof employees is recognized in the income statement on a straight-line basis over the average remaining period untilthe benefits become vested. The expense is recognized immediately in the income statement when the benefits arepaid.

Provisions

Provisions are recognized by PTTEP and presented in the balance sheet when there is an obligation as aresult of a past event and there is the possibility that PTTEP will have to pay its beneficial assets for such anobligation when the amount can be reliably calculated.

PTTEP records a provision for decommissioning costs whenever it is probable that there would be anobligation of a reliable amount as a result of a past event. PTTEP recognizes a provision for decommissioningcosts, which is provided at the onset of completion of the project, for the estimate of the eventual costs that relateto the removal of the production facilities. These costs are included as part of the oil and gas properties andamortized based on proved reserves on a unit of production basis. The estimates of decommissioning costs aredetermined based on reviews and estimates by engineers and managerial judgment.

The provisions are based on current regulations, technologies and prices. The actual results could differ fromthese estimates as future events occur.

Principal Income Statement Components

Sales

PTTEP’s sales comprise sales of natural gas, crude oil, condensate and LPG.

44

Revenue from Pipeline Transportation

Revenue from pipeline transmission comprises revenue received from Moattama Gas TransportationCompany and Taninthayi Pipeline Company LLC, of which PTTEP indirectly owns 25.5% and 19.3%,respectively.

Other Revenues

Other revenues mainly comprise gain on foreign exchange, interest income from fixed deposits, investmentin treasury bills and loans to associated companies, income from gas pipeline construction service, gain onsettlement of derivative financial instruments, rental revenues in connection with office rent to PTT, revenues fromthe disposal of assets and compensation received from insurers in relation to the Montara Incident.

Operating Expenses

Operating expense comprises expenses incurred to operate and maintain an enterprise’s wells and relatedequipment and facilities. For PTTEP, operating expenses include pre-operating expense, lifting cost (productioncost), production transportation expense, stock variation (product) and asset/material write-offs.

Exploration Expenses

Exploration expense is expense incurred in exploring property. Exploration involves identifying areas thatmay warrant examination and examining specific areas, including drilling exploratory wells. There are twocategories of exploration expense, exploration geology and geophysics cost (“G&G Cost”) and exploration drillingcost. The exploration expenses also include dry-hole write-off costs. PTTEP uses the successful efforts accountingmethod to allocate expenses. G&G Cost is recorded as an expense in the Income Statement. Exploration drillingcost is initially recorded in a work in progress account, and then later transferred to a completed asset or writtenoff depending on whether commercially viable proved reserves are found.

Administrative Expenses

Administrative costs include office costs at the head office and for PTTEP’s various international operations.

Petroleum Royalties and Remuneration

Petroleum royalties and remuneration comprise royalties paid to the Government.

Other Expenses

Other expenses include losses on foreign exchange, hedging losses, management’s remuneration, lossesfrom the Montara Incident and expenses related to the purchase of the FPSO.

Results of Operations

2010 Compared to 2009

Sales. PTTEP’s sales in 2010 were Baht 138,474 million (U.S.$4,571 million) compared to Baht 115,547million in 2009, an increase of Baht 22,927 million, or 19.8%. This increase was primarily attributable to thehigher sales volume and higher average petroleum sales prices in 2010 of U.S.$44.83 per Boe compared toU.S.$39.53 per Boe in 2009. PTTEP’s sales volume increased to 264,575 Boe/d in 2010 from 233,756 Boe/d in2009, due primarily to the increase in natural gas and condensate sales volume from the Arthit North, whichexperienced its first full year of production, MTJDA-B17, which commenced commercial production in February2010, and Bongkot projects, where gas sales volume increased to 586 MMSCFD in 2010 from 516 MMSCFD in2009 and condensate sales volume increased to 19,779 Boe/d in 2010 from 18,217 Boe/d in 2009. However,natural gas and condensate sales volume from the Arthit project decreased. The weighted average price at whichPTTEP sold its natural gas increased to U.S.$5.52 per MMBtu in 2010 from U.S.$5.17 per MMBtu in 2009, a6.8% increase, primarily due to the increase in average oil prices which affect the weighted average natural gasprice. The weighted average price at which PTTEP sold its crude oil increased to U.S.$74.24 per Bbl in 2010 fromU.S.$58.84 per Bbl in 2009, an increase of 26.2%.

Revenue from pipeline transportation. PTTEP’s revenue from pipeline transportation in 2010 was Baht3,504 million (U.S.$116 million) compared to Baht 3,763 million in 2009, a decrease of Baht 259 million, or 6.9%.

45

This decrease resulted primarily from lower prices for gas from Yadana and Yetagun in 2010 compared to 2009,which resulted in a proportionate decrease in tariffs charged by PTTEP’s gas transportation affiliates MoattamaGas Transportation Company and Taninthayi Pipeline Company.

Other revenues. PTTEP’s other revenues in 2010 were Baht 5,594 million (U.S.$184 million) compared toBaht 1,028 million in 2009, an increase of Baht 4,566 million, or 444.2%. This increase was primarily due tocompensation received from insurers in relation to the Montara incident and from disposal of assets amounting toBaht 1,369 million and Baht 534 million, respectively. Additionally, there was a gain on foreign exchange in 2010from the Baht’s depreciation against the U.S. dollar, compared to 2009 when PTTEP experienced foreignexchange losses.

Operating expenses. PTTEP’s operating expenses in 2010 were Baht 14,588 million (U.S.$482 million)compared to Baht 11,926 million in 2009, an increase of Baht 2,662 million, or 22.3%. This increase was primarilyattributable to increased production activities, mainly from the Arthit North and MTJDA-B17 projects.

Exploration expenses. PTTEP’s exploration expenses in 2010 were Baht 2,752 million (U.S.$91 million)compared to Baht 7,377 million in 2009, a decrease of Baht 4,625 million, or 62.7%. The decrease was primarilyattributable to lower exploratory well write-offs in 2010 were Baht 1,472 million compared to Baht 5,671 millionin 2009. In 2010, the write-offs were mainly from the Myanmar Zawtika project. In 2009, there were well write-offcosts from the Iran Saveh, Australia AC/P36, and PTTEP AA projects, amounting to Baht 1,597 million, Baht1,247 million and Baht 917 million, respectively. PTTEP has discontinued all operations in Iran and currently hasno intention of engaging in operations in Iran.

Administrative expenses. PTTEP’s administrative expenses in 2010 were Baht 5,972 million (U.S.$197million) compared to Baht 5,062 million in 2009, an increase of Baht 910 million, or 18.0%, mainly due to officerental and staff costs.

Petroleum royalties and remuneration. PTTEP’s petroleum royalties and remuneration in 2010 were Baht16,773 million (U.S.$554 million) compared to Baht 14,066 million in 2009, an increase of Baht 2,707 millionor 19.2%. Petroleum royalties and special remuneration benefits per barrel of oil equivalent produced increased14.0% from U.S.$4.80 per Boe in 2009 to U.S.$5.47 per Boe in 2010. Royalties and remuneration are linked torevenue levels. Thus, this increase is primarily due to an increase in revenues.

Depreciation, depletion and amortization. PTTEP’s depreciation, depletion and amortization in 2010 wasBaht 36,825 million (U.S.$1,215 million) compared to Baht 29,856 million in 2009, an increase of Baht 6,969million, or 23.3%. The increase was primarily attributable to increased depreciation caused by increasedproduction at MTJDA-B17 in 2010 and a full year of production at Arthit North, which commenced commericalproduction in May 2009. Moreover, depreciation and amortization expenses increased because PTTEP AArecognized additional decommissioning costs for the Jabiru and Challis fields, which were shut down inSeptember 2010.

Other expenses. PTTEP’s other expenses in 2010 were Baht 2,127 million (U.S.$70 million) compared toBaht 9,750 million in 2009, a decrease of Baht 7,623 million, or 78.2%. This decrease was mainly due to the factthat in 2010 PTTEP experienced lower losses due to the Montara Incident in 2010 compared to 2009. Otherexpenses in 2010 also included environmental impact management in relation to the Montara Incident.Additionally, there was no loss on foreign exchange in 2010, compared to 2009, when such losses did exist.

Income before finance costs and income taxes. PTTEP’s income before finance costs and income taxes in2010 was Baht 68,490 million (U.S.$2,261 million) compared to Baht 42,283 million in 2009, an increase of Baht26,207 million, or 62.0%.

Finance costs. PTTEP’s finance costs in 2010 were Baht 2,540 million (U.S.$84 million) compared to Baht1,870 million in 2009, an increase of Baht 670 million, or 35.8%. This increase was primarily attributable tointerest on PTTEP’s May 2009 Baht issuance of Baht 40,000 million, with interest rates ranging from 3.0% to4.8%, as well as PTTEP Australia International Finance Pty Ltd.’s international bond issuance in July 2010 ofU.S.$500 million and a domestic bond issuance in August 2010 of U.S.$200 million, each with an interest rate of4.152% per annum and a term of five years.

Income taxes. PTTEP’s income taxes in 2010 were Baht 24,211 million (U.S.$799 million), or 35.3% of itsincome before finance costs and income taxes, compared to Baht 18,259 million in 2009, or 43.2% of its incomebefore finance costs and income taxes.

46

Net income. As a result of the foregoing, PTTEP’s net income in 2010 was Baht 41,739 million (U.S.$1,378million) compared to Baht 22,154 million in 2009, an increase of Baht 19,585 million, or 88.4%.

2009 Compared to 2008

Sales. PTTEP’s sales in 2009 were Baht 115,547 million compared to Baht 132,621 million in 2008, adecrease of Baht 17,074 million, or 12.9% from 2008. This decrease was primarily attributable to a lower averagepetroleum sales price in 2009 of U.S.$39.53 per Boe compared to U.S.$49.69 per Boe in 2008, partially offset bya weakened Baht relative to the U.S. dollar. The weighted average price at which PTTEP sold its natural gasremained unchanged at U.S.$5.17 per MMBtu in 2009 compared to 2008. The weighted average price at whichPTTEP sold its crude oil decreased to U.S.$58.84 per Bbl in 2009 from U.S.$90.08 per Bbl in 2008, a decreaseof 34.7%. Despite the weakened economic environment in 2009, PTTEP’s sales volume increased to 233,756Boe/d in 2009 from 219,314 Boe/d in 2008, due primarily to increased production of natural gas and condensatefrom the Arthit project and natural gas and crude oil from the Vietnam 9-2 project, which began production in2008, as well as sales from projects which began production in 2009, including natural gas from the Arthit Northproject and crude oil from the PTTEP Australasia project.

Revenue from pipeline transportation. PTTEP’s revenue from pipeline transportation in 2009 was Baht3,763 million compared to Baht 4,131 million in 2008, a decrease of Baht 368 million, or 8.9%. This decreaseresulted from lower prices for gas from Yadana and Yetagun in 2009, which resulted in lower transmission tariffs.

Other revenues. PTTEP’s other revenues in 2009 were Baht 1,028 million compared to Baht 3,255 millionin 2008, a decrease of Baht 2,227 million, or 68.4%. This decrease was primarily due to the fact that in 2008,PTTEP received Baht 1,947 million from PTT for PTTEP’s construction of the gas pipeline for the Arthit project,which was completed in 2008.

Operating expenses. PTTEP’s operating expenses in 2009 were Baht 11,926 million compared to Baht10,529 million in 2008, an increase of Baht 1,397 million, or 13.3%. This increase was primarily attributable tothe increased operating expenses and well repair and maintenance costs associated with the PTTEP Australasiaproject, as well as the operating expenses of the Arthit and Arthit North projects as a result of increased productionactivities, including the costs of leasing the FPSO facilities in connection with Arthit North.

Exploration expenses. PTTEP’s exploration expenses in 2009 were Baht 7,377 million compared to Baht8,273 million in 2008, a decrease of Baht 896 million, or 10.8%. The decrease was primarily attributable to thefact that the write-off costs associated with dry wells in 2008 from the Myanmar M3, M4, M7 and M11 MyanmarZawtika, Vietnam 16-1 and Algeria 433a & 416b projects were higher compared to the write-off costs associatedwith dry wells in 2009 from the Iran Saveh, Australia AC/P36, PTTEP Australasia and Oman 44 projects.

Administrative expenses. PTTEP’s administrative expenses in 2009 were Baht 5,062 million compared toBaht 4,497 million in 2008, an increase of Baht 565 million, or 12.6%. The increase was primarily attributableto compensation charges associated with the gas pipeline constructed for the Yetagun project as well as an increasein administrative expenses in connection with the addition of PTTEP Australasia.

Petroleum royalties and remuneration. PTTEP’s petroleum royalties and remuneration in 2009 were Baht14,066 million compared to Baht 17,328 million in 2008, a decrease of Baht 3,262 million or 18.8%, reflectinga decrease in sales revenues.

Depreciation, depletion and amortization. PTTEP’s depreciation, depletion and amortization in 2009 wasBaht 29,856 million compared to Baht 23,286 million in 2008, an increase of Baht 6,570 million, or 28.2%. Theincrease was primarily attributable to an increase in additional completed oil and gas properties from the Arthitproject, as well as increased depreciation of the Arthit North, PTTEP Australasia and Vietnam 9-2 projects as aresult of increased production volumes.

Other expenses. PTTEP’s other expenses in 2009 were Baht 9,750 million compared to Baht 1,064 millionin 2008, an increase of Baht 8,686 million, or 816.4%. This increase was almost entirely due to the Baht 9,086million of expenses relating to the Montara Incident. See “— Factors Affecting Results of Operations — TheMontara Incident.”

Income before finance costs and income taxes. PTTEP’s income before finance costs and income taxes in2009 were Baht 42,283 million compared to Baht 75,018 million in 2008, a decrease of Baht 32,735 million, or43.6%.

47

Finance costs. PTTEP’s finance costs in 2009 were Baht 1,870 million compared to Baht 841 million in2008, an increase of Baht 1,029 million, or 122.4%. This increase was primarily attributable to interest onPTTEP’s Baht bond issuance in May 2009 of Baht 40,000 million in four tranches with interest rates ranging from3.0% to 4.8%.

Income taxes. PTTEP’s income taxes in 2009 were Baht 18,259 million, or 43.2% of its income beforefinance costs and income taxes, compared to Baht 32,502 million in 2008, or 43.3% of its income before financecosts and income taxes.

Net income. As a result of the foregoing, PTTEP’s net income in 2009 was Baht 22,154 million comparedto Baht 41,675 million in 2008, a decrease of Baht 19,521 million, or 46.8%.

Liquidity and Capital Resources

PTTEP’s sources of funding include funds generated from operations, funds from external borrowings, andthe proceeds from offerings of its ordinary shares and Baht and U.S. dollar denominated bonds. PTTEP plans tofund the capital and related expenditures described in this Offering Memorandum through cash provided byoperating activities, and short-term debt and long-term debt. Net cash provided by operating activities during theyear ended December 31, 2010 was Baht 81,732 million. As of December 31, 2010, PTTEP had cash and cashequivalents of Baht 59,515 million.

The following table sets forth a summary of PTTEP’s statements of cash flows for the periods indicated.

For the Year Ended December 31,

2008 2009 2010 2010

Bt Bt Bt U.S.$(3)

(in millions)

Cash flows from operating activities:Net income from operating activities before

changes in operating assets and liabilities(1) 104,022 83,669 101,584 3,353Changes in operating assets and liabilities........ (21,757) (40,783) (19,852) (656)Net cash provided by operating activities ......... 82,265 42,886 81,732 2,697Cash flows from investing activities:Loans to related parties...................................... (1,235) 1,330 (86) (3)Deposit for the purchase of partnership units ... — — (10,312) (340)Investments in related parties ............................ — (556) — —Interest received from loans............................... 82 45 19 1Increase in property, plant and equipment ........ (48,984) (59,389) (64,755) (2,137)Increase in intangible assets............................... (140) (3,633) (41) (2)Net cash used in investing activities ................. 50,277 62,203 75,175 2,481Cash flows from financing activities:(Decrease)/increase in short-term loans............. 2,906 (1,361) 6,000 198Redemption of bonds ......................................... — — (9,500) (314)Proceeds from issuances of bonds(2) ................ — 39,950 22,193 733Interest paid ........................................................ (751) (1,439) (1,996) (66)Proceeds from common stock............................ 574 367 403 13Dividend paid ..................................................... (14,964) (13,366) (12,433) (410)Net cash (used in) provided by financing

activities.......................................................... (12,235) 24,151 4,667 154Net increase in cash and cash equivalents ........ 19,753 4,834 11,224 370Cash and cash equivalents at beginning of

the period....................................................... 24,013 43,995 48,678 1,607Effects of exchange differences ......................... 229 (151) (387) (13)Cash and cash equivalents at period end...... 43,995 48,678 59,515 1,964

(1) Includes adjustments to reconcile net income to net cash provided by/(used in) operating activities.(2) Net of bond issuance expense.(3) The U.S. dollar translations are provided for indicative purposes only and are unaudited. These translations were calculated based on

an exchange rate as of December 30, 2010: Baht/U.S.$ = Baht 30.296 to U.S.$1.00.

48

Cash Flows from Operating Activities

PTTEP’s operations generated cash flows of Baht 82,265 million, Baht 42,886 million and Baht 81,732million in 2008, 2009 and 2010, respectively.

Net cash from operations in 2010 resulted primarily from income before income taxes of Baht 65,950million, depreciation, depletion and amortization expenses of Baht 36,825 million associated with the producingassets of the Arthit, Bongkot, Contract 4 and S1 projects, amortization of exploration expenses of Baht 1,472million associated with write-off costs relating to the Myanmar Zawtika and Sidi Abd El Rahman Offshoreprojects and interest income (from deposit and loan to related parties) less interest expenses (from bonds and billsof exchange) of Baht 1,962 million. These items were partially offset by various items, principally a gain onforeign exchange.

Net cash from operations in 2009 resulted primarily from income before income taxes of Baht 40,413million, depreciation, depletion and amortization expenses of Baht 29,856 million associated with the producingassets of the Arthit, B8/32, Contract 4, and Bongkot projects, amortization of exploration expenses of Baht 5,671million associated with write-off costs relating to the Iran, Australia ACP36 and Oman 44 projects, loss on disposalof assets of Baht 3,499 million associated with the damaged topside wellhead platform of the Montara H1 project,and other losses from the Montara Incident of Baht 3,106 million.

Net cash from operations in 2008 resulted primarily from income before income taxes of Baht 74,177million, depreciation, depletion and amortization expenses of Baht 23,286 million associated with the producingassets of the Arthit, B8/32, Contract 4, and Bongkot projects and the amortization of exploration expenses of Baht6,307 million associated with the wells written off in the Vietnam 16-1 and Myanmar M3, M4, M7 and M11projects.

Cash Flows from Investing Activities

In 2010, PTTEP had net cash flows used in investing activities of Baht 75,175 million, primarily reflectinginvestment in oil and gas properties for exploration and production from the Arthit, Bongkot and PTTEPAustralasia projects and the deposit payment for the interest in SCP.

In 2009, PTTEP had net cash flows used in investing activities of Baht 62,203 million, primarily reflectingthe investment in oil and gas properties for exploration and production and intangible assets from PTTEPAustralasia.

In 2008, PTTEP had net cash flows used in investing activities of Baht 50,277 million, mainly resultingfrom: (i) the investment in oil and gas properties for production from the MTJDA-B17, Arthit, Contract 4, Bongkotand B8/32 & 9A projects and (ii) a long term loan to Energy Complex Co., Ltd. amounting to Baht 1,235 million.

Cash Flows from Financing Activities

In 2010, PTTEP had net cash provided by financing activities of Baht 4,667 million, mainly due to theproceeds from (i) the issuance of debentures amounting to Baht 22,193 million, (ii) the issuance of bills ofexchange amounting to Baht 6,000 million; and (iii) the issuance of common stock under the ESOP of Baht 403million. Those items were partially offset by (i) dividend payments to shareholders in the second half of 2009 ofBaht 1.20 per share and for the first half of 2010 of Baht 2.55 per share, totaling Baht 12,433 million; (ii) therepayment of debentures of Baht 9,500 million; and (iii) interest paid on indebtedness in the amount of Baht 1,996million.

In 2009, PTTEP had net cash provided by financing activities of Baht 24,151 million, primarily reflecting:cash proceeds received from the issuance of Baht debentures in the amount of Baht 39,950 million and cashreceived from the issuance of common stock under the ESOP of Baht 367 million. Those items were partiallyoffset by (i) net cash paid for short-term loans of Baht 1,361 million in connection with PTTEP’s ongoing issuanceof bills of exchange; (ii) dividend payments to shareholders in the second half of 2008 at Baht 2.56 per share andfor the first half of 2009 at Baht 1.48 per share, totaling Baht 13,366 million; and (iii) interest paid on indebtednessin the amount of Baht 1,439 million.

49

In 2008, PTTEP had net cash used in financing activities of Baht 12,235 million, primarily reflecting: (i) adividend payment to shareholders for the second half of 2007 of Baht 1.67 per share and a dividend payment toshareholders for the first half of 2008 of Baht 2.86 per share, totaling Baht 14,964 million; (ii) interest paid onindebtedness of Baht 751 million; (iii) net cash received in connection with PTTEP’s ongoing issuance of bills ofexchange in the amount of Baht 2,906 million; and (iv) cash received from the issuance of ordinary shares on theexercise of warrants of Baht 574 million.

Capital Commitments and Contingent Liabilities

PTTEP’s total consolidated short-term loans and bonds as at December 31, 2008, 2009 and 2010 comprised:

As at December 31,

2008 2009 2010

Bt Bt Bt

(in millions)

Current LiabilitiesShort-term loans

— Bills of exchange................................................................. 2,986 999 7,945— Other loans .......................................................................... — 936 —

Total short-term loans............................................................... 2,986 1,935 7,945

Current portion of bondsCurrent portion of bonds .......................................................... — 9,500 —Less: Deferred issuance expense of bonds .............................. — (1) —

Current portion of bonds — net .............................................. — 9,499 —

Total current liabilities.................................................... 2,986 11,434 7,945

Non-current LiabilitiesBonds ........................................................................................ 18,500 49,000 70,106Less: Deferred issuance expense of bonds .............................. (12) (49) (213)

Total non-current liabilities ............................................ 18,488 48,951 69,893

Bills of Exchange

PTTEP maintains a short-term financing program which involves the monthly issuance of Bills of Exchange(B/Es) via public offerings to institutional and high net-worth investors in Thailand. B/Es are to be issued monthlyon a revolving basis in an amount not to exceed Baht 50,000 million outstanding at any time, which was approvedby the Board of Directors’ in February 2009 and November 2010. As of December 31, 2010, the total amount ofB/Es outstanding had a face value of Baht 8,010 million, with the weighted average discount rate of 2.31%.

Other Borrowings

Other borrowings comprise secured loans valued in U.S. dollars with a floating interest rate of LIBOR U.S.dollar 1 month +2.00% per annum. As of December 31, 2010, PTTEP had no trade credits outstanding.

Bonds

In 2010, PTTEP guaranteed U.S.$700 million of five-year bonds issued by its subsidiary, PTTEP AustraliaInternational Finance Pty Ltd. The issuance included a U.S.$500 million international bond offering and aU.S.$200 million domestic bond offering. Both tranches have an interest rate of 4.152% per annum. Proceeds fromthese issuances were onlent to one or more subsidiaries of PTTEP through the Intercompany Loan for generalpurposes, including, but not limited to, funding exploration, development and production activities.

50

The carrying value of PTTEP’s unsecured and unsubordinated bonds as of December 31, 2010 was asfollows:

As of December 31, 2010

Bt (in millions)

Principal at MaturityWithin 1 year ............................................................................................................. —2012............................................................................................................................ 21,8002013............................................................................................................................ 5,0002014............................................................................................................................ 11,7002015............................................................................................................................ 21,1062016............................................................................................................................ —Beyond 2017.............................................................................................................. 10,500

Total par value of bonds ......................................................................................... 70,106Less: Deferred issuance expense of bonds ............................................................... (213)

Total carrying value................................................................................................... 69,893

Finance Lease Liabilities

Finance lease liabilities are liabilities from using the FPSO for PTTEP AA. PTTEP recorded the capitalexpenditure at the lower of the fair value of the leased property or the present value of the minimum leasepayments and recorded the liabilities at the lease obligation value, net of finance charges. The costs of the financelease are approximately U.S.$425.3 million. PTTEP will begin making payments under the lease when the FPSOis completed and ready for its intended use for petroleum production at the Montara project and will continuemaking payments for five years thereafter. The interest rate implicit in the lease is 10.56% per annum. PTTEPrecognizes the assets from finance leases as “Oil and Gas Properties” under the caption “Property, Plant andEquipment” in the balance sheet.

In 2010, PTTEP agreed to purchase the FPSO vessel that it had been leasing for Baht 13,535 million toreduce interest expenses for future periods. This resulted in the termination of the finance lease arrangement. Thepurchase price of the FPSO vessel was higher than its carrying value at the agreed purchase date. The differenceof Baht 1,485 million was recognized as other expenses in relation to the contract. The purchase price of FPSOvessel was fully settled in October 2010.

Finance lease liabilities as at December 31, 2009 and 2010 comprised:

As at December 31,

2009 2010

Bt Bt

(in millions)

Minimum future payment for finance leases— Maturity date within 1 year ................................................................ 1,212 —— Maturity date between 1-5 years ......................................................... 13,330 —

Less: Future finance cost of finance leases .................................................. (3,156) —

Present Value of finance leases..................................................................... 11,386 —

Finance Lease liabilities— Current portion ..................................................................................... 829 —— Long-term portion ................................................................................ 10,557 —

11,386 —

51

Operating Leases

As of December 31, 2010, PTTEP’s future minimum lease payments for non-cancellable operating leaseswere as follows:

As of December 31, 2010

Bt

(in millions)

Within 1 year ............................................................................................................. 3,985Between 1-5 years ..................................................................................................... 4,106Over 5 years .............................................................................................................. 2,829

Total ........................................................................................................................... 10,920

These operating leases relate to the FPSO facilities at the Arthit North project and floating storage andoffloading facilities at MTJDA.

Loan Agreements

As of December 31, 2010, PTTEP had a subordinated loan agreement with Energy Complex CompanyLimited (EnCo) with a loan limit of Baht 1,250 million. The term of the agreement is 13 years and six months,effective from April 2, 2009. As of December 31, 2010, the total amount of loans provided by PTTEP outstandingunder this agreement was Baht 580 million.

On November 24, 2010, PTTEP Offshore Investment Company Limited (“PTTEPO”) entered into aU.S.$500 million unsecured, unsubordinated loan agreement, fully guaranteed by PTTEP, with the Bank ofTokyo-Mitsubishi UFJ, Ltd., Mizuho Corporate Bank, Ltd., Oversea-Chinese Banking Corporation Limited andSumitomo Mitsui Banking Corporation. On December 1, 2010, PTTEPO entered into a U.S.$75 millionunsecured, unsubordinated loan agreement, fully guaranteed by PTTEP, with Mizuho Corporate Bank, Ltd. OnDecember 9, 2010, PTTEP entered into a U.S.$50 million unsecured, unsubordinated loan agreement withThanachart Bank Public Company Limited. On January 14, 2011, PTTEP and PTTEPO drew down the entire loanamount of these three loans, U.S.$625 million which amount was used for partial payment of PTTEP’s 40%interest in SCP. Each of these loan facilities is repayable in 2015 and none are subject to financial covenants.

On March 11, 2011, PTTEP entered into a Baht 20,000 million unsecured, unsubordinated loan agreementwith Krung Thai Bank Public Company Limited. The loan is not subject to any financial covenants and isrepayable within one year of the first drawdown. PTTEP plans to draw down Baht 5,000 million on March 31,2011 and expects to draw down the remaining Baht 15,000 million by the end of May 2011.

Obligation under Gas Sales Agreement

According to the GSA for the MTJDA-B17 project, if the PTTEPI and its joint venture partner fail to deliverthe quantity of natural gas nominated by PTT on the agreed upon date, PTT has the right to take the deficientquantity of natural gas (the “Shortfall”) at a price equal to 75% of the price applicable at the time the Shortfalloccurred. PTT began to nominate quantities of natural gas in late December 2009, but PTTEPI and its joint venturepartner could not deliver natural gas quantity nominated by PTT because commercial production commenced onFebruary 5, 2010. Thus, PTTEPI and its joint venture partner may have an obligation to provide the Shortfall gasamount that was incurred from late December 2009 to February 5, 2010 at the 75% discounted price as per theGSA. The approximate total cost to PTTEPI would be Baht 108 million. Negotiations with PTT are currentlyongoing.

Debt Structure

As of December 31, 2010, PTTEP’s total interest bearing debt amounted to Baht 77,838 million. PTTEP’sU.S. dollar denominated debt comprised 27% of its total interesting bearing debt and Thai Baht denominated debtcomprised 73% of its total interest bearing debt. Fixed rate debt comprised 90% of PTTEP’s total interest bearingdebt and floating rate debt comprised 10% of PTTEP’s total interest bearing debt. PTTEP’s weighted average costof debt was 3.70% and its average loan life was 3.5 years.

52

Contingent Liabilities

In July 2010, PTTEP guaranteed U.S.$700 million of five-year bonds issued by its subsidiary, PTTEPAustralia International Finance Pty Ltd. The issuance included a U.S.$500 million international bond offering anda U.S.$200 million domestic bond offering. Both tranches have an interest rate of 4.152% per annum. Proceedsfrom these issuances were onlent to one or more subsidiaries of PTTEP through the Intercompany Loan for generalcorporate purposes, including, but not limited to, funding exploration, development and production activities.

On August 26, 2010, PTTEP AA received a letter from the Government of Indonesia claiming U.S.$2.5billion in compensation related to the Montara Incident. Further details of the claim and supporting documentationwere received in October 2010. PTTEP AA has not accepted the claim as PTTEP AA believes that it is notsupported by scientifically valid evidence. PTTEP AA continues to actively engage the Government of Indonesia,but has not accepted any legal liability to pay compensation to the Government of Indonesia. In December 2010,PTTEP AA and the Government of Indonesia agreed to provide each other with additional documents and toconduct a joint survey to verify the Government of Indonesia’s data on the claimed damage to its fishing industry.PTTEP AA and the Government of Indonesia met again for discussions in February 2011. As of the date of thisOffering Memorandum, no conclusion has been reached regarding any claims for compensation.

As of December 31, 2010, PTTEP had contingent liabilities in the form of letters of guarantee amountingto Baht 3,141 million. These letters of guarantee relate to the performance bond payment guarantees and bid bondsin connection with PTTEP’s exploration and production activities and PTTEP’s group-related business.Performance bonds are issued to guarantee the work commitment of awarded concessions and PSC to an oil andgas regulator or to an operator in a joint venture as required by the applicable laws, regulations and for the relatedjoint venture agreement. Outstanding payment guarantees are guarantees for tax returns as required by the taxauthority. Other outstanding guarantees are required in a withdrawal contract agreement.

Capital Expenditures

PTTEP’s capital expenditures on an accrual basis for 2008, 2009 and 2010 were Baht 64,469 million, Baht80,953 million and Baht 55,947 million, respectively. PTTEP’s capital expenditures in 2010 were primarily usedfor the Bongkot, Arthit and PTTEP AA projects.

PTTEP currently estimates that its overall capital expenditures for the three years ending December 31, 2013will be Baht 228,635 million (U.S.$7.5 billion), principally in respect of the exploration, expansion anddevelopment of the Myanmar Zawtika, Arthit, KKD and Bongkot projects. The following table sets forth PTTEP’splanned capital expenditure requirements for the periods indicated. Actual future capital expenditures may differfrom the amounts indicated below.

For the year ending December 31,

2011 2012 2013

Bt

(in millions)

Planned capital expenditure requirements ..................... 94,475 70,951 63,209

Operating Expenditures

PTTEP’s operating expenditures for 2008, 2009 and 2010 were Baht 17,694 million, Baht 26,044 millionand Baht 26,219 million, respectively. The following table sets forth PTTEP’s planned operating expenditurerequirements for the periods indicated. The exploration, development and production operations and the relatedcosts are subject to uncertainties, and the actual future operating expenditures may differ from the amountsindicated below. See, “Risk Factors — The development of PTTEP’s projects involves construction, financing,regulatory and operational risks that could lead to increased expenses and lost revenues.”

For the year ending December 31,

2011 2012 2013

Bt

(in millions)

Planned operating expenditure requirements................. 39,749 31,232 31,494

53

Inflation

According to the Bank of Thailand, Thailand’s annual overall inflation rates in 2008, 2009 and 2010, asmeasured by the general consumption price index, were 5.5%, -0.9% and 3.3%, respectively. Core inflationregistered year-on-year growth of 1.0% in 2010, which was less than the maximum target inflation rate set by theBank of Thailand of 3.00% in 2010. The target inflation rate based on a multi-year average of core inflation.

Primary Risks

Commodity Price Risk

PTTEP’s product prices vary with those of world oil prices, which are subject to factors beyond its control,such as market demand and supply, the political and economic stability of various countries in which PTTEPoperates, OPEC’s production policy, oil reserves and the change in the global climate in each season. Fluctuationsin world oil prices affect PTTEP’s revenue and investment planning.

Regarding the aforementioned factors, when the world oil prices change, so do the prices of PTTEP’s crudeoil and condensate. However, because of built-in natural gas pricing mechanisms found in the Gas SalesAgreement which cushion natural gas prices from oil price volatility, when the reference oil prices change, thetypical prices of natural gas change in the same direction. Most of PTTEP’s contractual natural gas prices areadjusted every six or 12 months depending on the gas price formula of each project and should this price rise orfall, the natural gas price will move correspondingly to a certain degree comparing to the prices of crude oil andcondensate.

In an effort to mitigate existing price risks, PTTEP uses options contracts, subject to approval by the Boardof Directors prior to execution. In 2010, the world oil price was volatile, for example, Dubai crude oil fluctuatedin the range of U.S.$70 to U.S.$90 per barrel. In 2011, oil prices have increased and as of February 28, 2011, theprice of Dubai crude oil has risen to U.S.$107.23 per barrel.

Foreign Exchange Rate Risk

Although the vast majority of PTTEP’s domestic and international revenues and expenses are tied to theU.S. dollar, its functional currency is the Baht. Therefore, foreign exchange risk arises when transactions aredenominated in a currency other than Baht. Foreign exchange gains and losses are presented in Note 28 to theAudited Financial Statements appearing on page F-43.

PTTEP’s asset and liability management policy aligns the structures and features of transactions regardingassets, liabilities and shareholders’ equity against each other. In addition, PTTEP employs forward foreignexchange contracts to manage foreign exchange risk.

On January 1, 2011, PTTEP adopted the U.S. dollar as its official reporting currency. While this will reducethe effect of exchange rates on sales denominated in U.S. dollars, PTTEP still has some costs denominated in Bahtand faces some currency exchange effects. Further, the preparation for the transition, as well as actual transition,is likely to result in significant costs for PTTEP and may have a material adverse effect on its results of operations.See, also “PTTEP may incur significant costs in preparing for and complying with IFRS and may not be able tofully comply with such standards.”

Interest Rate Risk

As of December 31, 2010, 90% of PTTEP’s debt is subject to fixed interest rates, resulting in stable cashoutflows. However, fixed interest rates would result in a higher interest expense if market interest rates decrease.To manage the risk from falling interest rates, PTTEP’s policy is to maintain a proper proportion betweenfixed-interest rate debt and floating-interest rate debt. PTTEP uses floating-interest rate borrowings as well asfinancial instruments, such as interest rate swap agreements, to swap from fixed interest rates to floating rates inorder to minimize interest rate risks. The Group considers costs, market conditions, and acceptable risks in usingthe financial instrument to prevent the risk.

Furthermore, PTTEP’s short-term commercial papers (Bills of Exchange), which have tenors of one to sixmonths, are subject to pricing based upon the latest comparable yield on Government treasury bills.

54

Exploration Risk

The exploration for new petroleum sources is vital to PTTEP’s business and is, in itself, a high risk endeavor.Exploration projects search for petroleum reserves far beneath the surface of the earth. Despite the advancedtechnology used, it is still difficult to accurately understand the petroleum geology at such depths. Absolutegeological confidence is therefore rare and considerable geological uncertainty prevails. Still, the acquisition ofsufficient data and detailed geological analyses can reduce this uncertainty and exploration risks to acceptablelevels.

Some factors that PTTEP takes into consideration when exploring for petroleum resources are theprobability of success, the potential size of the reservoir, and the costs in exploration and development of thereservoirs. To minimize the risks that are associated with these factors, PTTEP develops the capability of itsexploration teams through knowledge management efforts and exploration and production databases shared withinthe PTTEP which institutionalize best practices and lessons learned. Furthermore, PTTEP uses a “peer review”process and consensus building to recommend exploration projects for approval. In order to balance reservegrowth and risk tolerance, the exploration portfolio undergoes strict reviews during the annual work program andbudget formulation period.

Production Risk

Production risks tend to be associated with aging production equipment and human error. To prevent suchrisks, PTTEP emphasizes risk management in every stage of production, from production platform design toproduction control and preventative maintenance. Automatic detection and emergency shutdown systems are inplace to prevent losses during equipment failures. PTTEP uses standardized work procedures and operationmanuals, together with training programs, to instill best practices and risk management in its employees. Inaddition, stringent operational safety assessments are conducted by outside agencies to ensure high standards.PTTEP believes that these systems help to minimize production risks.

Credit Risk

Credit risk includes risks relating to counterparties and the risk that a contractor (including productionsharing contractors) will not perform on a contract. The substantial majority of PTTEP’s sales are currently madeto PTT, PTTEP’s parent company. Otherwise, PTTEP attempts to sell its products to customers with acceptablecredit profiles.

55

THE PETROLEUM INDUSTRY IN THAILAND

The information in the section below has been derived, in part, from various government and privatepublications or obtained in communications with Government agencies in Thailand. This information has notbeen independently verified by PTTEP or the Initial Purchaser or any of PTTEP’s or their respective affiliatesor advisors. The information may not be consistent with other information complied within or outside Thailand.Neither PTTEP nor the Initial Purchaser has any actual knowledge of any material misstatement contained inthis section.

Overview

The Government historically regulated the petroleum industry through volume, distribution and pricingcontrols, which were administered by certain central government ministries including National Energy PolicyCouncil, Energy Policy and Planning Office, the Ministry of Energy (the “MOEN”) and the Ministry of Finance.Today, the Government regulates the domestic wholesale price of LPG marketing margins, natural gas for vehiclesretail price and the pipeline tariff for gas sales to EGAT and private power producers.

Due to a Government policy of reducing Thailand’s dependency on petroleum products and promotingenergy efficiency, crude oil as a percentage of total energy consumption in Thailand decreased from 43.6% in 2006to 36.6 % in 2010 while natural gas as a percentage of total commercial primary energy consumption in Thailandincreased from 37.5% in 2006 to 44.0 % in 2010. The following table sets out the total commercial primary energyconsumption and the percentage of the total commercial primary energy consumption represented by coal,petroleum products, natural gas and hydro-electricity in Thailand for the periods indicated.

Total

Commercial

Primary

Energy

Consumption

Percentage of Total Commercial Primary Energy Consumption

Lignite/Coal

Import

Petroleum

Products

Natural

Gas

Hydro/

Imported

Electricity

(KBoe/d) (%) (%) (%) (%)

Period2006............................................................ 1,545 16.0 43.6 37.5 2.92007............................................................ 1,604 17.4 41.6 38.3 2.72008............................................................ 1,618 18.6 39.2 40.0 2.22009............................................................ 1,663 18.2 38.7 41.0 2.12010............................................................ 1,783 17.4 36.6 44.0 2.0

Source: Energy Policy and Planning Office, Ministry of Energy

The following table sets out the total natural gas consumption in Thailand compared to that of petroleumproducts for the periods indicated.

Natural Gas

Consumption

Petroleum

Products

Consumption

Percentage

Increase in

Natural Gas

Consumption

Percentage

Increase in

Petroleum

Products

Consumption

(KBoe/d) (KBoe/d) (%) (%)

Period2006 .................................................................... 579.01 673.79 2.3 (2.3)2007 .................................................................... 614.67 666.78 6.2 (1.0)2008 .................................................................... 647.95 633.72 5.4 (5.0)2009 .................................................................... 681.72 642.70 5.2 1.42010 .................................................................... 784.18 652.46 15.0 1.5

Source: Energy Policy and Planning Office, Ministry of Energy

56

The following table sets out the total natural gas consumption in Thailand for the periods indicated.

2008 2009 2010

(MMSCFD)

PeriodJanuary................................................................................................. 3,220 2,881 3,576February............................................................................................... 3,378 3,413 3,884March................................................................................................... 3,450 3,578 3,933April..................................................................................................... 3,336 3,451 3,913May...................................................................................................... 3,659 3,635 4,074June...................................................................................................... 3,667 3,735 4,166July ...................................................................................................... 3,693 3,597 4.091August ................................................................................................. 3,680 3,643 4,131September............................................................................................ 3,602 3,793 4,256October ................................................................................................ 3,556 3,761 4,278November ............................................................................................ 3,115 3,752 4,075December............................................................................................. 2,968 3,526 4,086

Source: Energy Policy and Planning Office, Ministry of Energy

From 2006 to 2010, natural gas consumption in Thailand increased from 579 Kboe/d in 2006 to 784 Kboe/din 2010. Petroleum products consumption in Thailand decreased from 674 KBoe/d in 2006 to 652 KBoe/d in 2010.The significant growth in consumption of natural gas is a result of higher demand from power producers who areresponding to higher demand for electricity and switching to natural gas from alternative fuel sources. Highernatural gas consumption was also the result of increased demand for electricity and increased demand for naturalgas from industrial customers and the transportation sector in Thailand. In addition, emissions standards enactedin 1997 required EGAT and industrial users to partially switch from fuel oil to natural gas as a cleaner fuel sourcefor electricity generation.

The following table sets out the amount of electricity generated from various fuel sources in Thailand forthe periods indicated.

Natural

Gas(1) Fuel Oil Lignite Hydro(2) Diesel

Imported

Electricity

and SPP(3) Total

Growth

Rate

(in GWH) (%)

Year2006.............................. 89,325 7,808 18,028 7,995 77 18,685 141,919 5.32007.............................. 98,620 2,967 18,498 7,983 28 18,930 147,026 3.62008.............................. 104,727 990 18,679 6,979 23 16,822 148,221 0.82009.............................. 106,602 448 17,922 6,990 45 16,357 148,364 0.12010.............................. 118,578 558 17,988 5,370 42 21,132 163,668 10.3

Source: Energy Policy and Planning Office, Ministry of Energy

(1) Includes only electricity generated by EGAT and IPPs using natural gas.

(2) Also includes other alternative energies.

(3) Also includes geo-thermal and non-conventional sources.

57

Petroleum Industry

Exploration and Production

The Government owns all of Thailand’s petroleum resources and grants concessions to companies toconduct exploration and production activities in both onshore and offshore properties. As of the end of 2009Thailand commands over 61 active concessions covering 79 exploration blocks. In addition to PTTEP, a numberof foreign-owned companies explore, develop and produce oil and gas properties in Thailand, including ChevronOffshore (Thailand) Ltd. (“Chevron”), ExxonMobil Exploration and Production Khorat Inc. (“ExxonMobil”),formerly named Esso Exploration and Production Khorat Inc.) and Hess (Thailand) Ltd (“Hess”). See“Relationship with the Government and PTT and Regulatory Matters.”

On January 23, 1991, the MTJDA was established for the exploration and exploitation of natural resources,particularly petroleum, in the overlapping continental shelf area in the Gulf of Thailand known as the JDA. TheMTJDA is a statutory body established under the laws of Malaysia and Thailand to assume all rights andresponsibilities on behalf of the two governments. On April 21, 1994, the MTJDA awarded two ProductionSharing Contracts (“PSCs”) in the JDA to contractors. Block A-18 was awarded to Hess Oil Company of Thailandand Petronas Carigali (JDA) Sdn. Bhd (“Carigali”, recently renamed “PC JDA”). Blocks B-17 and C-19 wereawarded to PTTEPI and Carigali. In July 1994, these contractors set up two operating companies to act asoperators in their respective contract areas: Carigali-Hess Operating Company Sdn. Bhd. as operator for BlockA-18 and Carigali-PTTEPI Operating Company Sdn. Bhd. as operator for Blocks B-17 and C-19.

Thailand’s petroleum reserves are dominated by natural gas and approximately 95% of these reserves arelocated in the Gulf of Thailand. According to DMF, as of December 31, 2009, Thailand’s natural gas provedreserves (including Thailand’s 50.0% share in the JDA) totaled 11 trillion standard cubic feet. Proved reserves ofcrude oil and condensate were 180.3 and 255.1 MMbbl, respectively, as of December 31, 2009. Condensatereserves and production levels are largely associated with reserves and production levels of gas properties. Thefollowing table sets out Thailand’s petroleum reserve balances over the last three years.

Proved Reserves Natural Gas Crude Oil Condensate

(TSCF) (MMbbls) (MMbbls)

As of December 31,2007 ............................................................................................................. 11.2 176.0 264.82008 ............................................................................................................. 12.0 182.9 270.82009 ............................................................................................................. 11.0 180.3 255.12010(1).......................................................................................................... N/A N/A N/A

Source: DMF Annual Reports

(1) As of the date of this Offering Memorandum, the 2010 DMF Annual Report has not been released.

In 2009, all petroleum proved reserves decreased from 2008 levels. Natural gas proved reserves balancedecreased 1.0 trillion standard cubic feet (“TSCF”) or 8.3%. Crude oil proved reserves decreased 2.6 MMbbls or1.4% while condensate proved reserves decreased 15.8 MMbbls or 5.8%. The following table sets out Thailand’spetroleum sales over the last three years.

Sales

Natural Gas Crude Oil Condensate

(BSCF) (MMbbls) (MMbbls)

As of December 31,2007 ............................................................................................................. 871.2 48.7 24.02008 ............................................................................................................. 916.7 51.1 27.82009 ............................................................................................................. 861.9 54.0 26.72010(1).......................................................................................................... N/A N/A N/A

Source: DMF Annual Report, Petroleum Institute of Thailand

(1) As of the date of this Offering Memorandum, the 2010 DMF Annual Report has not been released.

58

In 2009, sales of natural gas decreased by 6.0% to 861.9 BSCF and sales of crude oil increased by 5.7% to54.0 MMbbls. Sales of condensate decreased by 4.0% to 26.7 MMbbls.

The following table lists the top producing operators in Thailand and the gross natural gas production andsales volumes for their respective properties in 2009, which are the latest figures available.

Natural Gas Production & Sales

Production Sales

(BSCF) (%) (BSCF) (%)

OperatorPTTEP.................................................................................... 521.3 56.1 447.5 52.3Chevron.................................................................................. 371.2 39.9 371.1 43.3Hess........................................................................................ 29.5 3.2 30.6 3.6ExxonMobil ........................................................................... 7.2 0.8 6.9 0.8

Total ....................................................................................... 929.2 100.0 856.0 100.0

Source: Petroleum Institute of Thailand

In 2009, PTTEP’s nineteen petroleum fields accounted for the largest portion of natural gas produced inThailand, primarily through the Bongkot project. Chevron was the second largest producing operator of naturalgas in Thailand. Produced natural gas to sales gas loss rate for Thailand averaged less than 8%, which includedlosses from flaring, some carbon dioxide removal and in-field energy use.

Crude Oil Procurement, Transportation and Distribution

In 2010, more than 83.7% of crude oil demand in Thailand was supplied by imports. Crude oil productionin Thailand increased 7.2% to 156,600 Bbls/d in 2010. Imported crude oil amounted to 803,700 Bbls/d, an increaseof 1.9% from 2009. Of this amount, 585,900 Bbls/d came from the Middle East, 73,100 Bbls/d from the Far Eastand 144,700 Bbls/d from other sources. Crude oil is transported within Thailand by marine tankers, pipelines,trucks or railway, depending on the location of the oil field and refinery.

All imported crude oil is shipped by oil tankers to oil jetties along the coastline of Thailand while domesticcrude is mainly transported to refineries by rail. Most of the crude oil shipped to the oil jetties is delivered torefineries located in their vicinity through connection pipelines. Currently, Thailand’s seven refineries are theprincipal processors of imported and domestic crude oil. Most of the refineries are located in the coastal regionin Thailand and all of them have connecting pipelines to an oil jetty located nearby.

Refining of Petroleum Products

The manufacture of refined petroleum products in Thailand is currently dominated by nine refineries, fourof which are owned by PTT.

As of September 30, 2010, the EPPO estimated that Thailand’s primary refining capacity was approximately1,075 Kb/d, and Thailand’s total refining throughput was approximately 956 Kb/d (55,491 million liters per year).

59

The following table sets out Thailand’s total production of certain principal refined products for the periodsindicated.

Year ended December 31,

Product 2008 2009 2010

(in millions of liters)

Gasoline....................................................................................................... 8,449.0 8,852.1 8,741.8Diesel ........................................................................................................... 20,769.0 22,489.0 23,304.8Aviation Fuel ............................................................................................... 6,001.9 5,975.0 6,196.1Fuel Oil........................................................................................................ 6,873.3 6,884.2 5,999.8Kerosene ...................................................................................................... 194.9 92.9 466.7LPG.............................................................................................................. 8,560.3 9,146.7 10,781.6Total ............................................................................................................. 50,848.3 53,439.8 55,490.8

Source: Department of Energy Business, Ministry of Energy

Trading and Marketing of Refined Petroleum Products

The trading of refined petroleum products in Thailand occurs through commercial, retail and internationaltrading networks. The commercial distribution market is characterized by competition among several majorplayers, including PTT. Retailing of refined petroleum products is open to domestic companies and foreigncompanies and Thai-foreign joint ventures. The following table sets out the number of service stations in Thailandas of September 30, 2010 and the market share by number of stations for the ten largest service station chains.

Product

Number of

stations Market share

(%)

PTT.................................................................................................................................... 1,163 6.07Bangchak........................................................................................................................... 1,060 5.52Shell .................................................................................................................................. 547 2.85Esso ................................................................................................................................... 538 2.80Chevron............................................................................................................................. 424 2.21Paktai................................................................................................................................. 289 1.51Picnic................................................................................................................................. 268 1.39Siam Gas........................................................................................................................... 246 1.28Susco ................................................................................................................................. 147 0.76PTT (retail) ....................................................................................................................... 146 0.76Other.................................................................................................................................. 14,367 74.85Total .................................................................................................................................. 19,195 100.00

Source: Department of Energy Business, Ministry of Energy

60

RELATIONSHIP WITH THE GOVERNMENT AND PTT AND REGULATORY MATTERS

General Overview

PTTEP was established in 1985 pursuant to a resolution of the Cabinet to enable the Government to holdpetroleum concessions and to bring into existence an organization with an independent, flexible and efficientmanagement that would be able to compete in the international petroleum industry. PTT is a state enterprise whichowned 65.32% of the issued and outstanding ordinary shares of PTTEP as of February 15, 2011. The Council ofMinisters has adopted a resolution setting forth a policy requiring PTT to retain a minimum of 51% of the issuedand outstanding ordinary shares of PTTEP. So long as PTT remains a state enterprise and PTT continues to ownmore than 50% of PTTEP’s outstanding capital stock, PTTEP will remain a state enterprise as defined undercurrent Thai law.

While the Council of Ministers has adopted a resolution generally exempting PTTEP from the orders, rules,regulations and resolutions of the Council of Ministers which normally apply to state enterprises, as a matter ofGovernment policy currently in effect, PTTEP, as a state enterprise, must have its financial statements audited bythe Office of the Auditor General of Thailand. PTTEP will continue to be subject to the restrictions describedabove until such time as government policy changes or the Government (through PTT or otherwise) ceases to ownno more than 50% of the outstanding capital stock of PTTEP.

In addition to the status of PTTEP as a state enterprise under Thai law, PTTEP, as a majority ownedsubsidiary of PTT, is controlled by PTT and maintains a significant business relationship with PTT. See “PrincipalShareholders.”

Regulatory Matters

The MOEN was established in 2002 as part of a ministerial restructuring. The creation of the MOEN wasaimed at achieving better integration and higher efficiencies in the formulation and implementation of thecountry’s energy related policies. The majority of the departments under the MOEN were transferred from theMinistry of Industry with the key addition of the National Energy Policy Office, which was previously under thedirect control of the Prime Minister.

The MOEN and its key offices, including the Department of Mineral Fuels, the Department of EnergyBusiness and the Energy Policy and Planning Office, make up an instrumental government body with the authorityto formulate, make recommendations on, and oversee the implementation of policies related to the country’spresent and future energy requirements. Such policies include the management of the country’s indigenousresources through the granting of concessions to explore and produce natural gas in the Gulf of Thailand.

The Government owns all of Thailand’s petroleum resources and has enacted Petroleum Act B.E. 2514(1971) and Petroleum Income Tax Act B.E. 2514 (1971), as amended (the “Petroleum Acts”) to govern the awardof concessions for exploration and production rights in Thailand. The Petroleum Acts have been amended overtime into four different concession regimes, commonly referred to as “Thailand I,” “Thailand II,” “Thailand III”and “Thailand IV.” Exploration and production of all properties in Thailand in which PTTEP currently has aworking interest is governed by Thailand I, Thailand III and Thailand IV.

Thailand I is applicable to all offshore concessions granted from 1971 to 1989 and all onshore concessionsgranted prior to 1982 and provides for exploration periods of eight years with an extension of four years at thediscretion of the MOEN. After five years, a concessionaire is required to relinquish exploration rights to 50.0%of the original concession area. Unless a concession period is renewed, the concessionaire must relinquish the rightto explore the remaining area at the termination of the exploration period. If renewed, the concessionaire mustrelinquish 25.0% of the original exploration area at the commencement of the renewal period. Thailand I providesfor a 30-year production period from the date of termination of the exploration period, with a discretionaryextension by the MOEN of up to 10 years. Thailand I provides for a fixed 12.5% royalty, payable quarterly, anda petroleum income tax of 50% of net profit derived from the petroleum business. For the purposes of determiningthe petroleum income tax due under Thailand I for any tax period, a taxpayer’s Thailand I royalty may be creditedagainst the corresponding petroleum income tax liability incurred in the tax period in which such royalty isincurred, but if the royalty exceeds the income tax liability in any year, the excess is not refunded and may notbe carried forward for use in subsequent year.

61

Thailand III is applicable to all concessions granted since 1990, and provides for exploration periods of sixyears with an extension of three years at the discretion of the MOEN. Under Thailand III, after four years aconcessionaire is required to relinquish exploration rights to 50.0% of the original concession area. Unless aconcession period is renewed, the concessionaire must relinquish the right to explore the remaining area at thetermination of the exploration period. If renewed, the concessionaire must relinquish 25.0% of the originalexploration area at the commencement of the renewal period. Thailand III provides for a 20-year production periodfrom the date of termination of the exploration period, with a discretionary extension by the MOEN of up to 10years. Thailand III provides for a royalty, payable monthly, of between 5.0% and 15.0%, based on the rate of sales,and a petroleum income tax of 50% of net profit derived from the petroleum business, as well as a special tax onprofits exceeding a certain threshold at rates from zero to 75.0%. A taxpayer’s Thailand III royalty may not becredited for purposes of determining the petroleum income tax liability due under Thailand III, but is deductibleas an expense.

Thailand IV is applicable to all concessions granted since October 2007, and provides for explorationperiods of six years with an extension of three years at the discretion of the MOEN. Under Thailand IV, after fouryears a concessionaire is required to relinquish exploration rights to 50.0% of the original concession area. Unlessa concession period is renewed, the concessionaire must relinquish the right to explore the remaining area at thetermination of the exploration period. If renewed, the concessionaire must relinquish 25.0% of the originalexploration area at the commencement of the renewal period. Thailand IV provides for a 20-year productionperiod from the date of termination of the exploration period, with a discretionary extension by the MOEN of upto 10 years. Thailand IV provides for a royalty, payable monthly, of between 5.0% and 15.0%, based on the rateof sales, and a petroleum income tax of 50% of net profit derived from the petroleum business, as well as a specialtax on profits exceeding a certain threshold at rates from zero to 75.0%. A taxpayer’s Thailand IV royalty may notbe credited for purposes of determining the petroleum income tax liability due under Thailand IV, but is deductibleas an expense.

Under Thailand I, the MOEN granted exploration blocks of 10,000 square kilometers each, and eachapplicant may receive up to five exploration blocks in the aggregate containing no more than 50,000 squarekilometers. Under Thailand III, onshore blocks of up to 4,000 square kilometers are granted, and each applicantmay receive up to five exploration blocks, in the aggregate containing no more than 20,000 square kilometers.Under Thailand IV, onshore blocks of up to 4,000 square kilometers are granted, and there is no limitation on thenumber of exploration block granted.

The Petroleum Acts impose price caps on prices charged for crude oil and condensate and natural gasproduced for domestic consumption. The price charged on crude oil or condensate produced for domesticconsumption must not exceed the average price of exported crude oil or condensate realized by all concessionairesin the preceding calendar month. The difference in quality of crude oil and condensate, transportation cost, as wellas any other relevant circumstances must be taken into account when determining the price that can be chargedby a concessionaire.

The price of natural gas produced for domestic consumption must be as agreed between a concessionaireand the Petroleum Committee with the consent of the Minister of Energy and must not exceed the average priceof exported natural gas, taking into account the difference in quality and transportation cost.

62

PTTEP CORPORATE STRUCTURE

PTTEP was incorporated in 1985 pursuant to a resolution of the Cabinet as the oil and natural gasexploration and production arm of PTT, which is a state enterprise that was established to develop and promoteThailand’s petroleum industry and to ensure the security of Thailand’s energy supply.

A simplified corporate and financing structure of the PTTEP Group as of February 28, 2011, is set out below.

PTTEP(1)

75%

PTTEPOffshore

InvestmentCompanyLimited

25%PTTEP

InternationalLimited

100%

PTTEPNetherland

HoldingLimited

PTTEPNetherlandsCoöperatie

U.A.

PTTEPCanadaLimited

PTTEPCanada

InternationalFinance

Limited(2)

100%

1%100%

100%100%

99%

PTTEPHolding

CompanyLimited

Notes:

(1) PTTEP will be providing a senior guarantee of the Notes. The Guarantee will be unsecured, rank equally with all of PTTEP’s existingand future senior debt and senior to all of PTTEP’s existing and future subordinated debt.

(2) The Issuer will on-lend the proceeds from the sale of the Notes to one or more subsidiaries of PTTEP by way of intercompany loans.

63

BUSINESS

General

PTTEP’s principal activity is the petroleum exploration, production and development of interests in oil andnatural gas and crude oil properties and reserves in Thailand, in neighboring countries and elsewhereinternationally. PTTEP was incorporated in 1985 as the oil and natural gas exploration and production arm of PTT,a state enterprise established to develop and promote Thailand’s petroleum industry and to ensure the security ofThailand’s energy supply. PTT had a 65.32% ownership interest in the Company as of February 15, 2011.

PTTEP conducts a substantial portion of its exploration and production activities through its workinginterests in petroleum concessions operated through joint ventures with international oil and gas companies. UnderPTTEP’s joint venture arrangements, one joint venture participant actively manages the concession as operator inaccordance with the terms of a joint venture agreement. As of January 31, 2011, PTTEP had participation interestsranging from 5.0% to 100.0% in 19 Thai projects, 14 regional projects in neighboring countries and 11international projects. Of these projects, PTTEP has participation interests ranging from 19.3% to 100.0% in fourinvestment projects in Myanmar. PTTEP is also the operator of seven Thai petroleum exploration and developmentprojects in which it holds a 100.0% interest.

PTTEP’s common stock was first listed on the Stock Exchange of Thailand in June 1993. PTTEP’s marketcapitalization as at February 28, 2011 was Baht 555,838 million, making it the second largest publicly tradedcompany in Thailand.

Competitive Strengths

PTTEP believes that its historical success and future prospects are directly related to a combination ofstrengths, including the following.

Leading regional exploration and production company with substantial international exposure

PTTEP is the largest publicly-listed oil and gas exploration and production company in Thailand and aleading oil and gas producer among publicly-listed oil companies in South East Asia. It is also one of the largestindependent exploration and production companies in South East Asia in terms of reserves and production, withgross proved reserves of 1,043 MMboe, as well as production of 304 Kboe/d for the year ended December 31,2010. Given its large size, the Company has the resources and expertise to serve as operator of many of its blocks.

PTTEP believes its large portfolio of blocks offers a diversification of reserves, production and explorationopportunities and risk. It has also diversified internationally, acquiring attractive assets in Australia, Canada, theMiddle East, and North Africa, in addition to acquiring assets in South East Asia. As of January 31, 2011, itsportfolio comprises a total of 44 projects, consisting of a combination of both oil and gas assets. The majority ofthe Company’s reserves are located in Thailand and nearby areas overlapping with Thailand’s neighbors (19blocks), out of which 14 are producing. The remaining 25 projects are located overseas across the Asia Pacific,North American, Middle Eastern and North African regions. The remaining projects, which are not currentlyproducing, are at various stages of exploration and development.

The Company believes its financial and operational strength allows it better access to the domestic andinternational capital markets to fund its acquisition and development costs, as demonstrated by its successfulprevious fund raisings in the capital markets.

Strong relationship with majority shareholder

PTTEP has a strong relationship with its majority shareholder, PTT. PTTEP was founded as the explorationand production arm of PTT in 1985. PTT had a 65.32% ownership interest in PTTEP as of February 15, 2011.Many of PTTEP’s directors and senior managers worked at PTT before working at PTTEP and several membersof PTT’s board of directors are also members of PTTEP’s board of directors.

PTT is Thailand’s national energy and petrochemical group and possesses a strong financial position andgovernment backing in the Thai petroleum markets. PTT also purchases substantially all of the natural gasproduction in Thailand, providing 98% of PTTEP’s natural gas sales revenue in 2010. PTT is the largest supplierof petroleum and petrochemical products in Thailand. The relationship with PTT also creates synergies betweenPTTEP and PTT in the natural gas value chain, ensuring access to petroleum production for PTT and a guaranteedcustomer relationship for PTTEP. PTT enjoys a natural monopoly as the owner and operator of Thailand’s entire

64

gas transmission and distribution pipeline system, which PTTEP uses to transport natural gas to PTT. As agovernment corporation, PTT provides leverage and support for PTTEP’s relationships with other governmentbodies and agencies. PTTEP works closely and coordinates with PTT and related government agencies tocollectively outline and implement Thailand’s national petroleum supply plans and policies.

Experienced management team

PTTEP’s senior management team has extensive experience in the oil and gas industry, and most of itsexecutives have been with PTTEP or PTT since PTTEP’s inception in 1985. PTTEP’s management team and staffhave had the opportunity to work closely with foreign partners both within and outside Thailand. PTTEP has beenable to deploy experienced management team members across its geographic operations to implement projects andoversee operations. PTTEP believes that its management team has contributed significantly to its past success andwill continue to contribute to its future growth.

Well-positioned to benefit from Thailand’s increasing energy consumption

PTTEP’s role as the sole investment vehicle for the Government in undertaking exploration and productionactivities and developing a long-term natural gas supply for Thailand plays an important role in developingThailand’s hydrocarbon reserves. In 2010, PTTEP’s sales accounted for approximately 31% of total nationalproduction of petroleum products. In the year ended December 31, 2010, approximately 44% of Thailand’sprimary energy consumption was from natural gas and in that same period natural gas accounted for approximately72% of fuel for power generation by the Electricity Generating Authority of Thailand, independent powerproducers, and small power producers, PTT’s primary customers for natural gas. Natural gas consumption hasexperienced persistent growth, generating a growth rate of 13.1%, from 3,597 MMSCFD in 2009 to 4,039MMSCFD in 2010, according to EPPO.

Strong reserves base to support production growth

PTTEP’s proved undeveloped reserves accounted for approximately 55% of its 1,043 MMboe provedreserves as of December 31, 2010. PTTEP intends to utilize this proved undeveloped reserve base and otherreserve prospects to grow its production and sales. PTTEP has an established track record of growing its reservesand production: during 2010, PTTEP’s average daily sales volume increased approximately 13% compared to2009, while its compound average growth rate for the three years ended December 31, 2010 was 9.8%. Keyprojects for PTTEP’s growth include the development of Arthit North and MT-JDA.

Significant growth, stable margins and competitive cost structure

PTTEP’s sales volumes have increased at a compound annual growth rate of 9.8% over the past three years.This increase is due to contributions in the sales of petroleum from Arthit, which experienced its first full year ofproduction in 2009, Arthit North, which commenced production in 2009, and MTJDA project, which commencedproduction in February 2010. PTTEP’s EBITDA increased in line with the sales growth, with a compound annualgrowth rate of 9.8% reaching Baht 101,708 million (U.S.$3.4 billion) in 2010. Since 2008, PTTEP has alsomaintained EBITDA margins over 65.4%. PTTEP’s finding and development costs are low due to productionsharing contracts with various foreign partners. In the years ended December 31, 2008, 2009 and 2010, PTTEP’sfinding and development costs were U.S.$15.7 per Boe, U.S.$11.1 per Boe and U.S.$13.6 per Boe, respectively.Low finding and development costs allow for the capital-efficient growth of PTTEP’s business, while its lowoperating costs further enhance returns and operating margins. In the years ended December 31, 2008, 2009 and2010, PTTEP’s lifting costs were U.S.$2.46 per Boe, U.S.$3.16 per Boe and U.S.$3.75 per Boe, respectively.PTTEP believes that this is significantly lower than the average lifting cost of most other exploration andproduction companies. Lifting costs consist of field operating expenses. PTTEP kept its lifting costs low throughvarious measures, including more efficient use of offshore infrastructure, the adoption of new technology in itsoperations, renegotiation of supply-chain costs, standardization among existing assets, as well as the adoption ofan excellence program to further develop its organizational capacity with a focus on organization restructuring,business process streamlining and optimizing resource allocation. PTTEP believes that its growth of EBITDA andmaintenance of its EBITDA margin is evidence of PTTEP’s focused development objectives, synergies with PTToperations as well as its cost structure. These factors allow it to compete effectively, even in a low crude oil priceenvironment.

65

Strategy

PTTEP’s primary objective as a leading exploration and production company is to enhance its position inthe Southeast Asian region and internationally. Significant elements of PTTEP’s strategy include the following:

Expanding its investment portfolio with a goal towards sustainable growth, and focus on growth by targetingselected acquisitions

PTTEP intends to capitalize on synergies with its subsidiaries and expand its investments and acquisitionsin particular areas including Southeast Asia, Canada and Australia. In addition, PTTEP plans to focus on areas orcountries that it believes have high petroleum potential and those where it has existing projects or interests tomaximize value, including Australia, Indonesia, Vietnam and Canada. PTTEP sees these developments as anopportunity to pursue acquisitions which would create value for it in the long term. PTTEP intends to focus mainlyon business development and transactions with respect to conventional exploration and production projects in thedevelopment and production phase and where the opportunities fit with PTTEP’s corporate culture. However, aswith the acquisition of SCP, PTTEP will also selectively pursue opportunities to invest in unconventionalexploration and production projects characterized by specialized technological expertise and high investment andunit costs (for example, oil sands, deepwater drilling and heavy oil). PTTEP is currently in the study phase ofdeveloping FLNG production, which is an emerging offshore production technology to monetize stranded gasresources. The areas of commercial focus for FLNG production will be in the Cash/Maple and Oliver fields in theTimor Sea. Both the oil sands and FLNG opportunities resulted from PTTEP’s continued monitoring and researchinto “mega trends,” which may provide sustainable long-term growth.

Continuing to participate in key regional and international petroleum projects

Since PTTEP was founded as the exploration and production arm of PTT in 1985, PTTEP has benefited fromthe Government’s policy of encouraging Thai participation in exploration and production activities in the region.As a result, PTTEP has participated in key projects in its regional focus areas of the Gulf of Thailand and the Gulfof Martaban, which PTT believes are attractive exploration and development areas due to their reserve potential,relatively low geological risk and finding costs and a developing infrastructure network of gathering systems,pipelines and platforms.

In PTTEP’s early stages of development, working interests were acquired through Government rights.Subsequently, PTTEP successfully developed relationships with leading international oil and gas companies andhas independently negotiated interests in many of its projects. PTTEP has also been able to farm-in to numerousother projects in Thailand and internationally. To farm-in is to acquire an interest in a lease or concession ownedby another operator on which oil or gas has been discovered or is being produced.

PTTEP believes that with its growing regional knowledge base, technical capability and its closerelationships with PTT, the Government and international oil and gas companies, it is well positioned to continueto take advantage of favorable exploration and development opportunities in the region, particularly in Thailandand elsewhere in Southeast Asia, as well as internationally.

Maximize existing assets through production plateau extension initiatives and implementing supply chainsecurity

PTTEP’s sales volume averaged 264,575 Boe/d in 2010, approximately 13% higher than its average salesvolume of 233,756 Boe/d in 2009. From 2008 to 2010, the compound annual growth rate of petroleum sales byvolume was 9.8%. PTTEP intends to increase the production level, production plateau period and production lifeof its existing assets by focusing on maximizing the recovery at its producing projects. PTTEP intends to continueactively developing its large undeveloped proved reserves which accounted for 55% of its proved reserves as ofDecember 31, 2010. PTTEP also expects further resources to be discovered by continuing to explore the areas nearits existing projects. In 2010, PTTEP succeeded in discovering petroleum in 15 of 18 exploration and appraisalwells drilled, which is equivalent to a drilling success rate of 83%.

PTTEP is dedicated to ensuring that Thailand has a secure supply of energy to meet its current and futureneeds. To respond to the dynamics of energy demand, PTTEP has closely monitored petroleum demands and hasbeen coordinating with PTT and related government agencies to collectively outline the optimal supply plan.PTTEP also has reviewed and adjusted its production as well as project development plans to match energyrequirements. In 2010, PTTEP conducted a study, provided a detailed evaluation of PTTEP’s competitiveness inselected countries and business technologies, the result of which was integrated into PTTEP’s overall growthstrategy roadmap with prioritized countries and technology to be pursued.

66

Implementing cost savings initiatives to optimize value from existing assets

PTTEP periodically reviews investment plans for its existing assets and has rescheduled investments witha view toward optimizing asset value. In particular, PTTEP focuses on cost savings initiatives such asrenegotiating procurement spending, so that product quantities and procurement periods are clearly defined inorder to coincide with the prevailing market situation. PTTEP also plans to standardize these initiatives across itsexisting assets. Moreover, PTTEP has initiated programs to improve its project management performance and theoverall efficiency of its production and operation activities.

Strengthen the capability of its operating model through enhancing organizational excellence in accordancewith international standards

PTTEP is instituting programs to enhance the efficiency and productivity of its business operations includingmeasures to accelerate the recruitment process in support of its business expansion activities, as well as toaccelerate the development and improve the skills of its personnel. On the technological side, PTTEP strives tocontinually gain new drilling and exploration competencies. PTTEP will complement these initiatives bydeveloping its structured leadership development program. PTTEP hopes that their initiatives will allow PTTEPto maintain its high level of corporate governance. PTTEP is also strengthening its organizational support tobusiness expansion and long-term growth through reviews and streamlining of the procurement process, theinvestment process and the portfolio management process.

Recent Developments

Acquisition of an Interest in the Kai Kos Dehseh Project

On January 21, 2011, PTTEP, through its subsidiary, PTTEP CA, acquired from two indirect subsidiaries ofStatoil a 40% interest in SCP, a partnership that owns KKD in Alberta, Canada, for consideration of U.S.$2.28billion. Statoil owns the remaining 60% interest in SCP and is the managing partner. PTTEP and Statoil enteredinto several key agreements to govern the sale and their partnership. KKD is an oil sands project, which PTTEPestimates has 3.8 to 4.3 billion Bbls of recoverable Bitumen resources as independently vertified by a leadingexternal petroleum consultant. The project is an in-situ oil sands project utilizing SAGD technology, and has anexpected project life of over 40 years. Commercial production began in January 2011. On March 19, 2011, PTTEPand Statoil entered into a memorandum of understanding to jointly investigate future collaboration opportunitiesinternationally.

Oil sands are composed of a mixture of sand, clay and other mineral matter, water and bitumen. The largestproven deposit of oil sands reserves is in Alberta, Canada although deposits also exist in Venezuela, Russia, theUnited States, Madagascar, Albania, Trinidad and Romania. The first oil sands project in Canada began in 1967.The Athabasca region, where KKD is located, is one of three oil sands regions in Alberta. The two extractionmethods used in Canadian oil sands projects are surface mining and in-situ methods. Surface mining is generallyused for oil sands located less than 75 meters from the surface. For deeper deposits, in-situ methods, whichresemble conventional oil drill projects, are used. There are several types of in-situ methods and KKD uses SAGD.The SAGD method injects steam into the earth to heat the bitumen and help separate it from the sand, then it ispumped to the surface. Bitumen extracted from oil sands is so viscous that it does not flow at normal temperatures.It has to be either blended with diluent to be able to flow through a pipeline and sold as blended bitumen orupgraded into synthetic crude oil by bitumen upgraders, which is a process of removing heavy components. Afterone of these two processes are complete, refineries can transform bitumen or synthetic crude oil into variouspetroleum products.

PTTEP has included unaudited pro forma combined financial information as of and for the year endedDecember 31, 2010 as well as the audited financial statements of SCP as of and for the year ended December 31,2010 elsewhere in this Offering Memorandum to illustrate the pro forma combined results of operations followingthe acquisition and provide information on the historical results of operations of SCP. See, “Unaudited Pro FormaCombined Financial Information.”

Project Description

KKD is located in Alberta, Canada, approximately 100 km southwest from Fort McMurray, Alberta, Canada.The project includes five fields, Leismer, Corner, Thornbury, Hangingstone, and South Leismer covering 257,200acres. When fully developed, KKD will include four hubs and a total planned project capacity of over 300,000Bbls/d. PTTEP CA has assessed KKD’s reserves using the COGE Handbook for estimating its resources and

67

reserves, which is broadly aligned with the SPE guidelines. Accordingly, PTTEP estimates that the total expectedBitumen resources for the project will be between 3.8 and 4.3 billion Bbls as independently verified by a leadingexternal petroleum consultant. Statoil acquired its interest in the corporate entity holding KKD in June 2007 andhas since invested over U.S.$1.8 billion in the development of the project, exclusive of the acquisition cost.

The first phase of development was a demonstration plant for the Leismer Demonstration Plant. The LeismerDemonstration Plant became operational in December 2010 and commercial production commenced in January2011. It currently has an approved capacity of 40,000 Bbls/d of bitumen and built-in processing and well capacitysufficient to raise production to the commercial scale of 18,800 Bbls/d. The Leismer Demonstration Plant isconnected via a 75 km pipeline to storage facilities in Cheecham, Alberta.

The KKD project is currently advancing plans for a second phase of development at the Leismer field. Inaddition, KKD is currently developing plans for the Corner field with a production capacity target of 40,000 Bbls/dof bitumen in the first phase.

For more information, see “Risk Factors — Risks Relating to the Acquisition of an interest in SCP.”

Material Agreements

PTTEP indirectly holds its interest in SCP through its wholly-owned subsidiary PTTEP CA. PTTEP CAholds a 40% interest in SCP, which wholly-owns KKD. PTTEP’s relationship with Statoil and SCP is governedby a Partnership Agreement dated January 21, 2011. Under the Partnership Agreement, Statoil is the initialmanaging partner in charge of oversight of the operations of SCP. However, unanimous approval of a managementcommittee representing each of the partners is required for many decisions, including approving changes to, andthe initiation of, project plans, accumulating debt, making expenditures over certain thresholds and othersignificant changes to the operations of KKD.

SCP sells its entire production volume of bitumen to Statoil under a sales agreement entered into as part ofthe acquisition process. The sales agreement is a long-term agreement for the life of SCP or until certainproduction volumes are reached. Once those volumes are reached, PTTEP can exercise its option to take its shareof production. The price of the bitumen is set according to a formula that references market benchmarks andpre-determined adjustments for adjustments for delivery costs, U.S. duties and marketing fees.

Montara Commission of Inquiry and Montara Action Plan

In August 2009, an oil and gas leak began during the Montara H1’s development well drilling whichcontinued until PTTEP AA stopped the leak in November 2009. The causes of the uncontrolled oil and gas releaseinclude deficiencies in the Montara H1 well cementing operation and well barrier testing and the failure to installall required pressure containing corrosion caps. In addition, other causative factors in the uncontrolled oil and gasrelease may have included inadequate supervision and monitoring of operations and personnel and deficiencies inwell management documentation and systems. During operations to stop the leak, PTTEP AA’s wellhead platformand the contractor-operated West Atlas drilling rig caught fire, causing substantial damage to both the wellheadplatform and the West Atlas rig. This affected the production start-up. In order to maintain control of the well andfix damaged production facilities, PTTEP AA temporarily suspended the development of the Montara H1 well.

Montara Commission of Inquiry

In November 2009, the Australian Minister for Resources, Energy and Tourism announced a Commissionof Inquiry (the “Commission”) into the Montara Incident. The Commission was charged with investigating severalmatters, including: (i) the likely causes of the incident; (ii) the adequacy and effectiveness of the regulatoryregime, including approved safety, environment and resource management arrangements; (iii) the performance ofrelevant persons in carrying out their obligations under the regulatory regime; (iv) the adequacy of responserequirements and the actual response to the incident; (v) the environmental impacts as a result of the incident,including reviewing environmental monitoring plans; and (vi) the offshore petroleum industry’s response to theincident and the provision and accessibility of information concerning the incident to stakeholders and theAustralian community.

On November 24, 2010, the Australian Minister for Resources, Energy and Tourism publicly released thefact finding report into the causes of and response to the Montara Incident prepared by the Commission. TheCommission found that the blowout occurred because the primary well control barrier failed to stop a surge of oiland gas in the well due to defects in the installation of the primary control barrier. Furthermore, the secondarycontrol barriers were not in place at the time of the surge. The Commission identified material deficiencies in the

68

procedures followed by PTTEP AA employees in connection with the Montara Incident and was critical of thegeneral management of the operations as well as specific actions taken and not taken by PTTEP AA and PTTEPleading up to and following the spill, including the mechanics and management of the drilling operations as wellas the subsequent spill containment efforts.

The Minister for Energy, Resources and Tourism has broad powers under the OPGGS Act to review, vary,suspend or cancel petroleum titles, including those with respect to the Montara project and PTTEP AA’s otherprojects in Australia. Following the Commission’s report recommended that the Minister conduct such a reviewand if he determines that there were violations of the OPGGS Act that he should consider revoking PTTEP AA’slicenses.

Montara Action Plan

PTTEP AA, in conjunction with industry experts and the relevant Australian regulatory bodies, developedand implemented an action plan as a coordinated response to the issues identified in the Commission’s Report (the“Action Plan”). The Action Plan addressed both technical and governance issues, as well as safety, security, healthand management concerns. In June 2010, PTTEP AA submitted the action plan to the Government of Australiafor review. Following the recommendation of the Commission’s report, the Minister for Energy, Resources andTourism conducted a review of PTTEP AA’s petroleum titles for the Montara Project and all of its other Australianoperations. The review process included an independent third-party review of the Action Plan.

On February 4, 2011, the Minister for Energy, Resources and Tourism announced his determination that theAction Plan effectively responded to the issues identified by the Commission. As a result, the Minister decidednot to pursue further inquiries or reviews of PTTEP AA’s petroleum titles. This decision was conditioned onPTTEP AA implementing the plan under an 18-month monitoring program overseen by independent industryexperts appointed by the Government of Australia. PTTEP, PTTEP AA and the Government of Australia enteredinto a Deed of Agreement in respect of PTTEP AA’s operations and the monitoring plan on February 22, 2011.If the independent monitors determine that PTTEP and PTTEP AA have failed to implement the Action Plan orfulfilled their obligations under the Deed of Agreement, the Minister for Energy, Resources and Tourism hasreserved the right to further review PTTEP AA’s petroleum licenses. The Government of Australia has alsoinformed PTTEP AA that new licenses or renewals of existing licenses will be subject to further conditions relatingto technical competency, corporate governance and reporting requirements with respect to PTTEP AA’s offshoreoperations. These conditions are also likely to be applied to the Montara licences by way of a direction under theOPGGS Act. PTTEP AA is currently discussing the details of these conditions with the Government of Australia.

For more information, see “Risk Factors — PTTEP AA and PTTEP may face material adverse consequencesas a result of ongoing and future investigations into the Montara Incident conducted by various Australiangovernmental agencies”, “Business — Principal Properties — Principal Properties Under Production — Overseas— PTTEP Australasia — Montara Project” and “Business — Environmental Matters — Montara Incident.”

Negotiations with the Government of Indonesia

On August 26, 2010, PTTEP AA received a letter from the Government of Indonesia claiming U.S.$2.5billion in compensation related to the Montara Incident. Further details of the claim and supporting documentationwere received in October 2010. PTTEP AA has not accepted the claim as PTTEP AA believes that it is notsupported by scientifically valid evidence. PTTEP AA continues to actively engage the Government of Indonesia,but has not accepted any legal liability to pay compensation to the Government of Indonesia. In December 2010,PTTEP AA and the Government of Indonesia agreed to provide each other with additional documents and toconduct a joint survey to verify the Government of Indonesia’s data on the claimed damage to its fishing industry.PTTEP AA and the Government of Indonesia met again for discussions in February 2011. As of the date of thisOffering Memorandum, no conclusion has been reached regarding any claims for compensation.

Reserves

PTTEP categorizes reserves as “proved” reserves when those quantities are commercially practical toproduce in the future based on existing geological and engineering data, current prices and economic conditions.In the case of natural gas and condensate reserves, PTTEP does not consider reserves from particular prospectsas “proved” until the material terms of a sales agreement for natural gas or condensate from such prospect havebeen agreed with a purchaser. Thereafter, PTTEP may categorize additional reserves from such prospects as“proved” as and when PTTEP determines that additional quantities are reasonably certain to be recoverable in thefuture under existing economic and operating conditions. This practice is consistent with the Society of Petroleum

69

Engineers guidelines with respect to such additional reserves, but may be viewed as more conservative than suchguidelines with respect to the initial classification of reserves as “proved” from a particular prospect. Provedreserves do not include petroleum that may be produced as a result of the introduction of new technology (unlessproved successfully) or changes in petroleum prices or economic conditions. PTTEP’s proved reserves arereported on a gross basis, which includes PTTEP’s net working interests and the related host-country interests.

At December 31, 2010, PTTEP had estimated proved natural gas reserves of approximately 5,325 BSCF andproved oil and condensate reserves of approximately 214 MMstb.

Proved Reserves as of December 31, 2010(1)

Crude Oil Condensate Natural Gas BOE

(MMbbls) (MMbbls) (BSCF) (MMboe)

Total ............................................................................ 138.85 74.87 5,324.95 1,043.05

(1) Proved Reserves as of December 31, 2010 does not include any proved reserves from KKD, which was not acquired until January 21,2011.

PTTEP categorizes as “proved developed reserves” that portion of proved reserves that it expects to recoverthrough existing wells with existing equipment and operating methods and through improved recovery techniquesfrom successful pilot projects or installed programs without any further significant investments required.

The table below sets forth information about PTTEP’s proved reserves and proved developed reserves as ofDecember 31, 2008, 2009 and 2010.

At December 31,

2008 2009 2010

Natural gas (BSCF):Proved reserves

Beginning of year .............................................................. 4,844.05 4,770.27 5,649.31Revisions of previous estimates........................................ 172.68 204.61 78.83Improved recovery............................................................. 6.44 23.82 19.20Extensions, discoveries and other ..................................... 156.75 1,076.04 100.66Purchases/Sales of reserves in place................................. — — —Production for the year...................................................... (409.66) (427.27) (518.04)

End of year ........................................................................ 4,770.27 5,649.31 5,324.95

Crude oil and condensate (MMls):Proved reserves

Beginning of year .............................................................. 196.51 201.16 219.29Revisions of previous estimates........................................ 8.47 7.97 4.23Improved recovery............................................................. 5.10 2.06 15.55Extensions, discoveries and other ..................................... 14.92 6.27 1.74Purchases/Sales of reserves in place................................. — 27.47 —Production for the year...................................................... (23.85) (25.67) (27.11)

End of year ........................................................................ 201.16 219.29 213.71

70

PTTEP’s proved reserves of natural gas at December 31, 2010 decreased by 5.7% whilst its estimatedproved reserves of crude oil and condensate decreased by 2.5% from December 31, 2009. PTTEP’s proveddeveloped reserves of natural gas increased in 2010 by 4.0%, while its proved developed reserves of crude oil andcondensate decreased by 12.9%. The decrease in proved reserves of natural gas was attributable primarily ongoingproduction activities, which were not offset by discoveries of commercial natural gas.

Principal Properties

As of January 31, 2011, PTTEP has working interests in 44 exploration and production projects, 20 of whichare in production.

The following table sets out certain information regarding PTTEP’s projects.

Project Location Operator Partners Share (%)

PTTEP’s

Share (%)(1)

Production Phase

ThailandArthit .............................................. Gulf of Thailand PTTEP Chevron Thailand

Exploration and ProductionLimited (16.0) MOECOThailand Co., Ltd (4.0)

80.0

Arthit North.................................... Gulf of Thailand PTTEP — 100.0

B6/27 .............................................. Gulf of Thailand PTTEP Siam Limited(PTTEPS)

JX Nippon Oil & GasExploration Corporation(40.0)

60.0

B8/32 & 9A.................................... Gulf of Thailand Chevron Offshore(Thailand) Limited

Chevron Offshore (Thailand)Limited (51.7) MOECOInternational B.V. (16.7)KrisEnergy (Gulf ofThailand) Ltd. (4.6) PalangSophon Two Limited (2.0%)

25.0

Bongkot .......................................... Gulf of Thailand PTTEP Total E&P Thailand (33.3)BG Asia Pacific Pte Ltd.(22.2)

44.4

Contract 3 (formerly Unocal III)... Gulf of Thailand CTEP Chevron ThailandExploration and ProductionLimited (71.3) Mitsui OilExploration CompanyLimited (23.8)

5.0

Contract 4 (formerly Pailin) .......... Gulf of Thailand CTEP Chevron ThailandExploration and ProductionLimited (35.0) Hess(Thailand) Limited (15.0)MOECO Thai OilDevelopment Co., Ltd. (5.0)

45.0

E5.................................................... NortheastThailand

ExxonMobilExploration andProduction KhoratInc.

ExxonMobil Exploration andProduction Khorat Inc.(80.0)

20.0

71

Project Location Operator Partners Share (%)

PTTEP’s

Share (%)(1)

G4/43 .............................................. Gulf of Thailand Chevron Offshore(Thailand) Limited

Chevron Offshore (Thailand)Limited (51.0) Mitsui OilExploration CompanyLimited (21.3) PalangSophon Limited (6.4)

21.4

G4/48 .............................................. Gulf of Thailand Chevron Pattani Ltd. Chevron Pattani Ltd. (71.3)Mitsui Oil ExplorationCompany Limited (23.8)

5.0

MTJDA-B17................................... Overlapping areabetween Thailandand Malaysia

CARIGALI-PTTEPIOperating CompanySdn. Bhd.

PC JDA Limited (50.0) 50.0

PTTEP 1 ......................................... Suphan Buri andNakhorn Pathomprovinces

PTTEP InternationalLimited (PTTEPI)

— 100.0

S1.................................................... Sukhothai,Phitsanulok andKamphaengpetprovinces

PTTEPS — 100.0(2)

Sinphuhorm .................................... NortheastThailand

Hess (Thailand)Limited.

Hess (Thailand) Limited(35.0) Apico LLC (35.0)ExxonMobil Exploration andProduction Khorat Inc.(10.0)

20.0

OverseasCanada Oil Sands KKD................. Canada Statoil Canada Ltd. Statoil Canada Ltd. (60%) 40.0

Oman 44......................................... Oman PTTEP OmanCompany Limited

— 100.0

PTTEP Australasia (PTTEP AA)

* Detail of operators andpercentage of interest in PTTEPAustralasia project:

Australia PTTEP Australasia — 100.0

1. AC/L1, AC/L2 and AC/L3 ... PTTEP Australasia(Ashmore Cartier)Pty Ltd

Santos Offshore Pty Ltd.(10.3)

89.7

2. AC/L7, AC/L8, AC/P33,AC/P34 and AC/P40..............

PTTEP Australasia(Ashmore Cartier)Pty Ltd

— 100.0

3. AC/P4, AC/P17 ...................... PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cosmo Oil Ashmore (50.0) 50.0

4. AC/P24 ................................... PTTEP Australasia(Ashmore Cartier)Pty Ltd

Nippon Oil (30.0), BengalEnergy Ltd. (10.0)

60.0

72

Project Location Operator Partners Share (%)

PTTEP’s

Share (%)(1)

5. AC/P32 ................................... PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cosmo Energy Co Ltd.(30.0), Bharat PetroResourceLimited (20.0), Bounty Oil& Gas NL (15.0)

35.0

6. WA-378-P, WA-396-P andWA-397-P...............................

Woodside Energy Ltd Woodside Energy Ltd (50.0),Toyota Tsusho E&P BrowsePty Ltd (20.0), Mitsui E&PAustralia Pty Ltd. (10.0)

20.0(3)

7. AC/RL4 (excludingTenacious) and AC/RL5 .......

PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cosmo Energy (50.0) 50.0

8. AC/RL4 (Tenacious) ............. PTTEP Australasia(Ashmore Cartier)Pty Ltd

— 100.0

9. AC/RL6 (excludingAudacious)..............................

PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cosmo Oil Ashmore Ltd.(50.0)

50.0

10. AC/RL6 (Audacious) ............ PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cosmo Oil Ashmore Ltd.(35.0), Cosmo Oil E&P CoLtd (15.0)

50.0

11. AC/RL7 .................................. PTTEP Australasia(Ashmore Cartier)Pty Ltd

Cue (Ashmore Cartier) PtyLtd. (20.0)

80.0

Vietnam 9-2.................................... Vietnam Hoang Long Hoan VuJoint OperatingCompany

Petrovietnam Explorationand Production CorporationLtd (50.0) SOCO VietnamLtd. (25.0)

25.0

Yadana ............................................ Myanmar Total E&P Myanmar Total E&P Myanmar (31.2)Unocal Myanmar Offshore(UMOL) (28.3) MOGE(15.0)

25.5

Yetagun........................................... Myanmar Petronas CarigaliMyanmar (HongKong) Ltd.

Petronas Carigali Myanmar(Hong Kong) Ltd. (40.9)MOGE (20.5) Nippon OilExploration (Myanmar) Ltd.(19.3)

19.3

Development Phase

OverseasAlgeria 433a & 416b ..................... Algeria Groupement Bir Seba

(For development)PetrovietnamExploration andProductionCorporation(PVEP-Algeria) (Forexploration)

Petrovietnam Explorationand Production Corporation(PVEP-Algeria) (40.0)Sonatrach (25.0)

35.0

73

Project Location Operator Partners Share (%)

PTTEP’s

Share (%)(1)

Myanmar Zawtika .......................... Myanmar PTTEPI — 100.0

Vietnam 16-1.................................. Vietnam Hoang Long Hoan VuJoint OperatingCompany

Petrovietnam Explorationand Production CorporationLtd (41.0) SOCO VietnamLimited (28.5) OPECOVietnam Limited (2.0)

28.5

Exploration Phase

ThailandA4, 5 and 6/48 ............................... Andaman Sea PTTEPI — 100.0

G9/43 .............................................. Overlapping areabetween Thailandand Cambodia

PTTEPI — 100.0

L21, 28 and 29/48.......................... Khon Kaen,Chaiyaphum,Udonthani,Nakornratchasrima,Nongbualumphu,Mahasarakhamand Buriramprovinces

PTTEPI Resourceful Petroleum(Thailand) Limited (30.0)

70.0

L22/43 ............................................ Phitsanulok andPichit provinces

PTTEPI — 100.0

L53/43 and L54/43 ........................ Suphan Buri,Ayuthaya,Ang-Thong andKarnchanaburiprovinces

PTTEPI — 100.0

OverseasAlgeria Hassi Bir Rekaiz............... Algeria PTTEP CNOOC International

Limited (24.5) andSonatrach (51.0)

24.5

Australia AC/P36 ........................... Australia Murphy Australia OilPty Ltd

Murphy Australia Oil PtyLtd. (40.0), FinderExploration Pty Ltd (40.0)

20.0

Australia WA-423-P....................... Australia Murphy Australia OilPty Ltd

Murphy Australia Oil PtyLtd (40.0), DiamondResources Australia (30.0)

30.0

Bahrain 2 ........................................ Bahrain PTTEP BahrainLimited

— 100.0

Cambodia B.................................... Cambodia PTTEPI Resourceful PetroleumLimited (33.3) SPCCambodia Limited (33.3)

33.3

74

Project Location Operator Partners Share (%)

PTTEP’s

Share (%)(1)

Indonesia Malunda......................... Indonesia PTTEP MalundarLimited

— 100.0

Indonesia Sadang ........................... Indonesia Talisman Sadang B.V. Talisman Sadang B.V. (60.0) 40.0

Indonesia Semai II ......................... Indonesia Murphy Semai OilCo. Ltd.

Murphy Semai Oil Co. Ltd.(28.3) INPEX Seram SeaLtd. (28.3), PT PertaminaHulu Energi Semai II (15.0)

28.3

Indonesia South Mandar ................ Indonesia PTTEP South MandarLimited

Talisman South Mandar B.V.(33.0)

67.0

Indonesia South Sageri .................. Indonesia Talisman South SageriB.V.

Talisman South Sageri B.V.(70.0)

30.0

Myanmar M3, M4, M7 and M11.. Myanmar PTTEPI 100.0

New Zealand Great South ............. New Zealand OMV New ZealandLimited

OMV New Zealand Limited(36.0) Mitsui E&P AustraliaPty Limited (28.0)

36.0

Rommana........................................ Egypt Sipetrol InternationalSA

Sipetrol International S.A.(40.0) Centrica ResourcesLimited (30.0)

30.0

Sidi Abd El Rahman Offshore ...... Egypt Edison InternationalSPA

Edison International SPA(40.0) Sipetrol InternationalS.A. (30.0)

30.0

Vietnam B & 48/95........................ Vietnam Chevron Vietnam(Block B), Ltd.

Chevron Vietnam (Block B),Ltd. (42.4) MOECOVietnam Petroleum Co., Ltd.(25.6) PetrovietnamExploration and ProductionCorporation (23.5)

8.5

Vietnam 52/97 ................................ Vietnam Chevron Vietnam(Block 52), Ltd.

Chevron Vietnam (Block52), Ltd. (43.4) PetrovietnamExploration and ProductionCorporation (30.0) MOECOSouthwest VietnamPetroleum Co., Ltd. (19.6)

7.0

Source: PTTEP

(1) PTTEP’s share represents its portion of costs and profits.

(2) PTTEP directly owns a 25.0% share of S1 and indirectly owns a 75.0% share of S1 through its wholly-owned subsidiary, PTTEPS.

(3) Purchased from Woodside Energy, although the transfer of shares has not yet been registered.

75

Exploration and Development Activities

PTTEP is involved in both exploration (the search for oil and gas) and development (the drilling andbringing into production of wells in addition to the discovery well in a field). PTTEP’s exploration operationsinclude aerial surveys, geological and geophysical studies (such as seismic surveys), drilling of wildcat wells, coretesting and well logging. Seismic surveys involve recording and measuring the rate of transmission of shock wavesthrough the earth with a seismograph. Upon striking rock formations, the waves are reflected back to theseismograph. The time lapse is a measure of the depth of the formation. The rate at which waves are transmittedvaries with the medium through which they pass. Seismic surveys may either be three-dimensional ortwo-dimensional surveys, the former type generally giving a better detail picture and the latter a better overallpicture.

Analysis of the data produced allows PTTEP to formulate a picture of the underground strata to enable itto form a view as to whether there are any “leads” or “prospects.” “Leads” are preliminary interpretation ofgeological and geophysical information that may or may not lead to prospects and “prospects” are geologicalstructures conducive to the production of oil and gas. The actual existence of such oil and gas must be confirmed,usually by the drilling of a wildcat well. If the wildcat well confirms the prospect (that is, is considered“successful”), PTTEP may then drill a delineation (or appraisal) well to acquire more detailed data on the reservoirformation. Once the presence of hydrocarbons is proved to be in commercially recoverable quantities, or thedelineation well is “successful,” development wells may be drilled to prepare for production. An area is consideredto be developed when it has a well on it capable of producing oil or gas in paying quantities.

The following table sets forth the total concession areas at December 31, 2010 in each of PTTEP’spetroleum properties.

Project PTTEP % share Concession Area

(square km)

Thailand:A4, 5 and 6/48 ........................................................................................................ 100.0 68,820Arthit........................................................................................................................ 80.0 3,682Arthit North (1) ....................................................................................................... 100.0 —B6/27 ....................................................................................................................... 60.0 1,302B8/32 & 9A............................................................................................................. 25.0 2,541Bongkot ................................................................................................................... 44.4 3,522Contract 3 ................................................................................................................ 5.0 2,738Contract 4 ................................................................................................................ 45.0 3,117E5............................................................................................................................. 20.0 34G4/43 ....................................................................................................................... 21.4 2,575G4/48 ....................................................................................................................... 5.0 504G9/43 ....................................................................................................................... 100.0 2,619L21, 28 and 29/48................................................................................................... 70.0 11,803L 22/43 .................................................................................................................... 100.0 859L53/43 and L54/43.................................................................................................. 100.0 1,983MTJDA-B17 (2) ....................................................................................................... 50.0 4,700PTTEP 1 .................................................................................................................. 100.0 9S1............................................................................................................................. 100.0 1,326Sinphuhorm ............................................................................................................. 20.0 232Myanmar:Yadana ..................................................................................................................... 25.5 26,140Yetagun .................................................................................................................... 19.3 24,130Myanmar Zawtika ................................................................................................... 100.0 12,306Myanmar M3, M4, M7 and M11 ........................................................................... 100.0 38,171Australia:PTTEP Australasia .................................................................................................. 100.0 20,637

(1) For Arthit North, the concession area was included in the Arthit area, as they both form part of the same concession, which PTTEPacquired from the DMF.

(2) Occupies the overlapping area between Thailand and Malaysia.

76

Project PTTEP % share Concession Area

(square km)

Other Foreign Countries:Oman 44 .................................................................................................................. 100.0 1,162Vietnam 9-2............................................................................................................. 25.0 1,093Algeria 433a & 416b .............................................................................................. 35.0 437Vietnam 16-1........................................................................................................... 28.5 2,034Algeria Hassi Bir Rekaiz ........................................................................................ 24.5 5,378Australia AC/P36 .................................................................................................... 20.0 4,064Australia WA-423-P ................................................................................................ 30.0 5,769Bahrain 2 ................................................................................................................. 100.0 2,228Cambodia B............................................................................................................. 33.3 6,515Indonesia Malunda .................................................................................................. 100.0 5,107Indonesia Sadang .................................................................................................... 40.0 3,700Indonesia Semai II .................................................................................................. 28.3 3,379Indonesia South Mandar ......................................................................................... 67.0 3,882Indonesia South Sageri ........................................................................................... 30.0 3,889New Zealand Great South ...................................................................................... 36.0 48,733Rommana................................................................................................................. 30.0 6,148Sidi Abd El Rahman Offshore................................................................................ 30.0 4,294Vietnam B & 48/95................................................................................................. 8.5 4,215Vietnam 52/97 ......................................................................................................... 7.0 1,435

Total ......................................................................................................................... 347,212

77

Drilling Activity

The following table sets forth the numbers of successful exploratory wells and exploratory wells abandonedas dry holes with respect to each of the concessions in which PTTEP participated as of December 31, 2008, 2009and 2010, including partner operated joint ventures. Successful offshore wells consist of exploratory ordevelopment wells that have been completed or are “suspended” pending completion (but which have beendetermined to be feasible and economic) and exploratory test wells that were not intended to be completed butwere proven to contain commercially producible hydrocarbons. A well is considered a dry hole upon reporting ofabandonment to the appropriate government agency.

Drilling Activity

2008 2009 2010

Explorationand Appraisal Development

Explorationand Appraisal Development

Explorationand Appraisal Development

Project Successful Dry Successful Dry Successful Dry Successful Dry Successful Dry Successful Dry

S1 ........................................... 1 1 33 1 1 56 3 37

B8/32&B9A ........................... 2 71 48 1 62 1

Contract 4 .............................. 7 39 5 30 33

Contract 3 .............................. 85 2 62 1 61

Bongkot.................................. 3 25 4 15 3 31

Arthit ...................................... 4 13 6 43 3 1 55

Arthit North ........................... 32

Sinphuhorm ..........................

G4/43...................................... 29 1 5 1

G4/48...................................... 20 1

L53/43 & L54/43................... 1 1

MTJDA-B17 .......................... 3 12 1 31 35

PTTEP1.................................. 3 1

Yetagun .................................. 1 4

Myanmar Zawtika.................. 3 1 2 1

Myanmar M3, M4, M7and M11 ........................... 2

Algeria 433a and 416b .......... 1 1

Indonesia

Merangin-1 ......................

Indonesia

Bengara I ........................ 1

Vietnam 9-2 ........................... 2 2 1

Vietnam 16-1 ......................... 2 1

Vietnam B and 48/95 ............ 1 2

Vietnam 52/97........................ 1

Sidi Abd El Rahman.............. 1 1

Australasia ............................

Australia AC/P36................... 1

PTTEP Australasia................. 1 1 4 2 6

Iran Saveh(1) .......................... 1

Cambodia B ........................... 1 1

Oman 58 ................................ 1

Oman 44 ................................ 1 1 2 2

Total....................................... 28 13 348 0 21 8 302 1 13 4 341 3

(1) PTTEP has discontinued all operations in Iran and currently has no intention of engaging in operations in Iran.

In 2010, PTTEP discovered petroleum in 13 out of a total of 17 exploration and appraisal wells drilled. In2008 and 2009, PTTEP discovered petroleum in 28 of 41 wells and 21 out of 29 wells, respectively.

Joint Venture Agreements

PTTEP holds the majority of its exploration and production interests through joint ventures withinternational oil and gas companies. Each joint venture participant holds an undivided interest in the concession

78

area described in the concession, and in all rights and obligations of the concessionaire. The operator has fullcontrol under the overall supervision and control of a joint operating committee of all petroleum-relatedoperations, including exploration, appraisal, development and production, storage and transportation and isrequired to report regularly to the other joint venture participants. The operator’s activities are generally fundedeither by monthly cash calls based on amounts agreed to in the annual budget prepared by the operator andapproved by a specified percentage of joint venture participants or as a certain percentage of available petroleumproduced in connection with a project. The operator generally can be removed for gross negligence or misconductand may resign with notice under certain circumstances.

Joint venture participants holding a specified percentage interest in a concession have the right of controlover operations, which the parties can exercise through the operating committee of the joint venture. In addition,the joint venture participants holding such specified percentage interests have the right to approve developmentand exploration programs, production levels, annual budgets and amendments and adjustments to such budgets,contracts for goods, services or capital expenditures in excess of specified amounts. Under the terms of its jointventure agreements, and given its percentage working interest in each concession, PTTEP effectively has a vetowith respect to all such decisions to be made by the joint venture for generally all of its projects. Representativesof each joint venture participant may review joint venture accounts and records and periodic reports before theyare sent to the relevant government agencies. Regular meetings are held to coordinate and review information andplans. Each joint venture participant is only permitted to engage in exploration work after consultation with theother joint venture partners. If these partners decline and the participant engages in such exploration work alone,it accepts all risks of venturing individually.

Liability arising in respect of operations not otherwise insured is generally borne by each participant inaccordance with their respective interest in the concession. The joint venture agreements generally provide thatthe operator will acquire insurance on behalf of the participants, unless such participants choose to acquireinsurance individually, or self-insure their risks.

PTTEP’s joint venture agreements generally terminate on the earlier of an agreement by the parties toterminate the joint venture and the termination of the underlying concession or production sharing contracts. Inaddition, the ability of the participants (including the operator) to transfer or assign their rights under theagreement or otherwise withdraw from the joint venture is generally subject to pre-emptive or first refusal rightsin favor of the remaining joint venture partners.

Production Sharing Contracts

PTTEPI operates the Yadana and Yetagun projects with a joint venture partner which has agreed to mutuallydevelop both projects under production sharing contracts. Under the production sharing contracts, 10% of the salesrevenue generated during the production period is paid back to the Myanmar Government as a royalty. In addition,a bonus is awarded if production surpasses certain levels. Nevertheless, the production sharing contracts providesthat the proportion of PTTEP’s interest in the offtake will decrease incrementally as production levels increase.(See “— Properties Under Production — Yadana” and “— Yetagun.”)

Similarly, in connection with the development of the MTJDA-B17 project, PTTEPI and its joint venturepartner have invested equally in the project. Likewise, 10.0% of sales revenue is paid as a royalty to the MTJAand production bonuses are paid for meeting certain production targets.

Principal Properties Under Production

Thailand

Arthit

In 1998, PTTEP acquired a concession from the Government to explore and develop Block 14, 15 and 16and Areas 14A, 15A and 16A in the joint area overlapping the border of Thailand and Vietnam in the Gulf ofThailand adjacent to the eastern end of the Bongkot concession area. PTTEP’s current interest in the Arthit projectis 80.0%. Chevron Thailand Exploration and Production Limited (CTEP) owns a 16.0% interest and MOECOThailand Co., Ltd. owns a 4.0% interest.

The first phase of exploration consisted of seven exploration wells in 1998 through 2000. The second phaseof exploration resulted in the drilling of 14 exploratory-appraisal wells in 2001 and 2002. The Arthit projectconducted post-well and prospect re-evaluated studies based on the exploration and appraisal results andconfirmed the Arthit commercial discovery. During the third phase of exploration, eight wells were drilled to

79

support development planning. The first phase of development at the Arthit project began in January 2004 andconsisted of a central processing platform, a living quarters platform, six wellhead platforms, five sub-sea gas linesand a condensate line. Arthit production started in March 2008 and produces gas at a rate of 330 MMSCFD andcondensate at a rate of 16,000 Bbls/d. Further development has been implemented to stabilize gas delivery incompliance with the GSA between the Arthit joint venture partners and PTT.

Sales volume averaged 318 MMSCFD of natural gas and 15,324 Bbls/d of condensate in 2010 and 329MMSCFD of natural gas and 16,797 Bbls/d of condensate in 2009, respectively.

Arthit North

In December 2006, the Arthit North project was developed, which is wholly owned and operated by PTTEP.The Arthit North Project is located in the Gulf of Thailand, approximately 230 kilometers off the coast of Songkhlaprovince, adjacent to the Bongkot concession area. Arthit North commenced operations in May 2009 andcontinues to produce gas at 120 MMSCFD and condensate 2,500-4,000 Bbls/d. Sales volume averaged 108MMSCFD of natural gas and 2,844 Bbls/d of condensate in 2010 and 41 MMSCFD of natural gas and nocondensate sales in 2009.

B6/27

The B6/27 project is located in the Gulf of Thailand, approximately 25 kilometers offshore from theChumphon province, covering an area of 1,302 square kilometers. In January 2004, PTTEP became the sole holderand operator of this concession. In 2009, PTTEP farmed-out a 40% interest in the project to JX Nippon Oil & GasExploration Corporation. Currently, PTTEP holds a 60% interest in the concession.

From 2005 to 2007, the Nang Nuan field, which had two production wells, produced an average ofapproximately 1,400 Bbls/day. After 2007, however, PTTEP stopped crude oil production due to a decline in theproduction rate. In 2009, PTTEP re-initialized exploration studies which include and new three-dimensionalseismic data acquisition and re-processing existing data. Most of the exploration studies have been completed andPTTEP plans to begin exploratory drilling in the first half of 2012.

B8/32 & 9A

In August 2005, PTTEP indirectly acquired an interest in the B8/32 & 9A project. PTTEP’s current interestin the B8/32 & 9A project is 25.0%. PTTEP’s joint venture partners in this project are Chevron Offshore(Thailand) Limited, MOECO International B.V. KrisEnergy (Gulf of Thailand) Ltd, and Palang Sophon Limited.The B8/32 & 9A project is located in the Gulf of Thailand off the Chumporn coast, covering an area of 2,541square kilometers. Chevron is the operator of the project. Sales volume averaged 171 MMSCFD of natural gas and40,240 Bbls/d of crude oil in 2010 and 174 MMSCFD of natural gas and 45,290 Bbls/d of crude oil in 2009.

Bongkot

The Bongkot field is the largest field in the Gulf of Thailand and has been in production since 1993. It islocated in the southern Gulf of Thailand (Blocks B15, B16, B17 and G12/48), 203 kilometers off of the coast ofSongkhla province. The field accounts for the largest portion of PTTEP’s natural gas and condensate reserves.PTTEP holds a 44.4% interest in the project and took over as operator of the project from Total E&P in 1998. Allof the natural gas and condensate produced at Bongkot is sold to PTT based on a long-term agreement. Theownership of the natural gas from the Bongkot project is transferred to PTT at the wellhead and transportedonshore through PTT pipeline system. The ownership of the condensate is transferred at the floating storage andoffloading unit near the production well area.

The Bongkot field’s third phase of development is underway, with the goal of maintaining a dailycontractual quantity of 550 MMSCFD. The fourth phase of development is being carried out to produce additionalnatural gas at Bongkot South. Bongkot South is expected to begin production in 2012.

In 2009, PTTEP and its joint venture partners officially signed a GSA with PTT for the natural gas producedat Bongkot South, with a daily contractual quantity of 320 MMSCFD of natural gas. The production start-upperiod is expected to be between June 1, 2012 and November 30, 2012. The signing of the GSA will raise the totaldaily contractual quantity of the Bongkot project to 870 MMSCFD.

Sales volume averaged 586 MMSCFD of natural gas and 19,779 Bbls/d of condensate in 2010 and 516MMSCFD of natural gas and 18,217 Bbls/d of condensate in 2009.

80

Contract 3

In July 1990, PTTEP acquired an interest in the Contract 3 project. PTTEP’s current interest in the Contract3 project is 5.0%. The operator is CTEP and MOECO is the other joint venture partner. The Contract 3 projectis located north of the Bongkot project in the Gulf of Thailand, off the coast of Surat Thani, covering an area of2,738 square kilometers. All of the natural gas and condensate produced at Contract 3 is sold to PTT on atake-or-pay basis pursuant to long-term agreements. Natural gas is transported to the Erawan platform fortransmission into PTT’s 418 kilometer pipeline to Map Ta Phut, Rayong province.

In 2010, one new exploratory well and 61 development wells were drilled and three additional wellheadplatforms were installed.

Sales volume averaged 416 MMSCFD of natural gas, 29,679 Bbls/d of crude oil and 9,558 Bbls/d ofcondensate in 2010 and 329 MMSCFD of natural gas and 24,715 Bbls/d of crude oil and 7,007 Bbls/d ofcondensate in 2009.

Contract 4

In July 1993, PTTEP acquired an interest in the Contract 4 project (Block B12/27). PTTEP’s current interestin the Contract 4 project is 45.0%. The Contract 4 project is located northwest of Bongkot in the Gulf of Thailandoff the coast of Songkhla province, covering an area of 3,117 square kilometers. All of the natural gas producedat Contract 4 is sold to PTT on a take-or-pay basis pursuant to a long-term agreement. The natural gas andcondensate produced at Contract 4 is transported by pipeline to PTT’s Erawan platform, and the natural gas is thendelivered by PTTEP to Map Ta Phut in Rayong province.

The Contract 4 project was expanded in July 2002 to provide 330 MMSCFD of gross production capacity.On October 10, 2003, the Contract 4 project joint development partners amended the gas sales agreement forContract 4 to reduce the gas price by 3.0% effective October 1, 2003. In return for this price reduction, PTT agreedto increase the volume of gas it purchased from Contract 4 from 330 to 353 MMSCFD. The price discount willincrease to 5.0% beginning from the date of completion of the project’s gas pipeline master plan until theexpiration of the gas sales agreement. In return for this further reduction, PTT agreed to increase the volume ofgas it purchased from 353 to 368 MMSCFD. In 2010, 33 development wells were drill and two additionalwellhead platforms were installed.

Sales volume averaged 362 MMSCFD of natural gas and 15,673 Bbls/d of hydrocarbons (condensate) in2010 and 364 MMSCFD of natural gas and 15,465 Bbls/d of hydrocarbons (condensate) in 2009.

E5

In April 1990, PTTEP acquired an interest in the E5 project from Esso Exploration and Production KhoratInc., the project operator. PTTEP’s current interest in the E5 project is 20.0%. Production commenced inDecember 1990. The E5 project is located onshore at Namphong, Khon Kaen province. All of the natural gasproduced at the E5 project is sold to PTT on a take-or-pay basis pursuant to a long-term agreement. PTT thentransports the gas to an EGAT power plant through a 3.5 kilometer transmission pipeline operated by PTT. Salesvolume at the E5 project averaged 18 MMSCFD of natural gas in 2010 and 19 MMSCFD of natural gas in 2009.

G4/43

In July 2003, PTTEP indirectly acquired an interest in the G4/43 project. PTTEP’s current interest in theG4/43 project is 21.4%. Its joint venture partners are Chevron, MOECO and PSL. The G4/43 project is locatedin Gulf of Thailand, covering an area of 2,575 square kilometers. In the second quarter of 2010, six explorationswells were drilled at the G4/43 project. Sales volume averaged 3 MMSCFD of natural gas and 7,910 Bbls/d ofcrude oil in 2010 and 2 MMSCFD of natural gas and 7,991 Bbls/d of crude oil in 2009.

81

G4/48

In July 2009, PTTEP indirectly acquired an interest in the G4/48 project. PTTEP’s current interest in theG4/48 project is 5.0%. Chevron Pattani Limited (operator) and Mitsui Oil Exploration Company Limited haveinterests of 71.3% and 23.8% in the project, respectively. The G4/48 project is located in the Gulf of Thailandoffshore from Surat Thani province, covering an area of 504 square kilometers. The G4/48 project’s proximity toexisting Contract 3 facilities will improve the economies of scale of both projects. In 2010, 21 development wellswere drilled at the G4/48 project. Sales volume averaged 4 MMSCFD of natural gas and 1,594 Bbls/d of crudeoil in 2010 and 1 MMSCFD of natural gas and 129 Bbls/d of crude oil in 2009.

MTJDA-B17

In April 1994, PTTEP’s wholly-owned subsidiary, PTTEPI, formed a joint operating agreement withCarigali, a wholly-owned subsidiary of PETRONAS, the Malaysian state oil company, named Carigali-PTTEPIOperating Company Sdn. Bhd., to explore and develop Blocks B-17 and C-19. PTTEPI and Carigali each ownsa 50.0% interest in a special purpose company that acts as operator of Blocks B-17 and C-19, and each of themhas the obligation to bear 50.0% of the related costs and expenses. Under the joint operating agreement, a royaltyequal to 10.0% of production is payable to the MTJA. On September 24, 2004, Carigali assigned all of its interestsunder the JOA to PC JDA Ltd. and on September 30, 2004, PTTEPI and PC JDA Ltd. (as “contractors”) and theMTJA signed a production sharing contract for the right to explore and produce petroleum in Block B-17-01, withthe contractors and MTJA sharing any potential production.

In June 2005, the joint venture partners executed a gas sales agreement for the sale of the natural gas to beproduced from the MTJDA-B17 project to PTT. The agreement covers blocks B-17 & C-19 and B-17-01 of theMTJDA-B17. The MTJDA-B-17 project began first commercial production in February 2010. The currentdelivery of natural gas to PTT has now met the gas quality and quantity specified in the gas sales agreement atapproximately 335 MMSCFD. The current production rate of condensate is approximately 10,000 Bbls/d.

Under the MTJDA-B17 gas sales agreement, if the seller fails to deliver on the contractual delivery date,the buyer is entitled to take a deficient quantity, or shortfall, at a price equal to 75% of the current price applicableat the time the shortfall occurred. PTTEP, therefore, may have an obligation for the shortfall by selling thedeficient amount of gas at discounted prices to PTT as per the gas sales agreement.

In 2010, 35 development wells were drilled and an additional wellhead platform was installed. Sales volumeaveraged 230 MMSCFD of natural gas and 7,337 Bbls/d of condensate in 2010.

PTTEP 1

In July 1993, PTTEP indirectly acquired an interest in the PTTEP 1 project, which had been producing crudeoil since 1991, from BP Exploration Operating (Thailand) Co., Ltd. PTTEPI is the sole owner and operator of thePTTEP 1 project. The PTTEP 1 project is located in central Thailand in the Suphan Buri and Nakhon Pathomprovinces, covering an area of 9 square kilometers. Crude oil produced from PTTEP 1 is transported 140kilometers via roadway to the Bangchak refinery. Crude oil is sold to PTT at the Bangchak refinery. PTTEP alsohas planned development wells at the PTTEP 1 project which will focus on partially offsetting field declines andenhancing oil recovery.

In 2010, PTTEP drilled one well and conducted a water-flood study on the site. Sales volume averaged 469Bbls/d of crude oil in 2010 and 440 Bbls/d of crude oil in 2009.

S1

In October 1985, PTTEP acquired a 25.0% interest in the S1 project from Thai Shell. On December 30,2003, PTTEP executed a share purchase agreement to buy all the outstanding shares of Thai Shell, the name ofwhich has been changed to PTTEP Siam Limited, resulting in PTTEP and its subsidiaries becoming the operatorand sole owner of the S1 project as of January 1, 2004. The S1 project is an onshore asset located in the Sirikitfield in Kamphaengphet province in north-central Thailand, covering an area of 1,326 square kilometers. Naturalgas produced at the S1 project is sold directly to EGAT to fuel an adjacent power plant, while crude oil producedat S1 is sold to PTT. LPG is also processed at a plant located at the S1 project and is sold to PTT.

In 2010, PTTEP drilled three exploration wells, 37 development wells and 45 work-over wells at the site.In addition, PTTEP completed three-dimensional seismic acquisition and processed 135 square kilometers ofseismic data. PTTEP continued a waterflood project onsite to maximize production volumes.

82

Sales volume averaged 13 MMSCFD of natural gas, 21,709 Bbls/d of crude oil and 199 tonnes per day ofLPG in 2010 and 13 MMSCFD of natural gas, 21,084 Bbls/d of crude oil and 198 tonnes per day of LPG in 2009.

Sinphuhorm

In July 1993, PTTEP and its subsidiary, PTTEP Siam, acquired a 20% interest in the Sinphuhorm project.PTTEP’s joint venture partners are Hess (Thailand) Ltd (the operator), Apico LLC and ExxonMobil Explorationand Production Khorat Inc. Production commenced in November 2006. The Sinphuhorm project is located inUdon Thani and Khon Kaen provinces in the northeast of Thailand, covering an area of 232 square kilometers.Sales volume averaged 86 MMSCFD of natural gas and 434 Bbls/d of condensate in 2010 and 85 MMSCFD ofnatural gas and 447 Bbls/d of condensate in 2009.

Overseas

PTTEP Australasia (“PTTEP AA”)

On February 4, 2009, PTTEP indirectly acquired 100.0% of the ordinary shares of Coogee ResourcesLimited. PTTEP later changed the name of the company to PTTEP Australasia Pty Ltd, or PTTEP AA. PTTEPAA is an oil and gas company with production, development and exploration assets located in the Timor Sea. Allprojects are located on the Australian continental shelf. PTTEP is currently negotiating a sales agreement with PTTfor partial supply of oil output from the Montara project to Thailand.

Montara Project

PTTEP is in the process of engineering design and preparing for the removal and replacement of thedamaged wellhead platform in the Montara field. PTTEP expects Montara field production to commence in late2011. Initial production is expected to be 35,000 Bbls/d. The Company is developing the Montara Project via aFPSO and wellhead platform to be located at the Montara field. The platform will be connected via subseapipelines called tiebacks to other nearby fields.

The Montara Project will utilize a Suezmax size FPSO facility with approximately 750,000 Bbls of storageand a mooring system consisting of a turret, anchor chains/wire and anchors/anchor piles designed for the siteconditions at Montara. Offloading facilities will consist of a standard tanker loading arrangement.

In August 2009, an oil and gas leak began during the Montara H1’s development well drilling, whichcontinued until PTTEP AA stopped the leak in November 2009. The causes of the uncontrolled oil and gas releaseinclude deficiencies in the Montara H1 well cementing operation and well barrier testing and the failure to installall required pressure containing corrosion caps. In addition, other causative factors in the uncontrolled oil and gasrelease may have included inadequate supervision and monitoring of operations and personnel and deficiencies inwell management documentation and systems. During operations to stop the leak, PTTEP AA’s wellhead platformand the contractor-operated West Atlas drilling rig caught fire, causing substantial damage to both the wellheadplatform and the West Atlas rig. This affected the production start up. In order to maintain control of the well andfix damaged production facilities, PTTEP AA temporarily suspended the development of the Montara H1 well.The West Atlas rig has been removed from the Montara field. PTTEP AA has contracted to remove and replacethe damaged topside of the wellhead platform. Operations are expected to recommence in mid-2011 as a newexpert project team is now in place and fully involved in the management of the project and the implementationof the Action Plan.

The costs of environmental cleanup, well control and asset damage are insured events As of December 31,2010, PTTEP preliminarily estimated the maximum amount to be recovered under the insurance policies to beapproximately Baht 6,700 million (U.S.$222 million). Of which, Baht 1,341 million was recognized in the fourthquarter of 2009 and Baht 1,369 million was recognized in the third quarter of 2010. However, the actual amountultimately recoverable under the insurance policies is dependent upon costs actually incurred and the terms andconditions of the policies. PTTEP is now in the claims process with the insurers for the remaining recoverableamounts. PTTEP expects the remaining funds in respect of the remaining receivable amounts to be received in2011. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — FactorsAffecting Results of Operations — The Montara Incident,” “Business — Principal Properties — PrincipalProperties Under Production — Overseas — PTTEP Australasia” and “Risk Factors — Risks Relating to PTTEP’sBusiness — The exploration, development and production risks of oil and natural gas operations may adverselyaffect PTTEP’s profitability and may not be fully protected by insurance.”

83

The government of Australia convened a Commission of Inquiry to investigate several matters, including,among others, the likely causes of the incident and the resulting environmental impacts. On November 24, 2010,the Australian Minister for Resources, Energy and Tourism released the fact finding report. The Commissionfound that the blowout occurred because the primary well control barrier failed to stop a surge of oil and gas inthe well due to defects in the installation of the primary control barrier. Furthermore, the secondary control barrierswere not in place at the time of the surge. The Commission identified material deficiencies in the proceduresfollowed by PTTEP AA employees in connection with the Montara Incident and was critical of the generalmanagement of the operations as well as specific actions taken and not taken by PTTEP AA and PTTEP leadingup to and following the spill, including the mechanics and management of the drilling operations as well as thesubsequent spill containment efforts. Following the release of the Commission’s Report, the Minister forResources, Energy and Tourism began a review of PTTEP AA’s petroleum licenses and the Action Plan. OnFebruary 4, 2011, the Minister announced that the Action Plan satisfactorily addressed the issues raised by theCommission and that no further review would be required if PTTEP and PTTEP abided by the Action Plan asmonitored by independent industry experts. On February 21, 2011, 2011, PTTEP, PTTEP AA and the Governmentof Australia entered into a deed of agreement to memorialize the Action Plan and 18 month monitoring period.The Government of Australia has also informed PTTEP AA that new licenses or renewals of existing licenses willbe subject to further conditions relating to technical competency, corporate governance and reporting requirementswith respect to PTTEP AA’s offshore operations. These conditions are also likely to be applied to the Montaralicences by way of a direction under the OPGGS Act. PTTEP AA is currently discussing the details of theseconditions with the Government of Australia. See “Risk Factors — Risks Relating to PTTEP’s Business — PTTEPis subject to claims and liabilities in relation to the Montara Incident” and “— PTTEP AA and PTTEP may facematerial adverse consequences as a result of ongoing and future investigations into the Montara Incidentconducted by various Australian governmental agencies.”

Other Projects

PTTEP AA’s portfolio of other exploration projects is primarily located in the Vulcan sub-basin of the TimorSea. These projects include AC/P32, AC/P40, AC/P33, AC/P34, AC/P17, AC/P24 and AC/P4, in which it hasinterests ranging from 35.0% to 100.0%. In 2010, PTTEP AA has begun reprocessing efforts at these projects inorder to confirm their recoverable potential. PTTEP AA plans to begin drilling at several of these projects overthe course of the next three years. PTTEP AA also operates AC/RL 6 and AC/RL4&5 in the Vulcan sub-basin.These projects contain the small Audacious and Tenacious oil deposits. Engineering studies are currently beingconducted to assess development options for these fields. Planning has begun for FLNG production at the Cashand Maple fields and the Oliver and Montara stranded gas fields. Appraisal wells are also being planned for theCash and Maple fields.

PTTEP AA also has a number of interests in the Browse Basin. These interests include a 20.0% interest inthe Woodside projects of WA-378-P, WA-396-P and WA-397-P. The first exploration well at these projects isscheduled for 2011 at WA-397-P.

Sales volume averaged 2,307 Bbls/d of crude oil in 2010 and 2,444 Bbls/d of crude oil in 2009, whichrepresents PTTEP’s share of the production from the Jabiru and Challis fields, both of which were shut down inSeptember 2010 due to declining production volumes.

Oman 44

In November 2006, PTTEP indirectly acquired the rights to the Oman 44 project, which it wholly owns andoperates. The Oman 44 project is located onshore, 300 kilometers to the west of Muscat, the Sultanate of Oman.Sales volume averaged 47 MMSCFD of natural gas and 1,960 Bbls/d of condensate in 2010 and 46 MMSCFDof natural gas and 2,470 Bbls/d of condensate in 2009.

Vietnam 9-2

In February 2002, PTTEP indirectly acquired an interest in the concession. PTTEP’s current interest in theVietnam 9-2 project is 25.0%. PetroVietnam Exploration and Production Corporation Ltd. and SOCO VietnamLtd. are its joint venture partners. The Petroleum Concession Block Vietnam 9-2 is located offshore to thesoutheast of Vung Tau City, Vietnam. The project became fully operational in 2009. The crude oil produced is soldin spot markets and pursuant to short-term contracts. The gas produced is sold to Vietnam Oil and Gas Group, aVietnamese state enterprise, for domestic consumption. Sales volume averaged 16 MMSCFD of natural gas and6,072 Bbls/d of crude oil in 2010 and 20 MMSCFD of natural gas and 6,735 Bbls/d of crude oil in 2009.

84

Yadana

In 1995, PTTEP’s wholly-owned subsidiary, PTTEPI, acquired a 25.5% working interest in the productionsharing contract for Yadana, a large gas project operated by Total Myanmar Exploration and Production (“TotalMyanmar”) under the M-5 and M-6 Blocks in the Gulf of Matabon, Myanmar. PTTEPI’s attributable interest inthe Yadana project is 25.5%. However, PTTEP’s share of revenues from the Yadana project takes into account thepayment of royalties and certain discounts required under the production sharing contract between the jointventure partners and Myanmar Oil and Gas Enterprise (“MOGE”).

PTTEPI and its joint venture partners sell the natural gas produced from the Yadana project to PTT on atake-or-pay basis pursuant to a 30-year GSA, which means that PTT agrees to pay for the natural gas even if itdoes not take delivery. The Yadana joint venture partners are required to deliver a daily contractual quantity of 565MMSCFD of natural gas to PTT for the first 19 years of the contract, or until there is a reassessment of naturalgas reserves.

Pursuant to the terms of the production sharing contract, the joint venture partners are entitled to allocateup to 50.0% of total natural gas production at the Yadana project to the recovery of their exploration, developmentand production costs. The remaining natural gas production is allocated among the joint venture partners andMOGE. The joint venture partners are required to pay a royalty of 10.0% of the value of this remaining naturalgas production to the government of Myanmar, as well as certain bonus payments due upon the attainment ofcertain specified production thresholds.

The allocation of natural gas production among the joint venture partners and MOGE (after the allocationfor cost recovery) is reduced incrementally as daily production volumes increase. For example, at daily natural gasproduction volumes between 301 MMSCFD and 600 MMSCFD, the joint venture partners’ allocation ranges from30.0% to 45.0%. At daily natural gas production volumes above 900 MMSCFD, the joint venture partners’allocation is reduced to 10%. The government of Myanmar also purchases up to 125 MMSCFD of natural gas,plus an additional 20 MMSCFD of natural gas from Wellhead no.3, for domestic use in Myanmar under a domesticGSA.

Similar incremental reductions in the allocation among the joint venture partners and MOGE apply toincreased production of crude oil until the joint venture partners’ allocation is reduced to 15.0% at daily productionlevels above 200,000 Bbls/d. In addition, under the terms of the production sharing contract, up to 20.0% of thenatural gas allocated to the joint venture partners must be made available to MOGE at a price that does not exceed10.0% of the fair market value in order to fulfill Myanmar’s domestic natural gas requirements.

To transport natural gas from Yadana to Thailand, PTTEP Offshore Investment Limited (a wholly ownedsubsidiary of PTTEP) and its joint venture partners, Total Myanmar, Unocal Myanmar Offshore Co., Ltd. andMOGE, established a gas transportation company, Moattama Gas Transportation Co., Ltd., to construct andoperate an onshore pipeline section of approximately 63 kilometers and an offshore pipeline section ofapproximately 346 kilometers from the Yadana development area to the Thai border. The pipeline’s capacity isapproximately 835 MMSCFD. The construction of these onshore and offshore pipelines was completed in Mayand November 1997, respectively. In 2000, PTT completed an approximately 260 kilometer section of onshorepipeline from the Thai border to the EGAT electric power generating plant in Ratchaburi, near Bangkok.

Sales volume of natural gas averaged 732 MMSCFD in 2010 and 643 MMSCFD in 2009.

Yetagun

In March 1997, PTTEP’s wholly-owned subsidiary, PTTEPI, acquired a 14.2% interest in Blocks M-12,M-13 and M-14 of the Yetagun project. On September 30, 2003, PTTEPI increased its interest in the Yetagunproject to 19.3% by exercising its right of first refusal, together with the other joint venture partners, to purchasethe remaining shares of Premier Petroleum Myanmar Limited, the former operator of the project. Petronas CarigaliMyanmar (Hong Kong) Ltd. is the current operator of the Yetagun project. PTTEPI and its joint venture partnerssell natural gas from Yetagun to PTT on a take-or-pay basis pursuant to a 30-year agreement. The project is locatedin the Gulf of Mataban, southeast of Yadana and began operations in May 2000.

Following cost recovery, the remaining natural gas and condensate production is allocated among the jointventure partners (40.0%) and MOGE (60.0%). The joint venture partners are required to pay the government ofMyanmar a royalty equal to 10% of the value of this remaining natural gas and condensate production, as wellas certain bonus payments due upon the attainment of certain specified production thresholds.

85

To transport natural gas from Yetagun to Thailand, PTTEPI and its joint venture partners established a gastransportation company, Taninthayi Pipeline Company LLC, to construct and operate an offshore pipeline of 210kilometers and an onshore pipeline of 67 kilometers (parallel to the Yadana pipeline) from the project to the Thaiborder. The pipeline capacity is approximately 600 MMSCFD of compressed natural gas. The construction of theonshore and offshore pipelines was completed in 1999.

Sales volume averaged 416 MMSCFD of natural gas and 11,129 Bbls/d of crude oil in 2010 and 389MMSCFD of natural gas and 9,975 Bbls/d of crude oil in 2009.

Principal Properties Under Development

Algeria 433a & 416b

PTTEP owns a 35.0% interest in the Algeria 433a & 416b project. Its joint development partners arePetrovietnam Exploration and Production Corporation (Algeria) and the Société Nationale pour la Recherche, laProduction, le Transport, la Transformation, et la Commercialisation des Hydrocarbures s.p.a. (“Sonatrach”). Theproject is located in the southeast part of Algiers. Engineering designs for the Bir Saba Oil Field are currentlybeing drafted. Oil production is scheduled to begin in 2013.

Myanmar Zawtika

PTTEP is the sole owner and operator of the Myanmar Zawtika project. The Myanmar Zawtika project islocated in the Gulf of Martaban, Union of Myanmar. A development planning study and procurement of long leaditems, which are categorized as items that are difficult to source and/or will take greater than one year to acquire,were completed for this project in 2009. On July 30, 2010, PTTEP entered into a 30-year GSA with MOGE.Production at the project is planned to begin in 2013.

Vietnam 16-1

PTTEP owns a 28.5% interest in the Vietnam 16-1 project, in partnership with SOCO Vietnam Ltd.,Petrovietnam Exploration and Production and OPECO Vietnam Ltd. The Vietnam 16-1 project is located offshoreto the southeast of Vung Tau City, Vietnam. The front-end engineering design for this project was completed in2009. The construction of the wellhead platform is currently in progress and production is scheduled to begin in2011.

Principal Properties Under Exploration

Thailand

A4, 5 and 6/48

PTTEP indirectly owns and operates 100.0% of the A4, 5 and 6/48 projects. The A4, 5 and 6/48 projects arelocated in the deep waters of the Andaman Sea, in the North Sumatra basin and Mergui basin, Thailand.Two-dimensional seismic acquisition was completed in December 2008 and the processing was completed in June2009.

G9/43

PTTEP indirectly owns and operates 100.0% of the G9/43 project. The G9/43 project is located in the Gulfof Thailand. Activities at this project have been suspended pending the resolution of a boundary dispute. Thereare ongoing negotiations between the governments of Thailand and Cambodia.

L21, 28 and 29/48

PTTEP indirectly owns a 70.0% interest in the L21, 28 and 29/48 project, in partnership with ResourcefulPetroleum (Thailand). The project is located in the Khon Kaen, Chaiyaphum, Udonthani, Nakornratchasrima,Nongbualumphu, Mahasarakham and Buriram provinces in north-eastern Thailand. In 2010, three-dimensionalseismic data processing was completed. PTTEP also began drilling the first exploration well in December 2010.

86

L22/43

PTTEP indirectly owns and operates 100.0% of the L22/43 project. The L22/43 project is located in thePhitsanulok and Pichit provinces. In 2010, three-dimensional seismic acquisition and processing for 135 squarekilometers was completed.

L53/43 and L54/43

PTTEP indirectly owns a 100.0% interest in the L53/43 and L54/43 project. The L53/43 and L54/43 projectis located in Suphan Buri, Ayuthaya, Ang-Thong, and Karnchanaburi provinces, adjacent to PTTEP1. Twoexploration wells have been drilled since 2009. In October 2010, the project began production with the oil beingsold to PTT at its Bangchak refinery. The Average sales volume of crude oil is 2 Bbls/d.

Overseas

Algeria Hassi Bir Rekaiz

On January 17, 2010, PTTEP, through its subsidiary, signed a contract for Block Hassi Bir Rekaiz in Algeria.The joint venture partners consist of PTTEP (as operator), CNOOC International Limited (CNOOC) andSonatrach, with participation interests of 24.5%, 24.5% and 51.0%, respectively. The contract is effective as ofMay 26, 2010. The Algeria Hassi Bir Rekaiz project is located in the southeast zone of Algeria with anapproximate area of 5,378 square kilometers.

Australia AC/P36

PTTEP indirectly owns a 20.0% interest in the Australia AC/P36 project, in partnership with MurphyAustralia Oil Pty Ltd. and Finder Exploration Pty Ltd. The Australia AC/P36 project is located in the BrowseBasin, offshore of Western Australia. The first exploration well in this project was commenced in 2008.

Australia WA-423-P

PTTEP indirectly owns a 30.0% interest in the Australia WA-423-P project, in partnership with MurphyAustralia Oil Pty Ltd. and Diamond Resources Australia. The Australia WA-423-P project is located offshore ofWestern Australia. Drilling of the first exploration well for this project will commence in 2011.

Bahrain 2

PTTEP indirectly owns a 100.0% interest in the Bahrain 2 project and is also the operator of this project.The Bahrain 2 project is located offshore, in the north of Bahrain. Three-dimensional and two-dimensional seismicacquisition and processing activities, as well as external geological studies commenced in July 2009.

Cambodia B

PTTEP indirectly owns a 33.33334% interest in the Cambodia B project along with Resourceful PetroleumLimited and SPC Cambodia Ltd. PTTEP serves as the operator of the project. The Cambodia B project is locatedin the Gulf of Thailand, offshore Cambodia. Drilling of the first exploration well for this project was conductedin 2008 and the second well was drilled in 2010. Various technical studies have been undertaken since then.

Indonesia Malunda

PTTEP indirectly owns a 100.0% interest in the Indonesia Malunda project and is the project operator. TheIndonesia Malunda project is located offshore in the Makassar Straits, off the coast of the Sulawesi andKalimantan islands in Indonesia. PTTEP acquired the exploration rights to the Indonesia Malunda project in May2010. The project is currently in the early exploration period, where geological studies and a three-dimensionalseismic survey will be conducted.

Indonesia Sadang

PTTEP indirectly owns a 40.0% interest in the Indonesia Sadang project, with Talisman Sadang B.V.(“Talisman”) as its partner. Talisman is the project operator. The Indonesia Sadang project is located offshore inthe Makassar Straits, off the coast of the Sulawesi and Kalimantan islands in Indonesia. PTTEP and its partneracquired the exploration rights to the Indonesia Sadang project in May 2010. The project is currently in theexploration period, where geological studies and a three-dimensional seismic survey will be conducted.

87

Indonesia Semai II

PTTEP indirectly owns a 28.3% interest in the Indonesia Semai II project along with Murphy Semai Oil CoLtd, INPEX Seram Sea Ltd and PT Pertamina Hulu Energi Semai II. The Indonesia Semai II project is locatedoffshore, to the southwest of West Papua, Indonesia. PTTEP and its partners acquired the exploration rights to theIndonesia Semai II project in November 2008. The project is currently in the exploration period. Drilling of thefirst exploration well was commenced in late 2010, with plans for a second and third well.

Indonesia South Mandar

PTTEP indirectly owns a 67.0% interest in the Indonesia South Mandar project, with Talisman SouthMandar B.V. as its partner. PTTEP is the project operator. The Indonesia South Mandar project is located offshorein the Makassar Straits, off the coast of the Sulawesi and Kalimantan islands in Indonesia. PTTEP and its partneracquired the exploration rights to the Indonesia South Mandar project in May 2010. The project is currently in theearly exploration period, where geological studies and three-dimensional seismic survey will be conducted.

Indonesia South Sageri

PTTEP indirectly owns a 30.0% interest in the Indonesia South Sageri project, with Talisman South SageriB.V. as its partner. Talisman is the project operator. The Indonesia South Sageri project is located offshore in theMakassar Straits, off the coast of the Sulawesi and Kalimantan islands in Indonesia. PTTEP and its partneracquired the exploration rights to the Indonesia South Sageri block in May 2010. The project is currently in theexploration period, where geological studies and a three-dimensional seismic survey will be conducted and oneexploration well is planned.

Myanmar M3, M4, M7 and M11

PTTEP indirectly owns a 100.0% interest in the Myanmar M3, M4, M7 and M11 project, and is the soleoperator of this project. The Myanmar M3, M4, M7 and M11 project is located in the Gulf of Martaban, Unionof Myanmar. Subsurface studies began in 2008. Exploration drilling is expected to begin in 2011.

New Zealand Great South

PTTEP indirectly owns a 36.0% interest in the New Zealand Great South project, in partnership with OMVNew Zealand Limited, Mitsui E&P Australia Pty. Limited. The New Zealand Great South project is located in theGreat South Basin, New Zealand. The two-dimensional seismic acquisition studies for this project commenced inNovember 2007 and geological studies commenced in January 2008. Additional 2D seismic acquisition studiescommenced in 2010.

Rommana

PTTEP indirectly owns a 30.0% interest in the Rommana project, in partnership with Sipterol and Centrica.The Rommana project is located onshore in Sinai in the north-eastern part of Egypt. Three-dimensional seismicacquisition studies for this project commenced in December 2009 and October 2010 and all were completed byin the end of 2010. The first exploration well began drilling in January 2011.

Sidi Abd El Rahman Offshore

PTTEP indirectly owns a 30.0% interest in the Sidi Abd El Rahman project, in partnership with Edison andSipetrol. The Sidi Abd El Rahman project is located in the Mediterranean Sea, northwest of Egypt.Three-dimensional seismic acquisition studies for this project commenced in December 2008. The firstexploration well was drilled in 2009. A second exploration well was drilled in 2010.

Vietnam B & 48/95

PTTEP indirectly owns an 8.5% interest in the Vietnam B & 48/95 project, in partnership with ChevronVietnam (Block B), LTD, Petrovietnam Exploration and Production Corporation and MOECO Vietnam PetroleumCo., Ltd. The Vietnam B and 48/95 project is located offshore of Vietnam. The front-end engineering design forthis project was awarded in February 2010 and was completed in the first quarter of 2011.

88

Vietnam 52/97

PTTEP indirectly owns a 7.0% interest in the Vietnam 52/97 project, in partnership with Chevron Vietnam(Block 52), LTD, Petrovietnam Exploration and Production Corporation and MOECO Southwest VietnamPetroleum Co., Ltd. The Vietnam 52/97 project is located offshore of Vietnam. The front-end engineering designfor this project was awarded in February 2010 and was completed in the first quarter of 2011.

General

The following table sets forth certain natural gas, crude oil and condensate total sales information for theperiods indicated.

Year ended December 31,

2008 2009 2010

Total Sales Total Sales Total Sales

Gas (Bbls/d)(1) .......................................................................... 149,639 160,336 188,385Liquid(Bbls/d)(2) ....................................................................... 69,675 73,420 76,190Average volume ......................................................................... 219,314 233,756 264,575

(1) Gas comprises natural gas and LPG.(2) Liquid comprises crude oil and condensate.

The following table shows the weighted average sales prices (in the currency indicated) received by PTTEPper unit of production during the periods indicated.

Year ended December 31,

2008 2009 2010

Gas (U.S. dollar per MMBtu)(1) ............................................... 5.17 5.17 5.52Liquid (U.S. dollar per Bbl)(2) .................................................. 91.38 58.03 73.77Weighted avg. (U.S. dollar per Boe) ........................................ 49.69 39.53 44.83

(1) Gas comprises natural gas and LPG.(2) Liquid comprises crude oil and condensate.

Natural Gas Sales

Consistent with current Government policy, PTT purchases a substantial portion of the natural gasproduction in Thailand through long-term take-or-pay gas sales agreements. The gas sales agreements generallyprovide for the sale to PTT of all natural gas produced by the field or fields covered by the agreement. PTTEP,together with its relevant joint venture partners, is a party to gas sales agreements with PTT. Such gas salesagreements were negotiated on an arm’s length basis between PTT and its joint venture partners, including PTTEP.PTTEP’s gas sales agreements will generally terminate on the earliest of (i) the expiration of the underlyingconcession, (ii) the depletion of reserves in the relevant field and (iii) a fixed period of time (generally 25 to 30years) after commencement of production.

Gas Sales Agreements. PTTEP’s gas sales agreements provide for delivery of natural gas at specifiedpressures to PTT at the wellhead or other agreed location. The agreements establish PTTEP’s obligation to deliver,and PTT to take delivery of, specified minimum daily quantities and require PTT to pay for any volumescontracted for but not taken. To the extent that PTTEP is unable to meet its delivery obligations, it is generallyrequired to supply the amount of shortfall in the succeeding period at a discount of up to 25% of the contractedprice. In the event that PTT is unable to meet its obligations under the gas sales agreements, PTT is obligated topay PTTEP for the minimum quantity it is required to purchase in each contract year, although PTT may acceptdelivery of such natural gas in succeeding years. The settlement terms of PTT’s take-or-pay obligations to PTTEPin respect of the gas sales agreements between PTT and PTTEP generally provide for billing and settlement inrespect of any gas not taken by PTT only after the end of the respective contract year during which suchobligations arose. PTT also has the right to require PTTEP and its joint venture partners to deliver quantities inexcess of the minimum, subject to a contractual maximum.

89

Under the gas sales agreements, the price at which PTTEP sells its natural gas production is adjusted at thebeginning of each of a number of consecutive periods that commence upon the earlier of the expiration of aspecified period of time or the production of a specified quantity of natural gas. The formulas used to reset theprice include an adjustment factor, which, absent offsetting increases in the other adjustment factors, would resultin lower natural gas sales prices over succeeding periods. In relation to the concessions located in Thai territory,the price is adjusted annually, semi-annually or monthly from a predetermined price (in Baht) to take into accountchanges to the average price per barrel of medium-sulphur fuel oil (or in certain instances low-sulphur fuel oil)ex Singapore and other adjustment factors, including Baht/U.S. dollar exchange rates and various measures ofinflation, including the Thai Consumer Price Index and the U.S. Producer Price Index for Oilfield and GasfieldMachinery and Tools. Several gas sales agreements also provide for an adjustment if the Baht/U.S. dollarexchange rate has fluctuated by more than 5% in a given month. Such price adjustments operate as a partialhedging mechanism against fluctuations in the Baht/U.S. dollar exchange rate and have the effect of increasingor decreasing the Company’s sales revenues measured in Baht. In the case of Yadana and Yetagun, the price isadjusted quarterly, after the initial contract period of up to 15 months, from a predetermined price (in U.S. dollars)to take into account changes to the average price per barrel of medium sulphur fuel oil ex Singapore and otheradjustment factors and various measures of inflation, including the U.S. Consumer Price Index and the U.S.Producer Price Index for Oilfield and Gasfield Machinery and Tools. Payments for gas sold under the agreementsare made monthly.

The gas sales agreements contain force majeure provisions that excuse PTT and PTTEP from performanceof their respective obligations in certain circumstances. Force majeure is generally defined as any happening,event or pernicious results which are beyond the control of the party claiming relief acting in a reasonable andprudent manner. Certain of the gas sales agreements include within the definition of force majeure the inabilityof PTT to accept delivery of natural gas by reason of the inability of any of PTT’s customers to take natural gas,if such inability is caused by an event which would have constituted force majeure in relation to PTT. However,PTT is not entitled to such force majeure relief unless PTT requires each of its suppliers to bear its proportionateshare of the volume of natural gas PTT is unable to take. Force majeure events generally do not include theinability to pay amounts called for under the agreement, nor does the existence of a force majeure event suspendany obligation for the payment of money due. These agreements are governed by Thai law, and, in the case ofYadana and Yetagun, English and Myanmar law, and provide for the resolution of disputes through arbitration.

PTTEP has also entered into a natural gas sales agreement with other buyers with respect to a portion ofnatural gas produced in the S1 concession area.

Oil, Condensate and LPG Sales

Oil Sales Agreements. PTTEP is a party to crude oil sales agreements with PTT with respect to its workinginterest in PTTEP 1 (the “PTTEP 1 Agreement”) and S1 (the “S1 Agreement”). The agreements provide for thesale to PTT of all oil produced from the fields. See “— Principal Properties — Properties Under Production —PTTEP 1” and “— S1.”

The PTTEP 1 Agreement provides for crude oil prices to be adjusted monthly based on the estimated yieldof refined petroleum products per barrel of crude oil produced at PTTEP 1, multiplied by an average price per unitof refined product derived from certain internationally available published prices and adjusted to reflect refiningcosts.

The S1 Agreement provides for sales of crude oil at a price adjusted to reflect the daily changes in a specifiedquoted price of a basket of a number of grades of crude oil. The stated price and the adjustment formula can beamended to reflect changes in the quality of crude oil produced and under certain other circumstances.

Condensate and LPG Sales Agreements. PTTEP is a party to condensate sales agreements with respect toits working interests in Bongkot, Arthit and Contract 3, and an LPG sales agreement with respect to its workinginterest in S1. The agreements provide for the sale to PTT of all of the condensate and LPG from the respectivefields. Condensate prices are based on specified quoted condensate and light crude prices in U.S. dollars. The LPGprice is set in the contract and is subject to revision by agreement of the parties or pursuant to a change inGovernment policy.

90

Research and Development

Present and future petroleum fields are deeper and have increasingly complex structure trapping andreservoir characteristics than fields explored in the past. Appropriate petroleum exploration and productiontechniques and technology are therefore required in order to reduce exploration and production risks whileincreasing PTTEP’s competitiveness and the chances of success. PTTEP researches and tests the suitability andapplicability of state-of-the-art exploration and production technologies to specific subsurface geologicalconditions in targeted areas or fields prior to full implementation of such technologies.

PTTEP carries out various research and studies on geology, geophysics and petroleum engineering toimprove its capabilities and competitiveness. Examples of studies with successful outcomes include:

• research intended to increase the petroleum reserves and to sustain and extend the production periodof major projects, including the Bongkot, S1 and Arthit projects. The research defined the highpotential areas, structures and targets for drilling exploratory wells and also involved the analysis ofappropriate petroleum production technologies for optimizing production and improving oil recovery;

• a study that resulted in the decision to begin full-scale water flooding in L block of Sirikit oil field in2007 by a series of water injection drilling methods that converted the production wells to injectionwells;

• the application of seismic attributes and “amplitude variations with offset” (AVO) technology fordetailed imaging of rock characteristics and trapping. For the seismic acquisition in blocks L21, 28 and29/48, PTTEP utilized a recording cable of more than six kilometers in length to obtain images of thedeep horizons clearer than any previous data;

• cooperation and support on Thai petroleum geology research with Chulalongkorn, Chiang Mai andKhon Kean Universities; and

• cooperation with Total and King Mongkut’s University of Technology North Bangkok to studycorrosion and corrosion prevention, including setting up the first corrosion laboratory in Thailand.PTTEP has established a standard petroleum exploration and production database and a PTTEP CoreResearch Center (PCRC) for all data and rock samples received from domestic and internationalassets. The database and PCRC, as well as PTTEP’s established knowledge management systemparticularly in the geosciences, plays a significant role in the continuing development of modern andstate-of-the-art exploration and production technologies for PTTEP.

Employee Matters

As of February 28, 2011, PTTEP had 1,711 employees and 1,598 contracted personnel. PTTEP’s success inconducting exploration and production activities and in operating oil and natural gas concessions is highlydependent upon its ability to attract and retain qualified geoscientists, petroleum engineers, technicians &managers with sufficient experience in the oil and gas exploration and production business. PTTEP has beensuccessful in attracting qualified personnel from both local and international sources. Shortages of experiencedengineers and technicians in Thailand, however, may make it necessary for PTTEP to hire increasing numbers ofexpatriate personnel in the future, particularly as PTTEP increasingly acts as operator of exploration or productionventures overseas.

PTTEP invests significant resources in training its personnel and regularly seconds employees to work withoperators of joint ventures in which it is a participant so that they can gain experience in a number of technicalareas, including training in gas processing and operations, reservoir engineering and management, productiongeology and petroleum geostatistics. PTTEP conducts an extensive employee training program, including internaltraining programs and attendance at Thai and international technical institutes, as well as technical training ofemployees seconded to work with its joint venture operators.

PTTEP is dedicated to demonstrating its social responsibility by encouraging substantial employeeparticipation in assorted activities including community quality of life and environmental conservation. PTTEPand its employees have launched diverse projects and activities focused on youth development, learning, healthand well-being and the occupational development of community members such as scholarships for thousands ofelementary and secondary students in various project areas of PTTEP every year. In the area of environmental

91

conservation, PTTEP has launched “Tree Planting in the Human Heart” and “Thai Heritage, World Heritage”projects to focus on society and PTTEP employees taking responsibility for environmental and culturalstewardship. “Smiling Earth” and “PTTEP Thai Marine Heritage Conservation” projects focus on social awarenessof the potential impact of society’s neglect of its natural resources and the environment.

PTTEP considers its current relations with its employees to be good. The work force is not unionized andPTTEP has not experienced a work stoppage or strike. PTTEP believes that its remuneration levels are competitivewithin the Thai oil and natural gas industry.

Environmental Matters

PTTEP and its subsidiaries are subject to environmental laws and regulations in Thailand and overseasconcerning its oil and gas exploration, transmission and production operations, petroleum and petrochemicalproducts and other activities. In particular, these laws and regulations may:

• require the submission and approval of environmental impact assessment reports prior to thecommencement of certain exploration, production, refining transmission, gas separation and chemicalprojects and pipeline construction;

• require submission and approval of health impact assessment reports, the conduct of a public hearingand the hearing of opinions from an independent environmental and health organization prior to thecommencement of certain projects that may have a severe impact on the environment, naturalresources and health of local community;

• restrict the type, quantities and concentration of various substances that can be released into theenvironment;

• limit or prohibit drilling activities on certain lands lying within protected areas; and

• impose criminal and civil liabilities for pollution resulting from oil, natural gas and petrochemicaloperations.

These laws and regulations also restrict air emissions and discharges to surface and subsurface waterresulting from the operation of natural gas processing plants, pipeline systems and other facilities that PTTEPowns. In addition, PTTEP’s operations may be subject to laws and regulations relating to the generation, handling,storage, transportation, disposal and treatment of waste materials.

PTTEP has clear policies with a commitment to strict compliance with governing laws and regulations.PTTEP pays attention to the environmental impact of every step of its operations, including the design ofproduction platforms, production processes, production control, vigilance and monitoring and hazard control.Training is continually provided to enhance employees’ potential and educate them about accident prevention andsafe work practices, as well as emergency responses through drills, including joint ones with relevant outsideagencies. PTTEP has internally implemented the ISO 14001:2004 environmental management system and theInternational Association of Oil and Gas Production (OGP) procedures in PTTEP’s safety managementprocedures.

PTTEP anticipates that the environmental laws and regulations to which it is subject will becomeincreasingly strict and are therefore likely to have an increasing impact on its operations. It is impossible, however,to predict accurately the effect of future developments in such laws and regulations on PTTEP’s future earningsand operations. Some risk of environmental costs and liabilities is inherent in certain of PTTEP’s operations andproducts, as it is with other companies engaged in similar businesses, and there can be no assurance that materialcosts and liabilities will not be incurred. However, PTTEP does not currently expect any material adverse effecton its financial condition or results of operations as a result of compliance with such laws and regulations.

Montara Incident

In accordance with the Australian “National Plan to Combat Pollution of the Sea by Oil and Other Noxiousand Hazardous Substances,” containment and clean up of the Montara Incident commenced on September 5, 2009,immediately after the uncontrolled release of crude oil, and continued until December 3, 2009. The AustralianMaritime Safety Authority (“AMSA”) took control of the incident site, cleanup and containment on August 23,2009, the day of the incident, and supervised the involvement of a wide range of Australian agencies and industryparticipants, including PTTEP. The immediate cleanup efforts included the application of approximately 184,000

92

liters of oil dispersant from September 5, 2009 through November 1, 2009. Offshore containment operations alsoused two vessels and a 300 meter containment boom that utilized a skimmer to recover oil. Over 35 days ofoperation, 844,000 liters of oil mixture were processed to recover an estimated 493,000 liters of oil or oilemulsion, representing approximately 10% of total oil spilled.

According to the Commission’s report released on November 24, 2010, the response strategy for preventingoil from impacting sensitive marine resources, particularly the Ashmore Reef, Cartier Island and the KimberleyCoast of Western Australia, was largely achieved. Nevertheless, the extent of the pollution was significant. TheCommission was unable to draw any firm conclusions in the report about the extent of the damage caused by theoil and dispersants used to break down the oil in the marine environment because adequate data was not available.

Under Australian law, the costs of containment and cleanup can be recovered from the company orcompanies responsible for the spill. To help ensure that companies can meet such potential expenses, Australianlaw requires petroleum exploration companies to maintain adequate insurance coverage. Australian governmentauthorities can challenge the amount of insurance required as inadequate. The type and amount of insurancerequired varies depending upon the activities of the exploration companies. However, standard practice in theoffshore petroleum industry is to obtain insurance coverage in amounts between U.S.$100 to U.S.$300 million.If a company does not adequately cover any liabilities, it may be subject to a wide range of penalties, includingbeing barred from gaining further petroleum concessions.

As of December 31, 2010, PTTEP preliminarily estimated the maximum amount to be recovered under theinsurance policies to be approximately Baht 6,700 million (U.S.$222 million). Of which, Baht 1,341 million wasrecognized in the fourth quarter of 2009 and Baht 1,369 million was recognized in the third quarter of 2010.However, the actual amount ultimately recoverable under the insurance policies is dependent upon costs actuallyincurred and terms and conditions of the policies. PTTEP is now in the claims process with the insurers for theremaining recoverable amounts. PTTEP expects the remaining funds to be received in 2011.

On October 9, 2009, PTTEP and the Australian government reached an agreement for a long-term scientificenvironmental monitoring program for the area affected by the release of crude oil. The objectives of themonitoring program were to obtain information to assist in the planning and execution of the response to therelease of oil and in minimizing environmental harm, and to obtain information to provide indicative or qualitativedata for short-term and longer-term environmental effects assessment. PTTEP has undertaken to fund themonitoring program for its duration.

The petroleum exploration and production industry also contributes to the resources and operations of theAustralian Marine Oil Spill Center (“AMOSC”). AMOSC provides equipment and personnel on a 24-hoursstandby basis to respond to major oil spills, provide oil spill training and advice on the use of oil spill equipmentand response activities. Costs associated with AMOSC activities during an oil spill response associated with anoffshore petroleum industry facility will be covered by the offshore operator’s insurance.

Montara Incident Action Plan

As a result of PTTEP’s and the Commission’s investigations into the Montara Incident, PTTEP and PTTEPAA have developed the Action Plan to initiate further procedures and ensure compliance with such procedures toavoid future uncontrolled releases of oil and natural gas at its projects. On February 4, 2011, the Minister forEnergy, Resources and Tourism announced his determination that the Action Plan effectively responded to theissues identified by the Commission. Pursuant to the Action Plan, PTTEP and PTTEP addressed both the technicalissues surrounding the Montara Incident and the systematic and organizational issues that contributed to it.

The Action Plan covers nine principal focus areas:

1. Clarification of well barrier integrity of the Montara wells (H2, H3, H4 and GI).

2. Independent review of the company’s drilling management system to provide clear guidance on wellconstruction specifications and standards.

3. Safety Security Health and Environment (SSHE) improvements: including defining safety auditingand monitoring programs; leadership training; amending investigation protocols to ensure any wellcontrol incidents are fully investigated by independent experts.

4. Regulatory/Industry liaison: developing collaborative engagement and consultation with keygovernment agencies during an emergency.

93

5. Organization and Personnel: continuously reviewing PTTEP AA and drilling organization to improvesafety and reliability.

6. Competency and Training: implementing competency assessments and training plans to ensure drillingand key operational personnel are competent and trained to do their jobs.

7. Environmental: improving spill response preparedness and capability by revising oil spill contingencyplans, assessing spill equipment availability, developing monitoring programs for future operations.

8. Governance: strengthening PTTEP AA and corporate oversight to improve working standards andcommunications; clearly defining governance between PTTEP AA and PTTEP.

9. Implementation: establishing a management committee comprising senior executives from PTTEP AAand PTTEP to oversee the implementation of the Action Plan; appointing an Implementation Manager.

As of December 31, 2010, PTTEP AA had completed approximately half of the 59 action items listed in theAction Plan. The target completion date for an additional 14 action items is April 1, 2011. As of the date of thisOffering Memorandum, the following focus areas are largely completed: the clarification of the Montara wellbarrier integrity, revision of the drilling management system, the implementation of the training plans, thestrengthening of corporate governance and the appointment of the implementation manager. The use of theregulatory/industry liaison and the improvement of the SSHE systems are perpetual activities that the PTTEP AAhas committed to engage in.

Safety, Security, Health and Environmental Policy

The petroleum exploration and production business has certain inherent risks, including oil and gas leakagesand fires. Offshore operations face natural risks such as waves, storms, and earthquakes; onshore operations couldalso suffer from earthquakes and flash floods. Man-made risks, such as sabotage or terrorist acts, are also possible.In addition to these external risks, human errors could create risk. All these situations require preventive andmitigating measures.

In view of these risks, PTTEP has drawn up a clear Safety, Security, Health and Environment policy and witha commitment to comply strictly or exceed governing laws and regulations. PTTEP applies the policy to every stepof operations, including the engineering, design, construction, installation, commissioning, de-commissioning andoperation of production facilities.

To efficiently and effectively implement the policy across PTTEP as a whole, PTTEP regularly updates itsinformation and knowledge capabilities. PTTEP continually provides training to enhance employee potential andto educate them about accident prevention and safe work practices. Drills and exercises, including drills withrelevant outside agencies, are conducted to prepare for emergency responses.

PTTEP has implemented a variety of risk prevention and remedy measures to achieve its objectives andsustainable business operation. PTTEP has implemented the ISO 14001:2004 environmental management systemand the OHSAS 18001 health and safety management system in certain operating assets. PTTEP has alsoimplemented the International Association of Oil and Gas Production (OGP) procedures in PTTEP’s safety,security, health and environmental management system.

Insurance

PTTEP has a comprehensive insurance policy that covers all aspects of its business and all of its properties.PTTEP employs a risk management policy that helps it analyze what aspects of its business and properties needspecific levels of insurance. In addition, PTTEP employs large international insurance brokers to help determineits risk profile each year so that it may apply its insurance resources in the most cost-effective manner. PTTEPalso assists certain subsidiaries to determine their insurance needs.

PTTEP’s coverage includes property damage, third party liability and personnel accident insurance. PTTEPconsiders its insurance coverage to be in accordance with industry standards.

94

Legal Proceedings

PTTEP is involved in certain other judicial and arbitral proceedings before Thai courts, foreign courts orarbitral bodies concerning matters arising in connection with the conduct of its businesses. PTTEP believes, basedon currently available information, that the results of such other pending proceedings, if adversely determined, willnot, in aggregate, have a material adverse effect on PTTEP’s business, financial condition, results of operationsand prospects.

In connection with the Montara Incident, PTTEP AA may be subject to potential civil claims (from, forexample, plaintiffs seeking damages for property damage or loss of livelihood due to the oil spill) as well asregulatory claims from Australian and/or Indonesian government agencies. For example, on August 26, 2010,PTTEP AA received a letter from the Government of Indonesia claiming U.S.$2.5 billion in compensation relatedto the Montara Incident. Further details of the claim and supporting documentation were received in October 2010.PTTEP AA has not accepted the claim as PTTEP AA believes that it is not supported by scientifically validevidence. PTTEP AA continues to actively engage the Government of Indonesia, but has not accepted any legalliability to pay compensation to the Government of Indonesia. In December 2010, PTTEP AA and the Governmentof Indonesia agreed to provide each other with additional documents and to conduct a joint survey to verify theGovernment of Indonesia’s data on the claimed damage to its fishing industry. PTTEP AA and the Governmentof Indonesia met again for discussions in February 2011. As of the date of this Offering Memorandum, noconclusion has been reached regarding any claims for compensation. See “Risk Factors — Risks Relating toPTTEP’s Business — PTTEP and PTTEP AA are subject to claims and liabilities in relation to the MontaraIncident.” Among other things, criminal proceedings could also be brought as a result of the Montara Incident. See“Risk Factors — Risks Relating to PTTEP’s Business — PTTEP AA and PTTEP may face material adverseconsequences as a result of ongoing and future investigations into the Montara Incident conducted by variousAustralian governmental agencies. “PTTEP has also received claims in connection with the early termination ofcontracts due to the Montara Incident (although such claims to date have not, in the aggregate, been material), andhas received notice of potential claims for compensation from fishermen due to the Montara Incident (althoughno claim has yet been filed and any damages, if claimed, are not yet quantifiable).

95

PRINCIPAL SHAREHOLDERS

The following table details certain information about PTTEP’s shareholders, as shown on its share registeras of February 15, 2011. Other than PTT, no shareholder owns more than 5% of PTTEP’s outstanding commonshares.

Name of Shareholder

Number of

Shares Held Percentage

PTT Public Company Limited ...................................................................... 2,167,500,700 65.32State Street Bank and Trust Company.......................................................... 72,318,443 2.18BNP Paribas Securities Services Luxembourg............................................. 70,485,645 2.12Nortrust Nominees Ltd.................................................................................. 68,586,328 2.07Thai NDVR Company Limited..................................................................... 60,958,452 1.84HSBC (Singapore) Nominees Pte Ltd .......................................................... 60,890,307 1.84The Bank of New York (Nominees) Limited............................................... 47,658,200 1.44Chase Nominees Limited 42......................................................................... 40,243,900 1.21BNP Paribas Securities Services, London Branch ....................................... 38,243,600 1.15Social Security Office (2 Cases)................................................................... 30,864,020 0.93Total Shares of Top 10 Major Shareholders ............................................ 2,657,749,595 80.10Issued and Paid-Up Shares as of February 15, 2011 ............................. 3,318,433,600 100.00

96

MANAGEMENT

Directors

PTTEP’s board of directors has ultimate responsibility for the administration of the affairs of the company.The Articles of Association provide for a board of directors of between five and fifteen directors and one-third ofthe Board members are retired each year by rotation. According to PTTEP’s Corporate Governance Policy, at leasthalf of the Board members must be independent directors. PTTEP’s board of directors consisted of 14 members.The business address of all the directors and executive officers is PTTEP’s registered office.

The Directors as of March 1, 2011 are as follows:

Name Age Position

Mr. Prasert Bunsumpun.............................................................. 58 ChairmanMr. Pongsvas Svasti ................................................................... 53 Director (Independent)Mr. Pichai Chunhavajira ............................................................ 61 DirectorMr. Chulasingh Vasantasingh..................................................... 60 Director (Independent)Mr. Sommai Khowkachaporn .................................................... 62 Director (Independent)Mr. Viraphol Jirapraditkul.......................................................... 55 Director (Independent)Mr. Tevin Vongvanich ................................................................ 52 DirectorMr. Vudhibhandhu Vichairatana ................................................ 62 Director (Independent)Mr. Chitrapongse Kwangsukstith............................................... 61 DirectorMr. Bhusana Premanode ............................................................ 56 Director (Independent)Mr. Witoon Simachokedee......................................................... 57 Director (Independent)Mr. Wichai Pornkaretiwat .......................................................... 58 DirectorMr. Chakkrit Parapuntakul......................................................... 51 Director (Independent)Mr. Anon Sirisaengtaksin........................................................... 58 Director, President and CEO

Certain information with respect to PTTEP’s directors is set out below:

Mr. Prasert Bunsumpun has been a director of PTTEP since August 29, 2000 and currently serves as aDirector, President and Chief Executive Officer of PTT Plc. and Chairman of PTTEP’s Board of Directors. Inaddition, he also serves as Chairman of the Board of Independent Power (Thailand) Co., Ltd., Thaioil Power Co.,Ltd. and Thai Lube Base Plc., and as a Vice Chairman for IRPC Plc. and PTT Chemical Plc. Moreover, he servesas a Director for PTT Aromatics and Refining Plc. He received his undergraduate degree in Civil Engineering fromChulalongkorn University and his MBA from Utah State University. Mr. Bunsumpun received a Certificate inAdvanced Management from Harvard Business School and attended the Politics and Governance in Democracyfor Executives Course from King Prajadhipok’s Institute. Mr. Bunsumpun served as President of the Oil BusinessGroup, Petroleum Authority of Thailand from 1996 to 1999, President of the Gas Business Group, PetroleumAuthority of Thailand, from 1999 to 2001, and Senior Executive Vice President of the Gas Business Group, PTTfrom 2001 to 2003.

M.R. Pongsvas Svasti has been a director of PTTEP since March 31, 2010 and is a Director of IRPC Plc.and MFEC Plc. He also serves as Associate Professor of Operations Management, Thammasat University. Hereceived a bachelor’s degree in Computer Sciences, Southeast Missouri State University and masters’ degrees inIndustrial Management from University of Central Missouri, and in Public Policy and Management from HarvardUniversity.

Mr. Pichai Chunhavajira has been a director of PTTEP since April 27, 2001 and is the Chairman ofPTTEP’s Risk Management Committee. He serves as a Chairman of the Board of Thaioil Plc. and Thaioil EthanolCo., Ltd., and as a Director on the boards of PTT Plc., IRPC Plc., Thai Airways International Plc., BangchakPetroleum Plc., Thai Lube Base Plc., and Thaioil Power Co., Ltd. In addition, he is President of University CouncilMember, Assumption University and Vice President and Chairman of the Managerial Accounting Committee,Federation of Accounting Professions. He served as Senior Executive Vice President, Corporate Finance &Accounting for PTT Plc. from 2001 to 2007. He received his bachelor’s degree in Accounting from ThammasatUniversity and his MBA in Finance from Indiana University of Pennsylvania.

97

Mr. Chulasingh Vasantasingh has been a director of PTTEP since April 30, 1998 and serves as Chairmanof PTTEP’s Audit Committee. He serves as the Attorney General at the Office of the Attorney General of theKingdom of Thailand. He is also a Director of Krung Thai Bank Plc., Thai Airways International Plc. and the ThaiBar Association. In addition, he sits on the Board of Property Management, Chulalongkorn University. He holdsan LL.B. from Chulalongkorn University and an M.C.L. from the University of Illinois.

Mr. Sommai Khowkachaporn has been a director of PTTEP since April 10, 2008. He is also a Director ofPTT Plc., IRPC Plc., Ratchaburi Electricity Generating Holding Plc., Thai Lube Base Plc. and Wangthong GroupPlc. He previously served as a Director of PTT Aromatics and Refining Plc. and National Petrochemical Plc. Mr.Khowkachaporn received a bachelor’s degree in Business Administration from the University of East, Philippinesand an MBA from Long Island University.

Mr. Viraphol Jirapraditkul has been a director of PTTEP since March 29, 2007 and is Director General ofthe Energy Policy and Planning Office (EPPO). He also sits on the board of the Electrical and Electronics Instituteand the Energy Fund Administration Institute. He previously sat on the Energy Regulatory Board of EPPO, wasDeputy Director General of EPPO and a Director of the Energy System Analysis Bureau, EPPO. He received abachelor’s degree in Economics from Thammasat University and masters’ degrees in Economics from theNational Institute of Development Administration and Energy Economics from the University of Calgary, Canada.

Mr. Tevin Vongvanich has been a director of PTTEP since November 30, 2009 and is the CFO of PTT Plc.He is the Chairman of PTT ICT Solutions Co., Ltd. He is also a Director of PTT Aromatics and Refining Plc., PTTChemical Plc., Thaioil Plc. and PTT International Co., Ltd. Before taking his current position, he served as SeniorVice President, Office of Chief Executive Officer and President (seconded to PTT), Senior Vice President,Regional Assets Division, Senior Vice President, Operations Division, and Senior Vice President, New ProjectsDivision. He received his bachelor’s degree in Chemical Engineering from Chulalongkorn University and holdsmaster’s degrees in Petroleum Engineering from the University of Houston and Chemical Engineering from RiceUniversity.

Mr. Vudhibhandhu Vichairatana has been a director of PTTEP since April 29, 1999 and serves as Chairmanof PTTEP’s Corporate Governance Committee. He is currently the Chairman of the Executive Board of thePrincess Maha Chakri Sirindhorn Anthropology Centre. He previously served as a Director of Airports of ThailandPlc., Thai Military Bank Plc., Thai Airways International Plc., Thaioil Power Co., Ltd. and the ProvincialElectricity Authority. From 2002 to 2008, he also served as Budget Director of the Bureau of the Budget. Mr.Vichairatana received a bachelor’s degree in Economics from Stephen F. Austin State University and a master’sdegree in Economics from the University of Arkansas.

Mr. Chitrapongse Kwangsukstith has been a director of PTTEP since October 6, 2003 and currently servesas Chairman of the Board and acting President of PTT International Co., Ltd., Chairman of PTT Utility Co., Ltd.And PTT FLNG Co., Ltd. He is a Director of IRPC Plc. and Independent Power (Thailand) Co., Ltd. He is alsoa President of the Thailand Association for Natural Gas Vehicles. He previously served as Chairman of PTT LNGCo., Ltd., Energy Complex Co., Ltd. and PTT Natural Gas Distribution Co. Ltd. and as Chief Operating Officerof the Upstream Petroleum & Gas Business Unit of PTT Plc. He also previously served as Deputy Governor,Corporate Plan and Development, for the Petroleum Authority of Thailand from 1996 to 2001. He received abachelor’s degree in Mechanical Engineering from Chulalongkorn University and a master’s degree and Ph.D. inIndustrial Engineering from Lamar University.

Mr. Bhusana Premanode has been a director of PTTEP since January 5, 2009 and a visiting professor atImperial College, University of London, UK. He is also a Director of PTT Plc. He received a master’s degree inManagement from the Sasin Graduate Institution of Business Administration of Chulalongkorn University. Hereceived a doctorate in Business Administration in Finance from Somerset University, United Kingdom, and adoctorate in Bioengineering from Imperial College, University of London, United Kingdom.

Mr. Witoon Simachokedee has been a director since March 1, 2011 and currently serves at the PermanentSecretary of the Ministry of Industry. He is also Chairman of the Ratchaburi Electricity Generating Holding PLCand a director of the Electricity Generating Authority of Thailand. He has previously served as the DirectorGeneral of the Department of Primary Industries and Mines of the Ministry of Industry, the Permanent Deputy andInspector General of the Ministry of Industry. He received a doctorate in Public Administration fromRamkhamhaeng University, his MBA from Thammasat University, a bachelor’s degree in Electrical Engineeringfrom Kasetsart University and a bachelor’s degree in Law from Thammasat University.

98

Mr. Wichai Pornkeratiwat has been a director since March 1, 2011 and currently serves as the SeniorExecutive Vice President of the Gas Business Unit of PTT PLC and the Acting Managing Director of PTT LNGCompany Limited. He is also the Chairman of PTT LNG Company Limited. He has previously serviced as theExecutive Vice President of the Natural Gas Vehicles at PTT PLC, Managing Director of PTT LNG CompanyLimited and Executive Vice President of Project Management, Exploration, Production and the Gas BusinessGroup of PTT PLC. He received a master’s degree in Public Administration from the national InstituteDevelopment Administration and a bachelor’s degree in Electrical Engineering from Khon Kaen University.

Mr. Chakkrit Parapuntakul has been a director of PTTEP since January 1, 2011. He also serves as DirectorGeneral of the Public Debt Management Office of the Ministry of Finance, Chairman of Thaipost Co., Ltd. andChairman of the Audit Committee of Pongsaap Plc. He received his bachelor’s degree in Accounting fromThammasat University and MBA from Angelo State University, USA.

Mr. Anon Sirisaengtaksin has been a director of PTTEP since April 9, 2008 and is the President and ChiefExecutive Officer of PTTEP. He also serves as a Director of PTTEP FLNG Holding Company Limited. He wasthe Chairman of the Board of PTT ICT Solutions and a Director of the Boards of Bangkok Polyethylene Plc., ThaiLube Base Plc., Thai Paraxylene Co., Ltd., HMC Polymer Co., Ltd., Independent Power (Thailand) Co., Ltd., StarPetroleum Refining Co., Ltd., PTT Polyethylene Co., Ltd., Alliance Refining Co., Ltd. and PTT Natural GasDistribution Co., Ltd. Mr. Sirisaengtaksin previously served as Senior Executive Vice President of CorporateStrategy and Development of PTT Plc. He received his undergraduate degree in Geology from ChulalongkornUniversity and holds an MBA from Thammasat University and Certificates in “Project Investment Appraisal andManagement” and “Global Leadership” from Harvard University.

Executive Officers

The executive officers as of February 28, 2011 are as follows:

Name Age Position

Mr. Anon Sirisaengtaksin........................................................... 58 Director, President and CEOMr. Somkiet Janmaha................................................................. 56 Executive Vice PresidentMr. Asdakorn Limpiti................................................................. 56 Executive Vice PresidentMr. Somporn Vongvuthipornchai............................................... 52 Executive Vice PresidentMr. Prisdapunt Pojanapreecha.................................................... 58 Executive Vice PresidentMr. Luechai Wongsirasawad...................................................... 55 Executive Vice PresidentMr. Suraphong Iamchula............................................................ 58 Executive Vice PresidentMs. Penchun Jarikasem.............................................................. 56 Executive Vice PresidentMs. Chanamas Sasnanand.......................................................... 42 Vice President

Mr. Anon Sirisaengtaksin has been the President and Chief Executive Officer of PTTEP and is also adirector. See “Management — Directors.”

Mr. Somkiet Janmaha has been Executive Vice President of the Geosciences and Exploration Group sinceJanuary 15, 2010, and Acting Senior Vice President of the Geosciences and Technology Division, and Acting VicePresident of the Exploration Planning Department since February 16, 2011. Before taking his current position, heserved as Vice President of the Geosciences Division, and Vice President of the Strategy and CapabilityDevelopment Division. He holds a master’s degree in Geophysics from Stanford University in the United States.

Mr. Asdakorn Limpiti has been Executive Vice President of the Strategy and Business Development Groupsince January 15, 2010. Before taking his current position, he was Vice President of the Strategy and CapabilityDevelopment Division and Vice President of the Bongkot Asset. He holds a master’s degree in ChemicalEngineering from the University of Michigan in the United States.

Mr. Somporn Vongvuthipornchai has been Executive Vice President of the International Assets Group sinceJanuary 15, 2010. Before taking his current position, he was Vice President of the International Assets Division,Vice President of the Production Development Division, and Vice President of the Geosciences Division. He holdsa doctorate in Petroleum Engineering from the University of Tulsa in the United States.

99

Mr. Prisdapunt Pojanapreecha has been Executive Vice President of the Engineering and Operations andSupply Chain Group since February 16, 2011. Before taking his current position, he was Executive Vice Presidentof the Engineering and Operations Support Group, Vice President of the Thai Offshore Assets Division, RegionalVice President of the Joint Venture and Thai Onshore Assets Division, and Vice President of the Human ResourcesDivision. He holds a bachelor degree in Geology from Chiangmai University.

Mr. Luechai Wongsirasawad has been Executive Vice President of the Human Resources, Reputation andBusiness Services Group since February 16, 2011. Before taking his current position, he was Executive VicePresident of the Human Resources and Business Services Group, Vice President of the Human Resources andBusiness Services Division and Vice President of Greater S1 Assets. He holds a bachelor’s degree (Honors) inElectrical Engineering from Chulalongkorn University.

Mr. Suraphong Iamchula has been Executive Vice President of the Domestic Assets Group since January15, 2010 and Acting Vice President of Development and Production Planning Department since February 16,2011. Before taking his current position, he was Vice President of the Operations Support Division, Vice Presidentof the Bongkot Asset, and Acting Vice President of the Bongkot Asset. He has a bachelor’s degree in Geology fromChiangmai University.

Ms. Penchun Jarikasem has been Executive Vice President of Finance and Accounting Group of PTTEPsince February 16, 2011. Before taking her current position, she was Executive Vice President of CorporateFinance of PTT, Vice President of Corporate Strategic Finance, Vice President of the Corporate Funding andFinancial Management Department. She has a bachelor’s degree from Chulalongkorn University and a Master ofBusiness Administration degree from Thammasat University.

Ms. Chanamas Sasnanand has been Vice President of the Finance Department since August 1, 2010. Beforetaking her current position, she was Acting Vice President of the Finance Group, Assistant Manager of InvestorRelations and Senior Financial Analyst. She has a master’s of science degree in Business Administration of theUniversity of South Carolina.

Sub-Committees

The board of directors appoints sub-committees with special knowledge and expertise to assist in thesupervision of PTTEP’s business, namely the Corporate Governance Committee, the Audit Committee, theRemuneration Committee, the Nominating Committee and the Risk Management Committee.

The Corporate Governance Committee

The Corporate Governance Committee consists of at least three directors and all members must beindependent directors. The Corporate Governance Committee proposes corporate governance policy, including thecode of business conduct, to the board of directors, reviews the Company’s corporate governance policy, advisesthe board of directors on matters concerning corporate governance and ensures that the duties, responsibilities andpractices of all directors and members of management comply with good corporate governance policies.

The Audit Committee

The Audit Committee consists of at least three directors and all members must be independent directors. Oneof whom must be knowledgeable in accounting and finance. The Audit Committee:

• reviews PTTEP’s financial statements to ensure accuracy and adequacy;

• ensures that PTTEP has a suitable and efficient internal control and internal audit system;

• reviews PTTEP’s performance to ensure compliance with securities and exchange laws, regulations ofthe Stock Exchange of Thailand and other laws relating to its business;

• considers, selects, nominates and recommends the remuneration of PTTEP’s external auditor andattends a non-management meeting with the external auditors at least once a year;

• considers connected transactions and potential conflicts-of-interest to ensure that they reasonablyaccord with the best interests of the Company;

• considers and approves the internal audit plan and budget of the Internal Audit Department; and

100

• performs any other act as assigned by the board of directors subject to the scope of work, duties andresponsibilities of the Audit Committee and PTTEP’s internal regulations.

The Remuneration Committee

The Remuneration Committee consists of at least three directors, of which the majority are independentdirectors, and the chairman is an independent director. The Remuneration Committee considers the procedures forfair and reasonable determination of remuneration for directors and members of the sub-committees and presentsthem at the shareholders’ meeting for approval. In addition, the Remuneration Committee evaluates the annualperformance of the President and Chief Executive Officer and proposes its findings to the board of directors forapproval. The Remuneration Committee also considers the remuneration of the President and Chief ExecutiveOfficer and salary structure of senior management and proposes them to the board of directors for approval.

The Nominating Committee

The Nominating Committee consists of at least three directors, the majority of whom must be independentdirectors. The chairman must be an independent director. The Nominating Committee selects qualified persons tobe nominated as new directors, or President and Chief Executive Officer and proposes their names to the boardof directors or at shareholders’ meetings. It also nominates directors for vacancies on sub-committees, determinesprocedures for the nomination of directors, or President and Chief Executive Officer so as to ensure transparencyand develops annual performance agreements for the Board, and President and Chief Executive Officer, with theannual assessment forms for the chairman, directors, sub-committees and President and Chief Executive Officer.

The Risk Management Committee

The Risk Management Committee consists of at least three directors and one of whom must be anindependent director. The Risk Management Committee formulates PTTEP’s risk management framework,advises the board of directors on issues relating to risk management and supervises enterprise-wide riskmanagement practices. It also considers the Company’s key risks, recommends risk-mitigating actions and reportsto the board of directors the outcome of its risk assessments and risk-mitigating actions.

Compensation

For the years ended December 31, 2008, 2009 and 2010, remuneration paid to PTTEP’s directors and seniormanagement as a group was Baht 159 million, Baht 156 million and Baht 186 million, respectively.

101

DESCRIPTION OF THE NOTES

The Notes will be issued under an indenture (the “Indenture”) to be dated as of April 5, 2011 (the “IssueDate”) between PTTEP Canada International Finance Limited (the “Issuer”), PTT Exploration and ProductionPublic Company Limited (“PTTEP”), as guarantor, and The Bank of New York Mellon, as trustee for the holdersof the Notes (the “Trustee”). The following summaries of certain provisions of the Notes and the Indenture arenot complete and are subject to, and are qualified in their entirety by reference to, all the provisions thereof,including the definitions therein of certain terms. Wherever particular sections or defined terms from the Notesor the Indenture are referred to, such sections or defined terms are incorporated herein by reference. Copies of theIndenture will be available upon request on or after the Issue Date from the Issuer or at the corporate trust officeof the Trustee and the Paying and Transfer Agent (as defined below).

General

The Notes will:

• constitute the Issuer’s direct, unconditional, unsecured and unsubordinated general obligations;

• rank equally among themselves, without any preference one over the other by reason of priority ofdate of issue or otherwise;

• be irrevocably and unconditionally guaranteed by PTTEP; and

• rank at least equally with all of the Issuer’s other outstanding unsecured and unsubordinated generalobligations.

The Guarantee will:

• constitute PTTEP’s direct, unconditional, unsecured and unsubordinated general obligation; and

• rank equally with all of PTTEP’s other outstanding unsecured and unsubordinated general obligations.

Principal, Maturity and Interest

The Notes will be issued in an initial aggregate principal amount of U.S.$700,000,000 and will mature ata price equal to 100% of their principal amount on April 5, 2021 (the “Maturity Date”), unless earlier redeemedpursuant to the terms thereof and the Indenture. The Notes will be issued in denominations of U.S.$200,000 andintegral multiples of U.S.$1,000 in excess thereof. The Notes will bear interest at a rate of 5.692% per annum fromand including the Issue Date or from the most recent interest payment date to which interest has been paid orprovided for.

The interest rate payable on the Notes will be subject to an increase of 1.00% upon the occurrence of aChange of Control Triggering Event (as defined herein). See “Description of the Notes — Principal, Maturity andInterest.” (the “Reset Interest Rate”). The Reset Interest Rate will have effect from and including the first interestpayment date following the date of the occurrence of such Change of Control Triggering Event and shall applyto all subsequent interest payment dates regardless of any future increase in the ratings of the Notes.

Interest on the Notes will be payable semi-annually in arrear on October 5 and April 5 of each year, up to,and excluding, the Maturity Date with the first interest payment to be made on October 5, 2011, to the person inwhose name such Note is registered at the close of business on the 15th calendar day prior to such interest paymentdate (whether or not a Business Day (as defined below)). In any case where the date for the payment of anyprincipal of or interest on any Note is not a day on which banking institutions are open for business in Singapore,London, Bangkok, Toronto and New York (a “Business Day”), then payment of such principal or interest need notbe made at such time and place of payment but may be made on the next succeeding Business Day with the sameforce and effect as if made on the date for such payment of principal or interest, and no interest will accrue forthe period after such date. All payments of principal of or interest on the Notes will be made in Dollars. Intereston the Notes will be computed on the basis of a 360-day year of twelve 30-day months.

Guarantee

PTTEP will fully, irrevocably and unconditionally guarantee (the “Guarantee”) to each holder of a Note thedue and punctual payment of the principal of and interest in respect of or on such note (and any AdditionalAmounts (as defined below) or other amounts payable in respect thereof), when and as the same shall become due

102

and payable, whether on an interest payment date, at the stated maturity date of the Note, by declaration ofacceleration, call for redemption, or otherwise, in accordance with the terms of such Note and of the Indenture,provided that any payment under the Guarantee shall be subject to, and conditional upon, the prior approval of theBank of Thailand for such payment having been obtained. The Guarantee will constitute a direct, unconditional(subject as provided above), unsecured and unsubordinated obligation of PTTEP and will rank equally with allother present and future unsecured and unsubordinated obligations of PTTEP, but in the event of insolvency, onlyto the extent permitted by applicable laws relating to creditors’ rights.

Optional Redemption

At any time, the Issuer may on any one or more occasions redeem all or a part of the Notes, upon not lessthan 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Notesredeemed, plus the Applicable Premium as of, and accrued and unpaid interest, if any, to the date of redemption,subject to the rights of holders of Notes on the relevant record date to receive interest due on the relevant interestpayment date.

Optional Tax Redemption

The Notes may be redeemable, in whole but not in part, at the Issuer’s option, upon not less than 30 nor morethan 60 days’ notice, at any time at a redemption price equal to:

• 100% of the aggregate principal amount of the Notes to be redeemed, plus;

• accrued interest to the date fixed for redemption.

if, as a result of any change in, expiration of or amendment to, the tax laws of the Kingdom of Thailand or Canada(or of any political subdivision or taxing authority thereof or therein) (each, a “Relevant Taxing Jurisdiction”) orany regulations or ruling promulgated thereunder or any change in the official interpretation or official applicationof such laws, regulations or rulings, or any change in the official application or interpretation of, or any executionof or amendment to, any treaty or treaties affecting taxation to which any Relevant Taxing Jurisdiction is a party(which change, execution, amendment or treaty becomes effective on or after April 5, 2011), the Issuer or PTTEPis, or would be, obligated on the next succeeding due date for a payment with respect to the Notes to payAdditional Amounts (as defined below) with respect to the Notes (or, in the case of PTTEP, the Guarantee) (orif Additional Amounts are payable by the Issuer or PTTEP as of April 5, 2011, the Issuer or PTTEP have or willbecome obligated to pay Additional Amounts in excess of any Additional Amounts which are payable by the Issueror PTTEP as of April 5, 2011) and such obligation cannot be avoided by the use of reasonable measures availableto the Issuer or PTTEP; provided, however, that (i) no such notice of redemption may be given earlier than 60 daysprior to the earliest date on which the Issuer or PTTEP would be obligated to pay such Additional Amounts, and(ii) at the time such notice of redemption is given, such obligation to pay such Additional Amounts remains ineffect. Prior to any redemption of the Notes, the Issuer will deliver to the Trustee a certificate and an opinion ofcounsel (which counsel is acceptable to the Trustee), to be made available for inspection by holders, stating thatthe Issuer is entitled to effect such redemption and setting forth a statement of facts showing that the conditionsprecedent to the right of redemption have occurred.

Additional Amounts

The Issuer, PTTEP and any successor of the Issuer or PTTEP (each, a “Payor”) will make all payments ofprincipal of and interest on the Notes and the Guarantee without withholding or deducting any present or futuretaxes, duties, assessments, fees or other governmental charges imposed by a Relevant Taxing Jurisdiction, unlesssuch withholding or deduction is required by law. In the event that any such withholding or deduction in respectof principal or interest is required by law, the Payor will pay additional amounts (“Additional Amounts”) asnecessary to ensure that you will receive the same amount as you would have received without any suchwithholding or deduction.

No Payor will pay, however, any Additional Amounts if you are liable for taxation because:

• you were or are connected with a Relevant Taxing Jurisdiction (including being a citizen or residentor national of, or carrying on a business or maintaining a permanent establishment in, or beingphysically present in, a Relevant Taxing Jurisdiction) other than by merely owning the Note orreceiving income or payments on the Note;

103

• you failed to (a) provide information concerning your nationality, residence or identity or (b) make anydeclaration or other similar claim or satisfy any information or reporting requirement, in the case ofeither (a) or (b), after any Payor or the relevant tax authority requested you to do so;

• you failed to present your Note for payment within 30 days of when the payment is due. Nevertheless,the relevant Payor will pay Additional Amounts to the extent you would have been entitled to suchamounts had you presented your Note for payment on the last day of the 30-day period;

• such withholding or deduction is imposed on a payment to an individual and is required to be madepursuant to European Council Directive 2003/48/EC or any European Union Directive implementingthe conclusions of the ECOFIN Council meetings of January 21, 2003, December 13, 2001 and/orNovember 26-27, 2000 on the taxation of savings income (the “Directive”) or any law implementingor complying with, or introduced in order to conform with, such Directive;

• you would have been able to avoid the withholding or deduction by the presentation (wherepresentation is required) of the relevant Note to, or otherwise accepting payment from, another payingagent in a member state of the European Union; or

• any combination of the above.

No Payor will pay any Additional Amounts for taxes on the Notes except for taxes payable throughdeduction or withholding from payments of principal or interest on the Notes. Examples of the types of taxes forwhich the Payors will not pay Additional Amounts include the following: estate or inheritance taxes, gift taxes,sales or transfer taxes, personal property or related taxes, assessments or other governmental charges. The relevantPayor will pay stamp or other similar taxes that may be imposed by any Relevant Taxing Jurisdiction, the UnitedStates or any political subdivision or taxing authority thereof on the Indenture or may be payable in connectionwith the issuance of the Notes or the Guarantee.

References to principal or interest in respect of the Notes will be deemed also to refer to any additionalamounts which may be payable as set forth in the Notes, the Guarantee, and the Indenture.

Certain Covenants

Limitation on Liens

So long as the Notes are outstanding, PTTEP will not, and PTTEP will not permit any of its Subsidiariesto, create, incur, issue or assume or guarantee any External Indebtedness secured by any Security Interest on anyPrincipal Property owned by it or any Restricted Subsidiary or on any shares of stock of any Restricted Subsidiary(such shares of stock of any Restricted Subsidiary being called “Restricted Securities”) without in any such caseeffectively providing that the Notes (together with, if PTTEP shall so determine, any other Indebtedness of PTTEPor its Subsidiaries then existing or thereafter created which is not subordinate to the Notes) will be secured equallyand ratably with or prior to such secured External Indebtedness unless, after giving effect thereto, the aggregateprincipal amount of all such secured External Indebtedness, plus PTTEP’s Attributable Debt and the AttributableDebt of PTTEP’s Restricted Subsidiaries in respect of sale and leaseback transactions involving PrincipalProperties as described under the covenant entitled “— Limitation Upon Sale and Leaseback Transactions,” wouldnot exceed 10% of PTTEP’s Consolidated Net Tangible Assets.

The foregoing restrictions will not apply to External Indebtedness secured by:

(i) any Security Interest existing on the date of the Indenture;

(ii) any Security Interest existing on any Principal Property or Restricted Securities prior to the acquisitionthereof by PTTEP or any of its Restricted Subsidiaries or arising after such acquisition pursuant tocontractual commitments entered into prior to, and not in contemplation of, such acquisition;

(iii) any Security Interest securing External Indebtedness incurred or assumed for the purpose of financingthe purchase price thereof or the cost of construction, improvement or repair of all or any part thereof,provided that such Security Interest attaches to such Principal Property concurrently with or within 12months after the acquisition thereof or the completion of construction, improvement or repair thereof;

104

(iv) any Security Interest existing on any Principal Property or Restricted Securities of any RestrictedSubsidiary prior to the time such Restricted Subsidiary becomes a Subsidiary of PTTEP or arisingafter such time pursuant to contractual commitments entered into prior to, and not in contemplationof, such Restricted Subsidiary becoming a Subsidiary of PTTEP; or

(v) any Security Interest arising out of the refinancing, extension, renewal or refunding of any ExternalIndebtedness secured by any Security Interest permitted by any of the foregoing clauses, to the extentof the amount of such External Indebtedness; provided that such External Indebtedness is not securedby any additional Principal Property.

Limitation Upon Sale and Leaseback Transactions

The Indenture provides that, after the Issue Date, neither PTTEP nor any Restricted Subsidiary may enterinto any arrangement with any Person providing for the leasing by PTTEP or any Restricted Subsidiary for aninitial term of three years or more of any Principal Property which has been or is to be sold or transferred to suchPerson or to any other Person to whom funds are advanced by such Person on the security of such PrincipalProperty for a sale price of U.S.$1,000,000 (or the equivalent thereof) or more (a “sale and leaseback transaction”)unless (i) PTTEP’s Attributable Debt and the Attributable Debt of PTTEP’s Restricted Subsidiaries in respectthereof and in respect of all other sale and leaseback transactions entered into after the date of the Indenture plusthe aggregate principal amount of External Indebtedness secured by Security Interests on Principal Properties andRestricted Securities then outstanding without equally and ratably securing the Notes, would not exceed 10% ofPTTEP’s Consolidated Net Tangible Assets; or (ii) PTTEP or a Restricted Subsidiary, within 12 months after suchsale and leaseback transaction, applies an amount equal to the net proceeds of such sale or transfer of the propertyor asset which is the subject of such sale and leaseback transaction to the retirement of PTTEP’s ExternalIndebtedness or that of a Restricted Subsidiary, as the case may be, which is not subordinate to the Notes, providedthat the amount to be applied will be reduced by (i) the principal amount of Notes delivered within 180 days aftersuch sale and leaseback transaction for retirement and cancellation, and (ii) the principal amount of PTTEP’sExternal Indebtedness or that of a Restricted Subsidiary, other than the Notes, voluntarily retired by PTTEP or aRestricted Subsidiary within 12 months after such sale and leaseback transaction. Notwithstanding the foregoing,no retirement referred to in this clause may be effected by payment at maturity or pursuant to any mandatorysinking fund payment or any mandatory prepayment provision.

Certain Definitions

“Applicable Premium” means, with respect to any Note on any redemption date, the greater of:

(1) 1.0% of the principal amount of the Note; or

(2) the excess of:

(a) the present value at such redemption date of (i) the principal amount of the Note plus (ii) allrequired interest payments due on the Note through April 5, 2021 (excluding accrued but unpaidinterest to the redemption rate), computed using a discount rate equal to the Treasury Rate as ofsuch redemption date plus 35 basis points; over

(b) the principal amount of the Note.

“Attributable Debt” means, as to any lease, at the date of determination, the lesser of (x) the fair marketvalue of the property or asset subject to such lease and (y) the total present value of the net amount of rent requiredto be paid under such lease during the remaining term thereof including renewal terms at the option of the lessor(excluding amounts on account of maintenance and repairs, insurance, taxes, assessments, water rates and similarcharges and contingent rents), discounted at a rate per annum equal to the discount rate of a capital lease obligationwith a like term in accordance with Thai GAAP.

“Change of Control” means PTT Public Company Limited, directly or indirectly, ceasing to own and controlat least 50.1% of PTTEP’s issued and outstanding capital stock.

“Change of Control Triggering Event” means the occurrence of both a Change of Control and a RatingsDecline.

105

“Consolidated Net Tangible Assets” means the total amount of the assets of PTTEP and its consolidatedSubsidiaries, including investments in unconsolidated Subsidiaries and associated companies, after deductingtherefrom (i) all current liabilities (excluding any current liabilities constituting Long-term Debt by reason of theirbeing renewable or extendible at the option of PTTEP or its consolidated Subsidiaries), and (ii) all goodwill, tradenames, trademarks, patents, unamortized debt discount and expense and other like intangible assets, all as set forthon the most recent balance sheet of PTTEP and its consolidated Subsidiaries and computed in accordance withThai GAAP.

“External Indebtedness” means any Indebtedness which is denominated in a currency other than thecurrency of the Kingdom of Thailand and which has a final maturity of one year or more from its date ofincurrence or issuance.

“Indebtedness” means any obligation for the payment or repayment of money borrowed.

“Long-term Debt” means any note, bond, debenture or other Indebtedness for money borrowed having amaturity of more than one year from the date such Indebtedness was incurred or having a maturity of less thanone year but by its terms being renewable or extendible, at the option of the borrower, beyond one year from thedate such evidence of Indebtedness was incurred.

“Moody’s” means Moody’s Investors Service, Inc. and its successors.

“Principal Property” means any oil or gas production, development or exploration facility or project ofPTTEP or any of its Subsidiaries, whether at the date of the Indenture owned or thereafter acquired, including anyland, buildings, structures or machinery and other fixtures that constitute any such facility, or portion thereof, otherthan any such facility, or portion thereof, reasonably determined by PTTEP’s board of directors not to be ofmaterial importance to the total business conducted by PTTEP and its Subsidiaries as a whole.

“Principal Subsidiary” means at any time a Subsidiary of PTTEP: (i) as to which one or more of thefollowing conditions is satisfied: (x) its net profits or (in the case of a Subsidiary of PTTEP which has one or moreSubsidiaries) consolidated net profits attributable to PTTEP (in each case before taxation and extraordinary items)are at least 5% of the consolidated net profits of PTTEP and its Subsidiaries (in each case before taxation andextraordinary items); or (y) its net assets or (in the case of a Subsidiary of PTTEP which has one or moreSubsidiaries) consolidated net assets attributable to PTTEP represent 5% or more of the consolidated net assets(after deducting minority interests in Subsidiaries) of PTTEP and its Subsidiaries; all as calculated by referenceto the then latest audited accounts (consolidated or, as the case may be, unconsolidated) of such Subsidiary andthe then latest consolidated audited accounts of PTTEP and its Subsidiaries, provided that: (1) in the case of aSubsidiary of PTTEP acquired after the end of the financial period to which the then latest relevant auditedaccounts relate, the reference to the then latest audited accounts for the purposes of the calculation above shall,until audited accounts for the financial period in which the acquisition is made are published, be deemed to be areference to the accounts adjusted to consolidate the latest audited accounts of the Subsidiary in the accounts; (2)if, in the case of a Subsidiary of PTTEP which itself has one or more Subsidiaries, no consolidated accounts areprepared and audited, its consolidated net assets and consolidated net profits shall be determined on the basis ofpro forma consolidated accounts of the relevant Subsidiary and its Subsidiaries prepared for this purpose andopined on by its auditors; (3) if the accounts of a Subsidiary of PTTEP (not being a Subsidiary referred to in (1)above) are not consolidated with those of PTTEP then the determination of whether or not the Subsidiary ofPTTEP is a Principal Subsidiary shall, if PTTEP requires, be based on a pro forma consolidation of its accounts(consolidated, if appropriate) with the consolidated accounts of PTTEP and its Subsidiaries; or (ii) to which istransferred the whole or substantially the whole of the assets and undertaking of a Subsidiary of PTTEP whichimmediately prior to the transfer was a Principal Subsidiary, provided that the Subsidiary of PTTEP which sotransfers its assets and undertaking shall forthwith upon the transfer cease to be a Principal Subsidiary (but withoutprejudice to clause (i) above) and the Subsidiary of PTTEP to which the assets and undertaking are so transferredshall become a Principal Subsidiary.

“Rating Agency” means any of (i) S&P and (ii) Moody’s; provided that (A) if either of S&P or Moody’s,but not both, will not make a rating of the Notes publicly available, one other “nationally recognized statisticalrating organization” that is registered as such pursuant to Section 15E of the Exchange Act and Rule 17gthereunder selected by PTTEP as a replacement agency will be substituted for S&P or Moody’s, as the case maybe; and (B) if both S&P and Moody’s will not make a rating of the Notes publicly available, two other “nationallyrecognized statistical rating organizations” that are registered as such pursuant to Section 15E of the Exchange Actand Rule 17g thereunder selected by PTTEP as a replacement agency.

106

“Rating Category” means (1) with respect to S&P, any of the following categories: “AAA,” “AA,” “A,”“BBB,” “BB,” “B,” “CCC,” “CC,” “C” and “D” (or equivalent successor categories); (2) with respect to Moody’s,any of the following categories: “Aaa,” “Aa,” “A,” “Baa,” “Ba,” “B,” “Caa,” “Ca,” and “C” (or equivalentsuccessor categories); and (3) the equivalent of any such category of S&P or Moody’s used by another RatingAgency. In determining whether the rating of the Notes has decreased by one or more gradations, gradations withinRating Categories (“+” and “-” for S&P; “1,” “2” and “3” for Moody’s; or the equivalent gradations for anotherRating Agency) shall be taken into account (e.g., with respect to S&P, a decline in a rating from “BB+” to “BB,”as well as from “B+” to “B-,” will constitute a decrease of one gradation).

“Ratings Decline” means, in connection with a Change of Control Triggering Event, the occurrence on, orwithin 90 days after, the earlier of the date, or public notice of the occurrence, of a Change of Control or theintention by PTT Public Company Limited to effect a Change of Control (which period will be extended so longas the rating of the Notes is under publicly announced consideration for possible downgrade by any of the RatingAgencies), the public announcement by either Rating Agency of a decrease in the rating of the Notes by one ormore gradations (including gradations within Rating Categories as well as between Rating Categories).

“Restricted Subsidiary” means any Subsidiary that owns a Principal Property and the Issuer.

“Security Interest” means any mortgage, pledge, lien, fixed or floating charge or other encumbrance.

“Subsidiary” means any corporation or other entity of which more than 50% of the total voting power ofshares, securities or other ownership interests entitled to vote in the election of the board of directors or otherpersons performing similar functions is at the time directly or indirectly owned by PTTEP.

“S&P” means Standard & Poor’s Rating Services, a division of the McGraw-Hill Companies, Inc. and itssuccessors.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date ofUnited States Treasury securities with a constant maturity (as compiled and published in the most recent FederalReserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to theredemption date (or, if such Statistical Release is no longer published, any publicly available source of similarmarket data)) most nearly equal to the period from the redemption date to April 5, 2021; provided, however, thatif the period from the redemption date to April 5, 2021, is less than one year, the weekly average yield on actuallytraded United States Treasury securities adjusted to a constant maturity of one year will be used.

Events of Default

The occurrence and continuance of the following events will constitute events of default (“Events ofDefault”) under the Indenture:

(i) failure to pay interest on the Notes as and when the same will become due and payable, and suchfailure continues for 30 days;

(ii) failure to pay principal on the Notes within 7 days as and when the same will become due and payable;

(iii) failure to perform any of the other covenants or agreements in the Indenture relating to the Notes thatcontinues for 60 days after written notice specifying such failure, stating that such notice is a “Noticeof Default” under the Notes and demanding the Issuer or PTTEP, as the case may be, remedy the same,is given to the Issuer or PTTEP by the Trustee or holders of at least 25% in aggregate principal amountof the outstanding Notes;

(iv) the Guarantee’s ceasing to be in full force and effect (except as contemplated by the terms hereof) orPTTEP or any Person acting by or on behalf of PTTEP denies or disaffirms in writing PTTEP’sobligations under the Indenture or the Guarantee (other than by reason of the termination of theIndenture or such Guarantee or the release of the Guarantee in accordance with the Guarantee or theIndenture);

(v) any of PTTEP’s or the Issuer’s External Indebtedness of an amount equal to or greater than U.S.$25million either (a) becoming due and payable by reason of acceleration following a default by PTTEPor the Issuer, as applicable, or (b) not being repaid by PTTEP or the Issuer, as applicable, andremaining unpaid, after maturity (as extended by the grace period, if any), or any guarantee given by

107

PTTEP or the Issuer in respect of any External Indebtedness of another person or entity of an amountequal to or greater than U.S.$25 million not being honored and remaining dishonored after becomingdue and called; provided that, if any such default has been cured or waived, the default under theIndenture will be deemed to have been cured and waived; or

(vi) certain events of bankruptcy, insolvency or court-ordered reorganization relating to PTTEP or theIssuer, or PTTEP or the Issuer ceasing to carry on the whole or substantially the whole of PTTEP orthe Issuer’s business.

If an event of default occurs and is continuing, the Trustee or the holders of not less than 25% in aggregateprincipal amount of the outstanding Notes may by written demand to the Issuer declare the principal amount tobe due and payable. In certain cases, the holders of more than 50% in aggregate principal amount of thenoutstanding Notes can rescind and annul such declaration and its consequences.

Subject to the provisions of the Indenture relating to the duties of the Trustee, the Trustee is not obligatedto exercise any of its rights or powers at the request or direction of any of its holders unless they have offered theTrustee security or indemnity satisfactory to the Trustee in its sole discretion. You may also not institute anyproceedings to enforce the Indenture (other than proceedings for enforcing payments of principal or interest)unless the Trustee has failed to act for 60 days after it receives notice of a default, a written instruction to act byholders of not less than 25% of the aggregate principal amount of the outstanding Notes and an offer of securityor indemnity satisfactory to the Trustee in its sole discretion. If the holders provide security or indemnitysatisfactory to the Trustee, the holders of more than 50% in aggregate principal amount of the then outstandingNotes during an event of default may direct the time, method and place of conducting any proceedings for anyremedy available to the Trustee under the Indenture or exercising any of the Trustee’s trusts or powers with respectto the Notes.

The Indenture provides that the Trustee will, with certain exceptions, notify the holders of the Notes of anyevent of default known to it within 90 days after the occurrence of such event.

The Issuer is required to file an annual statement with the Trustee concerning its compliance with theIndenture.

Consolidation, Merger and Sale of Assets

Both the Issuer and PTTEP may, without your consent, consolidate with or merge into, or sell or lease allor substantially all of the Issuer’s or PTTEP’s property to: (i) another direct or indirect subsidiary of PTTEPorganized under the laws of Canada (in the case of the Issuer) or (ii) another corporation organized under the lawsof the Kingdom of Thailand (in the case of PTTEP) as long as:

• any successor corporation expressly assumes the Issuer’s and/or PTTEP’s, as applicable, obligationsunder the Notes and the Indenture;

• the consolidation, merger, sale or lease does not create a default under the Indenture;

• in the case of the Issuer, PTTEP owns and controls, directly or indirectly, 100% of the Issuer’s issuedand outstanding shares following such consolidation, merger, or sale of assets; and

• certain other conditions in the Indenture are satisfied.

Defeasance and Discharge

The Issuer need not comply with certain restrictive covenants of the Indenture (including the limitations onliens and sale and leaseback transactions) with respect to the Notes, if:

(i) the Issuer deposits with the Trustee, in trust, money or U.S. government obligations (or a combinationthereof) sufficient to pay the principal of, and interest on, the Notes when due;

(ii) the Issuer is not in default under the Indenture;

(iii) the Issuer delivers to the Trustee an opinion of counsel to the effect that the deposit will not cause theholders of the Notes to recognize income, gain or loss for U.S. federal income tax purposes and theholders of the Notes will be subject to U.S. federal income tax on the same amounts, in the sameamounts and at the same times as if the deposit was not made;

108

(iv) the Issuer delivers to the Trustee an opinion of counsel to the effect that the holders of the Notes (otherthan holders who are deemed residents of the Kingdom of Thailand or Canada or who carry onbusiness in the Kingdom of Thailand or Canada) will not be subject to Thai or Canadian taxation andthat the payments out of the trust fund will be free and exempt from all withholding and other incometaxes of the Kingdom of Thailand and Canada; and

(v) the Issuer delivers to the Trustee an officer’s certificate and opinion of counsel stating that allconditions for the defeasance have been complied with.

In addition, the Issuer will be discharged from all of its obligations under the Notes (except for certainobligations to exchange or register the transfer of the Notes, replace stolen, lost or mutilated notes and maintainpaying agents) (“legal defeasance”) (a) if the Issuer delivers to the Trustee all the Notes for cancellation, togetherwith an opinion of counsel and an officer’s certificate stating that all conditions for the discharge have beencomplied with, and pays all other amounts payable under the Indenture, or (b) if all Notes not delivered to theTrustee for cancellation have become due and payable, will become due and payable within one year or are to becalled for redemption within one year, and the Issuer has irrevocably deposited with the Trustee, in trust, moneyor U.S. government obligations (or a combination thereof) sufficient to pay the principal of, and interest on, theNotes when due, together with an opinion of counsel and an officer’s certificate stating that all conditions fordischarge have been complied with, and pays all other amounts payable under the Indenture, provided that, underthe circumstances outlined in (a) or (b) above, the opinion described in (iii) above also confirms that (x) the Issuerhas received from, or there has been published by, the U.S. Internal Revenue Service a ruling or (y) since the IssueDate, there has been a change in the applicable U.S. federal income tax law, in either case to the effect that, andbased thereon such opinion of counsel will confirm that, the holders of the outstanding Notes will not recognizeincome, gain or loss for U.S. federal income tax purposes as a result of such legal defeasance and will be subjectto U.S. federal income tax on the same amounts, in the same amounts and at the same times as would have beenthe case if such legal defeasance had not occurred. In the event that the Issuer exercises its legal defeasance option,PTTEP will be released from all of its obligations with respect to its Guarantee.

Repurchase

PTTEP and any of its Subsidiaries (including the Issuer) may, in accordance with all applicable laws andregulations, at any time purchase the Notes in the open market or otherwise at any price. If purchases are madeby tender, such tender must be made available to all holders of the Notes alike. Any Notes PTTEP or any of itsSubsidiaries (including the Issuer) repurchase may be held, cancelled or sold.

Modification and Waiver

With the consent of the holders of more than 50% in aggregate principal amount of the outstanding Notes,the Issuer and PTTEP may execute supplemental indentures with the Trustee to add provisions or change oreliminate any provision of the Indenture, any supplemental indenture or the Guarantee or to modify the rights ofthe holders of the Notes. Without the consent of the holders of all the outstanding Notes, however, no suchsupplemental indenture will, with respect to the Notes:

• change their stated maturity;

• reduce the principal amount payable, reduce the stated rate of (including the Reset Interest Rate), orextend the stated time for payment of, interest on any Note;

• change the place or currency in which they are payable;

• impair the right to institute suit for their enforcement;

• reduce the percentage in principal amount of the outstanding Notes, the consent of the holders ofwhich is required for any such supplemental indenture, modification to the Guarantee or for anymodification to the provisions relating to modification and waiver; or

• modify the Guarantee in any manner adverse to the Holders of the Notes.

The holders of more than 50% in aggregate principal amount of the outstanding Notes may:

• waive compliance by the Issuer or PTTEP with certain provisions of the Indenture; and

109

• waive any past default under the Indenture (except defaults relating to payment of principal of orinterest on any Note).

Further Issuances

The Issuer may from time to time, without notice to or the consent of the holders of the Notes, create andissue further debt securities ranking pari passu with the Notes in all respects (or in all respects except for thepayment of interest accruing prior to the issue date of the debt securities or except for the first payment of interestfollowing the issue date of the debt securities). The Issuer may consolidate such further debt securities with theoutstanding Notes to form a single series; provided that, if any further debt securities issued are not fungible forU.S. federal income tax purposes with any Notes previously issued, such further debt securities shall tradeseparately from such previously issued Notes under a separate CUSIP number but shall otherwise be treated asa single series with all other Notes issued under the Indenture.

Replacement Notes

If a Note is mutilated, destroyed, lost or stolen, it may be replaced at the corporate trust office or agencyof the Trustee in New York or at the office of the Paying and Transfer Agent (as defined below). You will haveto pay any expenses incurred by the Issuer, PTTEP, the Trustee and the Paying and Transfer Agent and furnish anyevidence and indemnity that the Issuer, PTTEP, the Trustee and the Paying and Transfer Agent may require.Mutilated Notes must be surrendered before the Issuer will issue new Notes to you.

Notices

Any notice required to be given by the Issuer to a holder of a Note (which will be DTC’s nominee so longas the Notes are held in global form) will be mailed to the holder’s last address indicated in the security register.

Concerning the Trustee

The holders of more than 50% in aggregate principal amount of all outstanding Notes will have the rightto direct the time, method and place of conducting any proceeding for exercising any remedy or power availableto the Trustee with respect to the Notes. However, the direction must not conflict with any rule of law or with theIndenture.

In case of an event of default, the Trustee will be required to exercise its powers with the degree of care andskill of a prudent person in the conduct of his own affairs. The Trustee is, however, under no obligation to exerciseany of its rights or powers under the Indenture at the request of any of the holders of the Notes, unless they haveoffered to the Trustee security or indemnity satisfactory to the Trustee in its sole discretion.

The Bank of New York Mellon is the Trustee under the Indenture. The corporate trust office of the Trusteeis located at 101 Barclay Street, New York, N.Y. 10286, U.S.A.

Governing Law

The Indenture, the Notes and the Guarantee will be governed by, and construed in accordance with, the lawsof the State of New York. The Issuer and PTTEP have agreed that any legal suit, action or proceeding arising outof or based upon the Indenture or the Notes may be instituted in any state or federal court in the State and Cityof New York, United States of America.

Paying and Transfer Agent

The New York office of the Trustee will serve as the initial principal paying and transfer agent (the “Payingand Transfer Agent”). The Paying and Transfer Agent may resign at any time or may be removed by the Issuer.If the Paying and Transfer Agent is removed or becomes incapable of acting as a Paying and Transfer Agent orif a vacancy occurs in the office of the Paying and Transfer Agent for any cause, a successor Paying and TransferAgent will be appointed as provided by the Indenture. The Issuer will undertake to maintain a Paying Agent ina member state of the European Union that will not be obliged to withhold or deduct tax pursuant to the EuropeanUnion Directive 2003/48 EC or any other directive implementing the conclusions of the ECOFIN Councilmeetings of January 21, 2003, December 13, 2001 and/or November 26-27, 2000 on the taxation of savingsincome, or any law implementing, or complying with or introduced in order to conform to, such directive.

110

Book Entry, Delivery and Form

Global Notes

The Notes will be issued in fully registered form without interest coupons. Notes sold in offshoretransactions in reliance on Regulation S will initially be represented by one or more permanent global Notes indefinitive, fully registered form without interest coupons (each, a “Regulation S Global Note”) and will bedeposited with the Trustee as custodian for, and registered in the name of, a nominee of DTC (and, together withany successor, the “Depository”) for the accounts of Euroclear and Clearstream, Banking.

Notes sold in reliance on Rule 144A will be represented by one or more permanent global Notes indefinitive, fully registered form without interest coupons (each, a “Rule 144A Global Note” and, together with theRegulation S Global Note, the “Global Notes”) and will be deposited with the Trustee as custodian for, andregistered in the name of, a nominee of DTC.

Each Global Note (and any Notes issued in exchange therefor) will be subject to certain restrictions ontransfer set forth therein as described under “Transfer Restrictions.” Except in the limited circumstances describedbelow under “— Certificated Notes,” owners of beneficial interests in the Global Notes will not be entitled toreceive physical delivery of Certificated Notes (as defined below). The Notes are not issuable in bearer form.

Ownership of beneficial interests in the Global Notes will be limited to persons who have accounts withDTC (“participants”) or persons who hold interests through participants. Ownership of beneficial interests in theGlobal Notes will be shown on, and the transfer of that ownership will be effected only through, recordsmaintained by DTC or its nominee (with respect to interests of participants) and the records of participants (withrespect to interests of persons other than participants). Qualified institutional buyers may hold their interests inRule 144A Global Notes directly through DTC if they are participants in such system, or indirectly throughorganizations which are participants in such system.

Investors may hold their interests in a Regulation S Global Note directly through Euroclear or Clearstream,Banking, if they are participants in such systems, or indirectly through organizations that are participants in suchsystems. Euroclear and Clearstream, Banking will hold interests in the Regulation S Global Notes on behalf oftheir participants through DTC.

So long as DTC, or its nominee, is the holder of the Global Notes, DTC or such nominee, as the case maybe, will be considered the sole owner or holder of the Notes represented by the Global Notes for all purposes underthe Indenture and the Notes. No beneficial owner of an interest in a Global Note will be able to transfer thatinterest except in accordance with DTC’s applicable procedures, in addition to those provided for under theIndenture and, if applicable, those of Euroclear and Clearstream, Banking.

Payments of the principal of, or interest on, the Global Notes will be made to DTC or its nominee, as thecase may be, as the holder thereof. None of the Issuer, PTTEP, the Trustee or any Paying and Transfer Agent (asdefined above) will have any responsibility or liability for any aspect of the records relating to or payments madeon account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing anyrecords relating to such beneficial ownership interests.

The Issuer expects that DTC or its nominee, upon receipt of any payment on the Global Notes, will creditparticipants’ accounts with payments in amounts proportionate to their respective beneficial interests in the statedprincipal amount of the Global Notes as shown on the records of DTC or its nominee. The Issuer also expects thatpayments by participants to owners of beneficial interests in the Global Notes held through such participants willbe governed by standing instructions and customary practices, as is now the case with securities held for theaccounts of customers registered in the names of nominees for such customers. Such payments will be theresponsibility of such participants.

Transfers between participants in DTC will be effected in the ordinary way in accordance with DTC rulesand will be settled in same-day funds. Transfers between participants in Euroclear and Clearstream, Banking willbe effected in the ordinary way in accordance with their respective rules and operating procedures. See “— TheClearing Systems” below.

111

The Issuer expects that DTC will take any action permitted to be taken by a holder of Notes only at thedirection of one or more participants to whose account the DTC interests in the Global Notes is credited and onlyin respect of such portion of the aggregate stated principal amount of the Global Notes as to which such participantor participants has or have given such direction. However, if there is an Event of Default under the Notes, DTCwill exchange the Global Notes for certificates representing the Notes, which it will distribute to its participantsand which may be legended as set forth under “Notice to Investors.”

Certificated Notes

If (i) DTC notifies the Issuer that it is unwilling or unable to continue as a depositary for such Rule 144AGlobal Note or Regulation S Global Note, as the case may be, and a successor depositary is not appointed by theIssuer within 90 days of such notice, (ii) any of DTC, Euroclear or Clearstream, Banking or a successor clearingsystem is closed for business for a continuous period of 14 days (other than by reason of holidays, statutory orotherwise) or announces an intention permanently to cease business or does in fact do so, or (iii) an Event ofDefault has occurred and is continuing, the Issuer will issue certificates representing the Notes (“CertificatedNotes”) in registered form in exchange for the Rule 144A Global Note and the Regulation S Global Note, as thecase may be. Upon receipt of such notice from DTC, Euroclear, Clearstream, Banking or the Trustee, as the casemay be, the Issuer will use its best efforts to make arrangements for the exchange of interests in the relevant GlobalNote for Certificated Notes and cause the requested Certificated Notes to be executed and delivered to the Payingand Transfer Agent in sufficient quantities and delivered to the Paying and Transfer Agent for delivery to holders.

A Certificated Note may be transferred in whole or in part (in a principal amount equal to the minimumauthorized denomination or any integral multiple thereof) by surrendering such Certificated Note to be transferred,together with an executed instrument or assignment of transfer, at the corporate trust office of the Trustee or atthe office of the Paying and Transfer Agent in New York. In the case of a permitted transfer of only part of aCertificated Note, a new Certificated Note in respect of the balance not transferred will be issued to the transferor.Each new Certificated Note to be issued upon the transfer of a Certificated Note will, upon the effective receiptof a duly completed form of transfer by a Paying and Transfer Agent at its respective specified office, be availablefor delivery three business days after issuance at such specified office, or at the request of the holder requestingsuch transfer, will be mailed at the risk of the transferee entitled to the new Certificated Note to such address asmay be specified in such duly completed form of transfer. The transfer of the Certificated Notes will be effectedwithout charge by or on behalf of the Issuer or any Paying and Transfer Agent but against such indemnity as theIssuer or the Paying and Transfer Agent may require in respect of any tax or other duty of whatever nature whichmay be levied or imposed in connection with such transfer.

The Clearing Systems

General

DTC, Euroclear and Clearstream, Banking have advised the Issuer as follows:

DTC. DTC is a limited-purpose trust company organized under the laws of the State of New York, a memberof the Federal Reserve System, a “clearing corporation” within the meaning of the New York UniformCommercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the ExchangeAct. DTC was created to hold securities of its participants and to facilitate the clearance and settlement ofsecurities transactions among its participants in such securities through electronic book-entry changes in accountsof participants, thereby eliminating the need for physical movement of securities certificates. DTC’s participantsinclude securities brokers and dealers, banks, trust companies, clearing corporations, and certain otherorganizations, some of whom own DTC, and may include the Initial Purchaser. Indirect access to the DTC systemis also available to others that clear through or maintain a custodial relationship with a DTC participant, eitherdirectly or indirectly. Transfers of ownership or other interests in Notes in DTC may be made only through DTCparticipants. In addition, beneficial owners of Notes in DTC will receive all distributions of principal of, or intereston, the Notes from the Trustee through such DTC participant.

Euroclear. Euroclear was created in 1968 to hold securities for its participants and to clear and settletransactions between its participants through simultaneous electronic book-entry delivery against payment,thereby eliminating the need for physical movement of certificates and any risk from lack of simultaneoustransfers of securities and cash. Euroclear includes various other services, including securities lending andborrowing, and interfaces with domestic markets in several countries. Euroclear is operated by Euroclear BankS.A./N.V. (the “Euroclear Operator”), under contract with Euroclear Clearance Systems, S.C., a Belgiancooperative corporation (the “Cooperative”). All operations are conducted by the Euroclear Operator, and all

112

Euroclear securities clearance accounts and Euroclear cash accounts are accounts with the Euroclear Operator, notthe Cooperative. The Cooperative establishes policy for Euroclear on behalf of Euroclear participants. Euroclearparticipants include banks (including central banks), securities brokers and dealers and other professional financialintermediaries and may include the Initial Purchaser. Indirect access to Euroclear is also available to others thatclear through or maintain a custodial relationship with a Euroclear participant, either directly or indirectly.

The Euroclear Operator was granted a banking license by the Belgian Banking and Finance Commission in2000, authorizing it to carry out banking activities on a global basis. It took over operation of Euroclear from theBrussels, Belgium office of Morgan Guaranty Trust Company of New York on December 31, 2000.

Securities clearance accounts and cash accounts with the Euroclear Operator are governed by the Terms andConditions Governing Use of Euroclear and the related Operating Procedures of the Euroclear System, andapplicable Belgian law (collectively, the “Terms and Conditions”). The Terms and Conditions govern transfers ofsecurities and cash within Euroclear, withdrawals of securities and cash from Euroclear, and receipts of paymentswith respect to securities in Euroclear. All securities in Euroclear are held on a fungible basis without attributionof specific certificates to specific securities clearance accounts. The Euroclear Operator acts under the Terms andConditions only on behalf of Euroclear participants and has no record of or relationship with persons holdingthrough Euroclear participants.

Distributions with respect to the Notes held beneficially through Euroclear will be credited to the cashaccounts of Euroclear participants in accordance with the Terms and Conditions, to the extent received byEuroclear.

Clearstream, Banking. Clearstream, Banking is incorporated under the laws of the Grand Duchy ofLuxembourg as a professional depositary. Clearstream, Banking holds securities for its participants and facilitiesthe clearance and settlement of securities transactions between its participants through electronic book-entrychanges in accounts of its participants, thereby eliminating the need for physical movement of certificates.Clearstream, Banking provides to its participants, among other things, services for safekeeping, administration,clearance and settlement of internationally traded securities and securities lending and borrowing. Clearstream,Banking interfaces with domestic markets in several countries. As a professional depositary, Clearstream, Bankingis subject to regulation by the Luxembourg Monetary Institute. Clearstream, Banking participants are financialinstitutions around the world, including securities brokers and dealers, banks, trust companies, clearingcorporations and certain other organizations and may include the Initial Purchaser. Indirect access to Clearstream,Banking is also available to others that clear through or maintain a custodial relationship with a Clearstream,Banking participant either directly or indirectly.

Distributions with respect to the Notes held beneficially through Clearstream, Banking will be credited tocash accounts of Clearstream, Banking participants in accordance with its rules and procedures, to the extentreceived by Clearstream, Banking.

Initial Settlement

Initial settlement for the Notes will be made in immediately available funds. All Notes issued in the formof Global Notes will be deposited with the Trustee, as custodian for DTC. Investors’ interests in Notes held inbook-entry form by DTC will be represented through financial institutions acting on their behalf as direct andindirect participants in DTC. As a result, Euroclear and Clearstream, Banking will initially hold positions on behalfof their participants through DTC.

Investors electing to hold their Notes through DTC (other than through accounts at Euroclear or Clearstream,Banking) must follow the settlement practices applicable to United States corporate debt obligations. Thesecurities custody accounts of investors will be credited with their holdings against payment in same-day fundson the settlement date.

Investors electing to hold their Notes through Euroclear or Clearstream, Banking accounts will follow thesettlement procedures applicable to conventional Eurobonds in registered form. Notes will be credited to thesecurities custody accounts of Euroclear holders and of Clearstream, Banking holders on the business dayfollowing the settlement date against payment for value on the settlement date.

113

Secondary Market Trading

Because the purchaser determines the place of delivery, it is important to establish at the time of trading ofany Notes where both the purchaser’s and seller’s accounts are located to ensure that settlement can be made onthe desired value date.

Trading between DTC participants. Secondary market trading between DTC participants will occur in theordinary way in accordance with DTC rules and will be settled using the procedures applicable to United Statescorporate debt obligations in same-day funds using DTC’s Same Day Funds Settlement System.

Trading between Euroclear and/or Clearstream, Banking participants. Secondary market trading betweenEuroclear participants and/or Clearstream, Banking participants will occur in the ordinary way in accordance withthe applicable rules and operating procedures of Euroclear and Clearstream, Banking and will be settled using theprocedures applicable to conventional Eurobonds in same-day funds.

Trading between DTC seller and Euroclear or Clearstream, Banking purchaser. When Notes are to betransferred from the account of a DTC participant to the account of a Euroclear participant or a Clearstream,Banking participant, the purchaser must send instructions to Euroclear or Clearstream, Banking through aparticipant at least one business day prior to settlement. Euroclear or Clearstream, Banking, as the case may be,will receive the Notes against payment. Payment will then be made to the DTC participant’s account againstdelivery of the Notes. After settlement has been completed, the Notes will be credited to the respective clearingsystem and by the clearing system, in accordance with its usual procedures, to the Euroclear participant’s orClearstream, Banking participant’s account. Credit for the Notes will appear on the next day (European time) andcash debit will be back-valued to, and the interest on the Notes will accrue from, the value date (which would bethe preceding day when settlement occurs in New York). If settlement is not completed on the intended value date(i.e., the trade date fails), the Euroclear or Clearstream, Banking cash debit will be valued instead as of the actualsettlement date.

Euroclear participants or Clearstream, Banking participants will need to make available to the respectiveclearing systems the funds necessary to process same-day funds settlement. The most direct means of doing so isto pre-position funds for settlement, either from cash on hand or existing lines of credit, as they would for anysettlement occurring within Euroclear or Clearstream, Banking. Under this approach, they may take on creditexposure to Euroclear or Clearstream, Banking until the Notes are credited to their accounts one day later.

As an alternative, if Euroclear or Clearstream, Banking has extended a line of credit to them, participantscan elect not to pre-position funds and allow that credit line to be drawn upon to finance settlement. Under thisprocedure, Euroclear participants or Clearstream, Banking participants purchasing Notes would incur overdraftcharges for one day, assuming they cleared the overdraft when the Notes were credited to their accounts. However,interest on the Notes would accrue from the value date. Therefore, in many cases, the investment income on Notesearned during that one-day period may substantially reduce or offset the amount of such overdraft charges,although this result will depend on each participant’s particular cost of funds.

Because the settlement is taking place during New York business hours, DTC participants can employ theirusual procedures for sending Notes to the relevant depositary for the benefit of Euroclear participants orClearstream, Banking participants. The sale proceeds will be available to the DTC seller on the settlement date.Thus, to the DTC participant, a cross-market transaction will settle no differently than a trade between two DTCparticipants.

Finally, day traders that use Euroclear or Clearstream, Banking and that purchase Notes from DTCparticipants for credit to Euroclear participants or Clearstream, Banking participants should note that these tradeswill automatically fail on the sale side unless affirmative action is taken. At least three techniques should be readilyavailable to eliminate this potential problem:

(1) borrowing through Euroclear or Clearstream, Banking for one day (until the purchase side of the daytrade is reflected in their Euroclear account or Clearstream, Banking account) in accordance with theclearing system’s customary procedures;

(2) borrowing the Notes in the United States from a DTC participant no later than one day prior tosettlement, which would give the Notes sufficient time to be reflected in the borrower’s Euroclearaccount or Clearstream, Banking account in order to settle the sale side of the trade; or

114

(3) staggering the value dates for the buy and sell sides of the trade so that the value date for the purchasefrom the DTC participant is at least one day prior to the value date for the sale to the Euroclearparticipants or Clearstream, Banking participants.

Trading between Euroclear or Clearstream, Banking seller and DTC purchaser. Due to the time zonedifferences in their favor, Euroclear participants or Clearstream, Banking participants may employ their customaryprocedures for transactions in which Notes are to be transferred by the respective clearing system to another DTCparticipant. The seller must send instructions to Euroclear or Clearstream, Banking through a participant at leastone business day prior to settlement. In these cases, Euroclear or Clearstream, Banking will credit the Notes tothe DTC participant’s account against payment. Payment will then be made to the DTC participant’s accountagainst delivery of the Notes. The payment will then be reflected in the account of the Euroclear participant orClearstream, Banking participant the following day, and receipt of the cash proceeds in the Euroclear orClearstream, Banking participant’s account will be back-valued to the value date (which would be the precedingday when settlement occurs in New York). If the Euroclear participant or Clearstream, Banking participant has aline of credit with its respective clearing system and elects to draw on such line of credit in anticipation of receiptof the sale proceeds in its account, the back-valuation may substantially reduce or offset any overdraft chargesincurred over the one-day period. If settlement is not completed on the intended value date (i.e., the trade fails),receipt of the cash proceeds in the Euroclear or Clearstream, Banking participant’s account would instead bevalued as of the actual settlement date.

As in the case with respect to sales by a DTC participant to a Euroclear or Clearstream, Banking participant,participants in Euroclear and Clearstream, Banking will have their accounts credited the day after their settlementdate. See “— Trading between DTC Seller and Euroclear or Clearstream, Banking purchaser” above.

Although DTC, Euroclear and Clearstream, Banking are expected to follow the foregoing procedures inorder to facilitate transfers of interests in the Global Notes among participants of DTC, Euroclear and Clearstream,Banking, they are under no obligation to perform or continue to perform such procedures, and such proceduresmay be discontinued at any time. Neither the Issuer, PTTEP, the Trustee nor any Paying and Transfer Agent willhave any responsibility for the performance by DTC, Euroclear or Clearstream, Banking or their respectiveparticipants or indirect participants of their respective obligations under the rules and procedures governing theiroperations.

115

TAXATION

Canadian Taxation

In the opinion of Stikeman Elliott LLP, counsel to the Issuer and the Guarantor (“Counsel”) the followingis a summary of the principal Canadian federal income tax considerations under the Income Tax Act (Canada) andregulations thereunder (together, the “Tax Act”) generally applicable to a purchaser who (i) is, at all relevant timesfor purposes of the Tax Act and any applicable tax treaty or convention, neither resident nor deemed to be residentin Canada; (ii) deals at arm’s length and is not affiliated with either the Issuer or the Guarantor; and (iii) holds suchNotes as capital property (a “Non-Resident Holder”). The Notes will generally be considered to be capital propertyto a Non-Resident Holder unless either the Non-Resident Holder holds such securities in the course of carryingon a business, or the Non-Resident Holder has held or acquired such Notes in a transaction or transactionsconsidered to be an adventure or concern in the nature of trade.

This summary is not applicable to a Non-Resident Holder (i) that is a “financial institution” for purposes ofthe “mark-to-market” rules in the Tax Act; (ii) an interest in which is a “tax shelter investment”; (iii) that haselected to report its “Canadian tax results” in a currency other than the Canadian currency; or (iv) that carries onan insurance business in Canada and elsewhere. In addition, this summary may not apply to a Non-ResidentHolder in respect of a disposition of a Note to a holder resident or deemed to be resident in Canada for the purposesof the Tax Act and with whom the Non-Resident Holder does not deal with at arm’s length. Non-Resident Holdersto whom this paragraph may apply should consult their own tax advisors.

This summary is based upon the current provisions of the Tax Act, and Counsel’s understanding of thecurrent published administrative policies and assessing practices of the Canada Revenue Agency. This summaryalso takes into account all specific proposals to amend the Tax Act that have been publicly announced by or onbehalf of the Minister of Finance (Canada) prior to the date hereof (the “Tax Proposals”), and assumes that all suchTax Proposals will be enacted in the form proposed. No assurance can be given that the Tax Proposals will beenacted as proposed or at all. Except for the Tax Proposals, this summary does not take into account or anticipateany changes in law or administrative policy or assessing practice, whether by way of legislative, judicial,regulatory or administrative action or interpretation, nor does it address any provincial or territorial taxconsiderations.

The following summary is of a general nature only and is not intended to be, and should not be consideredto be, legal or tax advice to any prospective investor and no representation with respect to the tax consequencesto any particular investor is made. Accordingly, prospective investors should consult with their own tax advisorsfor advice with respect to the income tax consequences to them of purchasing, holding or disposing of the Noteshaving regard to their own particular circumstances.

Taxation of Interest on Notes

A Non-Resident Holder will not be subject to Canadian withholding tax in respect of amounts paid orcredited by the Issuer as, on account or in lieu of payment of, or in satisfaction of, interest, principal or premiumon the Notes.

Disposition of Notes

A Non-Resident Holder will not be subject to tax under the Tax Act in respect of any capital gain realizedby such Non-Resident Holder on a disposition or deemed disposition of a Note.

Thailand Taxation

This summary contains a description of the principal Thai income tax consequences of the purchase,ownership and disposition of the Notes by an individual or corporate holder of the Notes that is not a resident ofThailand, not organized under Thai law, nor engaged in business in Thailand through a permanent establishment,employees, agents or representatives in Thailand. It does not purport to be a comprehensive description of all ofthe tax considerations that may be relevant to a decision to purchase the Notes. The summary is based upon thetax laws of Thailand in effect on the date of this Offering Memorandum.

116

PROSPECTIVE HOLDERS OF THE NOTES SHOULD CONSULT THEIR OWN PROFESSIONALADVISORS CONCERNING THE CONSEQUENCES OF THE ACQUISITION, OWNERSHIP ANDDISPOSITION OF THE NOTES, INCLUDING THE CONSEQUENCES UNDER THAI LAW, THE LAWS OFTHE JURISDICTION OF WHICH THEY ARE RESIDENT AND ANY TAX TREATY BETWEEN THAILANDAND THEIR COUNTRY OF RESIDENCE FOR TAX PURPOSES.

The Thai taxation in this summary may apply only to the payment made to the holders of the Notes byPTTEP pursuant to its obligations under the Guarantee if such payment is considered payment of interest from orin Thailand. As a result, such payment may be subject to Thai withholding tax. The tax liability of a prospectiveholder of the Notes and the applicable rates of tax will depend on various factors such as whether the holder ofthe Notes is a company or an individual, whether the holder of the Notes is a resident of Thailand or is deemedto carry on business in Thailand and, if not, whether the holder of the Notes is a resident of a country which hasa double tax treaty with Thailand.

Income Tax

Non-resident Individual Investors

In considering whether the individual holder of the Notes is a resident of Thailand, Thai law does not lookat the nationality of such individual holder of the Notes, but will determine whether the holder of the Notes hasresided in Thailand for a period or periods aggregating 180 days or more in any tax year.

Interest paid on the Notes in or from Thailand to a non-resident individual holder of the Notes will be subjectto a withholding tax at the rate of 15% of the gross amount of the interest payment, unless the terms and conditionsof a double taxation agreement between Thailand and the resident country of such non-resident individual holderof the Notes provide otherwise.

Unless the terms and conditions of a double taxation agreement between Thailand and the resident countryof such non-resident individual holder of the Notes provide otherwise, capital gains, which is the amount in excessof the cost of acquisition, arising on a transfer of the Notes and paid in or from Thailand, which will be subjectto a withholding tax at the rate of 15% of the capital gains. The transferee or the payer of the gain has a duty towithhold tax at such rate on payments of gain in respect of the transfer of the Notes.

Non-resident Corporate Investors

In the case of a company or registered partnership established pursuant to a foreign law which does notengage in business in Thailand but receives income paid in or from Thailand in the nature of interest or a capitalgain arising on a transfer of the Notes by a holder of the Notes in Thailand, a payer of such income must withholdtax at the rate of 15% on any such payment, unless the terms and conditions of a double taxation agreementbetween Thailand and the resident country of such non resident corporate holder of the Notes provide otherwise.

Income tax on individuals or companies who are tax residents of countries having double tax treaties withThailand

Presently, Thailand has double taxation treaties with 54 countries. Both individual and corporate holders ofthe Notes, who are regarded as tax residents of such countries and receive interest payments in respect of theNotes, will be subject to withholding tax, at the rate of 15%. The rate of withholding tax, however, may be reducedto 10% depending on the terms of the particular tax treaty.

A limited number of corporate holders of the Notes resident in such a country for tax purposes and nothaving a permanent establishment in Thailand may be entitled to an exemption from Thai capital gains tax for thecapital gain received from or within Thailand depending on the terms and conditions of the particular tax treaty.

Specific Business Tax

Interest of the Notes or gains received by the holders of the Notes who carries on certain businesses inThailand may be subject to a specific business tax (SBT) plus municipal tax imposed on top of such SBT if suchinterest or gains are considered to be income generated from commercial banking or any other specific law, andundertaking of finance business, securities business and credit foncier business under the laws governing financebusiness, securities business and credit foncier business or a business similar to that commercial banking.

117

Stamp Duty

No stamp duty is charged on transfer of the Notes (i.e., debentures).

United States Federal Income Taxation

TO ENSURE COMPLIANCE WITH INTERNAL REVENUE SERVICE CIRCULAR 230, THEISSUER HEREBY INFORMS YOU THAT: (A) ANY UNITED STATES FEDERAL TAX DISCUSSION INTHIS OFFERING MEMORANDUM WAS NOT WRITTEN AND IS NOT INTENDED OR WRITTEN TOBE USED AND CANNOT BE USED BY ANY TAXPAYER FOR PURPOSES OF AVOIDING UNITEDSTATES FEDERAL INCOME TAX PENALTIES THAT MAY BE IMPOSED ON THE TAXPAYER; (B)ANY SUCH TAX DISCUSSION WAS WRITTEN TO SUPPORT THE PROMOTION OR MARKETINGOF THE NOTES TO BE ISSUED PURSUANT TO THIS OFFERING MEMORANDUM AND (C) EACHTAXPAYER SHOULD SEEK ADVICE BASED ON THE TAXPAYER’S PARTICULARCIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISER.

General

The following is a summary of certain material U.S. federal income tax consequences that may be relevantwith respect to the acquisition, ownership and disposition of the Notes. This summary addresses only the U.S.federal income tax considerations of holders that acquire the Notes at their original issuance at the initial offeringprice, and that will hold the Notes as capital assets.

This summary does not address all U.S. federal income tax matters that may be relevant to a particularholder of the Notes (a “Noteholder”). In particular, this summary does not address tax considerations applicableto Noteholders that may be subject to special tax rules in light of their particular circumstances, including, withoutlimitation, the following: (i) financial institutions; (ii) insurance companies; (iii) dealers or traders in stocks,securities, currencies or notional principal contracts; (iv) tax-exempt entities; (v) regulated investment companies;(vi) real estate investment trusts; (vii) persons that will hold the Notes as part of a “hedging” or “conversion”transaction or as a position in a “straddle” or as part of a “synthetic security” or other integrated transaction forU.S. federal income tax purposes; (viii) persons that own (or are deemed to own) 10% or more of PTTEP’s votingshares (or interests treated as equity); (ix) persons whose “functional currency” is not the U.S. dollar; (x)partnerships, pass-through entities, or persons who hold the Notes through partnerships or other pass-throughentities; and (xi) U.S. expatriates and former long-term residents of the United States. Further, this summary doesnot address federal estate, gift or alternative minimum tax consequences, or the indirect effects on the holders ofequity interests in a Noteholder. This summary also does not describe any tax consequences arising under the lawsof any taxing jurisdictions other than the federal income tax laws of the U.S. federal government.

This summary is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), final,temporary and proposed U.S. Treasury Regulations and judicial and administrative interpretations thereof, and theConvention Between the Government of the United States of America and the Government of the Kingdom ofThailand for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with respect to Taxes onIncome (the “Thailand Treaty”) as in effect and available on the date of this Offering Memorandum. All of theforegoing is subject to change, which change could apply retroactively and could affect the tax consequencesdescribed below.

Prospective investors should consult their own tax advisers with respect to the U.S. federal, state, localand foreign tax consequences of acquiring, owning or disposing of the Notes. U.S. Holders should alsoreview the discussions under “Thailand Taxation” and “Canadian Taxation” for the Thai or Canadian taxconsequences to a U.S. Holder of holding the Notes.

For the purposes of this summary, a “U.S. Holder” is a beneficial owner of Notes that is, for U.S. federalincome tax purposes:

(a) an individual citizen or resident of the United States;

(b) a corporation, including an entity treated as a corporation for U.S. federal income tax purposes, createdor organized in or under the laws of the United States or any state thereof (including the District ofColumbia);

(c) an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

118

(d) a trust if (x) a court within the United States is able to exercise primary supervision over itsadministration and (y) one or more United States persons have the authority to control all of thesubstantial decisions of such trust. As provided in U.S. Treasury Regulations, certain trusts inexistence on August 20, 1996, and treated as United States persons prior to that date that maintain avalid election to continue to be treated as United States persons also are U.S. Holders.

A “Non-U.S. Holder” is a beneficial owner of Notes that is not a U.S. Holder. If a partnership holds Notes,the U.S. federal income tax treatment of a partner generally will depend upon the status of the partner and theactivities of the partnership. A partner of a partnership holding Notes should consult its tax advisor concerning theU.S. federal income tax consequences of acquiring, owning or disposing of the Notes by the partnership.

Payments of Interest

It is anticipated that the Notes will not be issued at a discount in excess of the statutory de minimis amount;therefore, the Notes will not be considered to have been issued with original issue discount (“OID”) within themeaning of Section 1273 of the Code. If this is the case, interest on a Note will be taxable to a U.S. Holder asordinary interest income at the time it is received or accrued, depending on the U.S. Holder’s method ofaccounting for U.S. federal income tax purposes. A U.S. Holder will also be required to include in income anyadditional amounts and any tax withheld from interest payments on the Notes, notwithstanding the fact that suchU.S. Holder does not receive such withheld tax. Subject to certain conditions and limitations, any tax withheld oninterest may be deducted from taxable income or credited against a U.S. Holder’s U.S. federal income tax liability.Interest on a Note, including additional amounts and any tax withheld, received by a U.S. Holder will be treatedas foreign source income for purposes of calculating such holder’s foreign tax credit limitation. The limitation onforeign taxes eligible for the U.S. foreign tax credit is calculated separately with respect to specific classes ofincome. The rules governing the foreign tax credit are complex. Potential investors are urged to consult theirown tax advisers regarding the availability of a foreign tax credit with respect to any Thai or Canadianwithholding tax and the applicability of the Thailand Treaty with respect to any Thai withholding tax undertheir particular circumstances.

Sale, Exchange or Other Disposition of the Notes

A U.S. Holder’s tax basis in a Note generally will be its U.S. dollar cost. Upon the sale, exchange orretirement of a Note, a U.S. Holder will generally recognize capital gain or loss equal to the difference betweenthe amount realized (not including any amounts attributable to accrued and unpaid interest, which will be treatedlike a payment of interest, as described above) and the U.S. Holder’s tax basis in the Note. Prospective investorsshould consult their own tax advisors with respect to the treatment of capital gains (which may be taxed atlower rates than ordinary income for taxpayers who are individuals that have held the Notes for more thanone year) and capital losses (the deductibility of which is subject to limitations) .

Any gain or loss recognized by a U.S. Holder generally will be U.S. source capital gain or loss (except tothe extent such amounts are attributable to accrued but unpaid interest). Consequently, a U.S. Holder may not beable to claim a credit for any Thai tax imposed upon a disposition of a Note unless, subject to applicablelimitations, such credit (i) can be claimed under the Thailand Treaty by a U.S. Holder entitled to benefits underthe Treaty or (ii) can be applied against tax due on other income treated as derived from foreign sources. U.S.Holders are urged to consult with their own tax advisers regarding the availability of a foreign tax creditand the applicability of the Thailand Treaty with respect to any Thai withholding tax under their particularcircumstances.

Taxation of Non-U.S. Holders

Subject to the backup withholding tax discussion below, a Non-U.S. Holder generally should not be subjectto U.S. federal income or withholding tax on any payments on the Notes and gain from the sale, exchange or otherdisposition of the Notes unless (i) that payment and/or gain is effectively connected with the conduct by thatNon-U.S. Holder of a trade or business within the United States; or (ii) in the case of any gain realized by anindividual Non-U.S. Holder, that holder is present in the United States for 183 days or more in the taxable yearof the sale or other disposition and certain other conditions are met. Non-U.S. Holders should consult their owntax advisers regarding the U.S. federal income and other tax consequences of owning and disposing of the Notes.

119

Information Reporting and Backup Withholding

Backup withholding and information reporting requirements may apply to certain payments of principal andinterest on a Note, and to proceeds of the sale of a Note, made to certain U.S. Holders that are beneficial ownersof Notes. PTTEP, PTTEP’s agent, a broker, or any paying agent, as the case may be, may be required to withholdtax from any payment if the U.S. Holder fails (i) to furnish the U.S. Holder’s taxpayer identification number, (ii)to certify that such U.S. Holder is not subject to backup withholding or (iii) to otherwise comply with theapplicable requirements of the backup withholding rules. Certain U.S. Holders (including, among others,corporations) are generally not subject to the backup withholding and information reporting requirements withrespect to these payments. Non-U.S. Holders who hold their Notes through a U.S. broker or agent or through theU.S. office of a non-U.S. broker or agent may be required to comply with applicable certification procedures toestablish that they are not U.S. Holders in order to avoid the application of such information reportingrequirements and backup withholding. Backup withholding is not an additional tax. Any amounts withheld underthe backup withholding rules generally may be claimed as a credit against such holder’s U.S. federal income taxliability provided that the required information is furnished to the IRS. Noteholders should consult their own taxadvisers as to their qualification for exemption from backup withholding and the procedure for obtaining anexemption.

Recently Enacted Legislation

Under recently enacted legislation, individuals that own “specified foreign financial assets” with anaggregate value in excess of U.S.$50,000 in taxable years beginning after March 18, 2010 will generally berequired to file an information report with respect to such assets with their tax returns. “Specified foreign financialassets” include any financial accounts maintained by foreign financial institutions, as well as any of the following,but only if they are not held in accounts maintained by financial institutions: (i) stocks and securities issued bynon-U.S. persons, (ii) financial instruments and contracts held for investment that have non-U.S. issuers orcounterparties and (iii) interests in foreign entities. U.S. Holders that are individuals are urged to consult their taxadvisors regarding the application of this legislation to their ownership of the Notes.

In addition, for taxable years beginning after December 31, 2012, a U.S. holder that is an individual, estateor trust will generally be subject to a 3.8% tax on the lesser of (1) the U.S. holder’s net investment income forthe relevant taxable year and (2) the excess of the U.S. holder’s modified gross income for the taxable year overa certain threshold. U.S. Holders that are individuals, estates or trusts are urged to consult their tax advisorsregarding the applicability of this tax to their investment in the Notes.

120

PLAN OF DISTRIBUTION

Subject to the terms and subject to the conditions contained in a purchase agreement dated March 29, 2011,the Initial Purchaser has agreed to purchase from the Issuer, and the Issuer has agreed to sell to such InitialPurchaser, the principal amount of the Notes set forth opposite the name of such Initial Purchaser.

Initial Purchaser Principal Amount

Barclays Bank PLC ................................................................................................................. U.S.$700,000,000

Total. ....................................................................................................................................... U.S.$700,000,000

The purchase agreement provides that the several obligations of the Initial Purchaser to purchase the Notesare subject to approval of certain legal matters by counsel and to certain other conditions. The Initial Purchasermust purchase all of the Notes if they purchase any of the Notes.

The Initial Purchaser initially proposes to offer the Notes for resale at the issue price that appears on thecover of this Offering Memorandum. After the initial Offering, the Initial Purchaser may change the offering priceand any other selling terms. The Initial Purchaser may offer and sell Notes through certain of its affiliates.

In the purchase agreement, the Issuer has agreed, among other things, that:

• for a period of 90 days after the date of the initial offering of the Notes by the Initial Purchaser, neitherthe Issuer nor PTTEP will offer, sell, contract to sell, pledge or otherwise dispose of, directly orindirectly, any United States dollar-denominated debt securities issued or guaranteed by the Issuer orPTTEP and having a maturity of more than one year from the date of issue; and

• it will indemnify the Initial Purchaser against certain liabilities, including liabilities under theSecurities Act, or contribute to payments that such Initial Purchaser may be required to make inrespect of those liabilities.

You should be aware that the laws and practices of certain countries require investors to pay stamp taxes andother charges in connection with purchases of securities.

No registration under the Securities Act or in Canada

The Notes and the Guarantee have not been and will not be registered under the Securities Act, and may notbe offered or sold within the United States except in certain transactions exempt from the registration requirementsof the Securities Act. Terms used in this paragraph have the meanings given to them by Regulation S.

The Notes are being offered and sold outside of the United States to non-U.S. persons in reliance onRegulation S. The Purchase Agreement provides that the Initial Purchaser may directly or through its U.S.broker-dealer affiliates arrange for the offer and resale of the Notes within the United States only to QIBs inreliance on Rule 144A.

The Notes have not been and will not be registered in any jurisdiction in Canada and may not be offeredor sold in Canada or to or for the benefit of any resident thereof except to Accredited Investors or, as the case maybe, Permitted Clients.

Each purchaser of the Notes will be deemed to have made the acknowledgements, representations andagreements as described under “Transfer Restrictions” in this Offering Memorandum.

New issue of Notes

The Notes are a new issue of securities, and there is currently no established trading market for the Notes.In addition, the Notes are subject to certain restrictions on resale and transfer as described under “TransferRestrictions.” Approval-in-principle has been received for the listing of the Notes on the SGX-ST. However, theIssuer cannot assure you that such listing will be obtained or maintained. The Issuer is entitled to seek analternative listing for the Notes on a stock exchange other than the SGX-ST, approved by the Trustee, if listingof the Notes on the SGX-ST is not obtained or if compliance with the rules of SGX-ST becomes undulyburdensome for the Issuer. The Initial Purchaser has advised the Issuer that it currently intends to make a marketin the Notes as permitted by applicable law, but it is not obligated to do so. The Initial Purchaser may discontinueany market making activities with respect to the Notes at any time in its sole discretion without notice. In addition,

121

such market-making activity will be subject to the limits imposed by the Securities Act and the Exchange Act.Accordingly, the Issuer cannot assure you that a liquid trading market will develop for the Notes, that you will beable to sell your Notes at a particular time or that the prices that you receive when you sell your Notes will befavorable.

Price stabilization, short positions and penalty bids

The Initial Purchaser or its affiliates may engage in over-allotment, stabilizing transactions, syndicatecovering transactions and penalty bids to the extent permitted by applicable laws and regulations. Over-allotmentinvolves sales in excess of the offering size, which creates a short position. Stabilizing transactions permit bidsto purchase the Notes so long as the stabilizing bids do not exceed a specified maximum. Covering transactionsinvolve purchase of the Notes in the open market after the distribution has been completed in order to cover shortpositions. Penalty bids permit the Initial Purchaser to reclaim a selling concession from a dealer when the Notesoriginally sold by such dealer are purchased in a stabilizing transaction or a covering transaction to cover shortpositions. Neither the Issuer nor the Initial Purchaser or its affiliates make any representation or prediction as tothe direction or magnitude of any effect that the transactions described above may have on the price of the Notes.

Stabilizing transactions and covering transactions may cause the price of the Notes to be higher than it wouldotherwise be in the absence of those transactions. In addition, neither the Issuer nor the Initial Purchaser makesany representation that the Initial Purchaser will engage in these transactions or that these transactions, oncecommenced, will not be discontinued without notice.

Other relationships

From time to time, in the ordinary course of business, the Initial Purchaser and its affiliates have providedadvisory, lending and investment banking services, and entered into other commercial transactions, such ashedging transactions, with the Company and its subsidiaries and affiliates for which customary compensation hasbeen received. It is expected that the Initial Purchaser and its affiliates will continue to provide such services to,and enter into such transactions with, the Company and its subsidiaries and affiliates in the future.

The Initial Purchaser or certain of its affiliates may purchase the Notes and be allocated Notes for assetmanagement and/or proprietary purposes and not with a view to distribution.

Selling restrictions

General

The Initial Purchaser has undertaken to the Issuer and the Company that it will comply with all applicablelaws and regulations in each country or jurisdiction in which it purchases, offers, sells or delivers the Notes or hasin its possession or distributes this Offering Memorandum (in preliminary, proof or final form) or any otheroffering material related to the Notes and the related Guarantee.

No action has been taken or will be taken in any jurisdiction by the Issuer or the Initial Purchaser that wouldpermit a public offering of the Notes, or the possession, circulation or distribution of this Offering Memorandumor any other material relating to the Notes, the related Guarantee, or this Offering, in any jurisdiction where actionfor that purpose is required. Accordingly, the Notes may not be offered or sold, directly or indirectly, and neitherthis Offering Memorandum nor such other material may be distributed or published, in or from any country orjurisdiction, except in compliance with any applicable rules and regulations of such country or jurisdiction.

United States

The Initial Purchaser has acknowledged that the Notes have not been registered under the Securities Act orthe securities laws of any other place.

The Initial Purchaser has acknowledged that the Notes may not be offered or sold within the United Statesor to U.S. persons except pursuant to an exemption from the registration requirements of the Securities Act or intransactions not subject to those registration requirements.

The Initial Purchaser has represented, warranted and agreed that, during the initial distribution of the Notes,it will offer or sell Notes only to QIBs in compliance with Rule 144A, in accordance with Regulation S or anyother available exemption from registration under the Securities Act.

122

In addition, until 40 days following the commencement of this Offering, an offer or sale of Notes and therelated Guarantee within the United States by a dealer (whether or not participating in the Offering) may violatethe registration requirements of the Securities Act unless the dealer makes the offer or sale in compliance withRule 144A or another exemption from registration under the Securities Act.

Canada

The Notes have not been registered in any jurisdiction in Canada. The Notes may only be offered under anexemption from the requirement to file a prospectus with the securities regulatory authorities in each province ofCanada where the securities are offered and sold and therein only by Initial Purchasers or their affiliates that areproperly registered under applicable provincial law or, alternatively, that are entitled to rely on exemptions fromthe dealer registration requirements in each such province of Canada.

United Kingdom

The Initial Purchaser has represented, warranted and agreed that:

(a) it has only communicated or caused to be communicated and will only communicate or cause to becommunicated an invitation or inducement to engage in investment activity (within the meaning ofSection 21 of the Financial Services and Market Act 2000 (the “FSMA”)) received by it in connectionwith the issue or sale of the Notes in circumstances in which Section 21(1) of the FSMA does notapply to the Issuer or the Company; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anythingdone by it in relation to the Notes in, from or otherwise involving, the United Kingdom.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the ProspectusDirective (each, a “Relevant Member State”), the Initial Purchaser has represented and agreed that with effect fromand including the date on which the Prospectus Directive is implemented in that Relevant Member State (the“Relevant Implementation Date”) it has not made and will not make an offer of Notes which are the subject ofthe Offering contemplated by this Offering Memorandum to the public in that Relevant Member State other than:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not soauthorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the lastfinancial year; (2) a total balance sheet of more than EUR43,000,000; and (3) an annual net turnoverof more than EUR50,000,000, as shown in its last annual or consolidated accounts;

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the ProspectusDirective) subject to obtaining the prior consent of the Initial Purchaser; or

(d) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer of Notes shall require the Issuer, the Company or any Initial Purchaser to publish aprospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 ofthe Prospectus Directive.

For the purposes of this provision, the expression an “offer of Notes to the public” in relation to any Notesin any Relevant Member State means the communication in any form and by any means of sufficient informationon the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribethe Notes, as the same may be varied in that Member State by any measure implementing the Prospectus Directivein that Member State and the expression “Prospectus Directive” means Directive 2003/71/EC and includes anyrelevant implementing measure in each Relevant Member State.”

123

Hong Kong

The Initial Purchaser has represented, warranted and agreed that:

(i) it has not offered or sold and will not offer or sell in Hong Kong, by means of any document, anyNotes other than (a) to “professional investors” as defined in the Securities and Futures Ordinance(Cap. 571) (the “SFO”) of Hong Kong and any rules made under the SFO; or (b) in othercircumstances which do not result in the document being a “prospectus” as defined in the CompaniesOrdinance (Cap. 32) of Hong Kong or which do not constitute an offer to the public within themeaning of that Ordinance; and

(ii) it has not issued or had in its possession for the purposes of issue, and will not issue or have in itspossession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement,invitation or document relating to the Notes, which is directed at, or the contents of which are likelyto be accessed or read by, the public of Hong Kong (except if permitted to do so under the securitieslaws of Hong Kong) other than with respect to Notes which are or are intended to be disposed of onlyto persons outside Hong Kong or only to “professional investors” as defined in the SFO and any rulesmade under thereunder.

Japan

The Initial Purchaser has represented, warranted and agreed that the Notes have not been and will not beregistered under the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended; the“FIEL”) and may not be offered or sold directly or indirectly, in Japan or to, or for the benefit of, any resident ofJapan (which term as used herein means any person resident in Japan, including any corporation or other entityorganized under the laws of Japan) or to others for re-offering or resale, directly or indirectly, in Japan or to, orfor the benefit of, a resident of Japan, except pursuant to an exemption from the registration requirements of, andotherwise in compliance with the FIEL and any other applicable laws, regulations and ministerial guidelines ofJapan.

Thailand

The Initial Purchaser has represented, warranted and agreed that it has not offered or sold and will not offeror sell any Notes in the Kingdom of Thailand and has not made and will not make any invitation in the Kingdomof Thailand to subscribe for the Notes.

Singapore

The Initial Purchaser acknowledges that the Offering Memorandum has not been and will not be registeredas a prospectus with the Monetary Authority of Singapore, and the Notes will be offered pursuant to exemptionsunder the Securities and Futures Act, Chapter 289 of Singapore (the “Securities and Futures Act”). Accordingly,the Initial Purchaser represents and agrees that it has not offered or sold any Notes or caused the Notes to be madethe subject of an invitation for subscription or purchase and will not offer or sell any Notes or cause the Notes tobe made the subject of an invitation for subscription or purchase, and has not circulated or distributed, nor willit circulate or distribute, the Offering Memorandum or any document or material in connection with the offer orsale, or invitation for subscription or purchase, of any Notes, whether directly or indirectly, to any person inSingapore other than (a) to an institutional investor pursuant to Section 274 of the Securities and Futures Act, (b)to a relevant person under Section 275(1) of the Securities and Futures Act, or to any person pursuant to Section275(1A) of the Securities and Futures Act and in accordance with the conditions specified in Section 275 of theSecurities and Futures Act, or (c) otherwise pursuant to, and in accordance with the conditions of, any otherapplicable provision of the Securities and Futures Act.

Each of the following persons specified in Section 275 of the Securities and Futures Act which hassubscribed or purchased Notes, namely a person who is:

(a) a corporation (which is not an accredited investor (as defined in Section 4A of the Securities andFutures Act)) the sole business of which is to hold investments and the entire share capital of whichis owned by one or more individuals, each of whom is an accredited investor; or

(b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments andeach beneficiary is an individual who is an accredited investor,

124

should note that securities (as defined in Section 239(1) of the Securities and Futures Act) of that corporationor the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable for 6months after that corporation or that trust has acquired the Notes under Section 275 of the Securities andFutures Act except:

(i) to an institutional investor or to a relevant person defined in Section 275(2) of the Securities andFutures Act, or (in the case of a corporation) where the transfer arises from an offer referred toin Section 276(3)(i)(B) of the Securities and Futures Act or (in the case of a trust) where thetransfer arises from an offer referred to in Section 276(4)(i)(B) of the Securities and Futures Act;

(ii) where no consideration is or will be given for the transfer;

(iii) where the transfer is by operation of law; or

(iv) pursuant to Section 276(7) of the Securities and Futures Act.

125

TRANSFER RESTRICTIONS

The Notes are subject to restrictions on transfer as summarized below. By purchasing Notes, you will bedeemed to have made the following acknowledgements, representations to, and agreements with, the Issuer, theCompany and the Initial Purchaser:

1. You understand and acknowledge that:

1. the Notes and the related Guarantee have not been registered under the Securities Act or anyother applicable securities laws;

2. the Notes and the related Guarantee are being offered for resale in transactions that do notrequire registration under the Securities Act or any other securities laws; and

3. unless so registered, the Notes and the related Guarantee may not be offered, sold or otherwisetransferred except under an exemption from, or in a transaction not subject to, the registrationrequirements of the Securities Act or any other applicable securities laws, and in each case incompliance with the conditions for transfer set forth in paragraph (4) below.

2. You represent that you are not an affiliate (as defined in Rule 144 under the Securities Act) of theIssuer, that you are not acting on the Issuer’s behalf and that either:

1. you are a “qualified institutional buyer” (as defined in Rule 144A under the Securities Act) andare purchasing Notes for your own account or for the account of another qualified institutionalbuyer, commonly referred to as “QIBs”, and you are aware that the Initial Purchaser is sellingthe Notes to you in reliance on Rule 144A; or

2. you are purchasing Notes in an offshore transaction in accordance with Regulation S.

3. You acknowledge that neither the Issuer, the Company nor the Initial Purchaser nor any personrepresenting the Issuer, the Company or the Initial Purchaser has made any representation to you withrespect to the Issuer, the Company or the Offering, other than the information contained in thisOffering Memorandum. You represent that you are relying only on this Offering Memorandum inmaking your investment decision with respect to the Notes. You agree that you have had access to suchfinancial and other information concerning the Issuer, the Company and the Notes as you have deemednecessary in connection with your decision to purchase Notes, including an opportunity to askquestions of, and request information from, the Issuer and/or the Company.

4. You represent that you are purchasing Notes for your own account, or for one or more investoraccounts for which you are acting as a fiduciary or agent, in each case not with a view to, or for offeror sale in connection with, any distribution of the Notes in violation of the Securities Act. You agreeon your own behalf and on behalf of any investor account for which you are purchasing Notes, andeach subsequent holder of the Notes by its acceptance of the Notes will agree, that until the end of theResale Restriction Period (as defined below), the Notes may be offered, sold or otherwise transferredonly:

(a) to the Issuer;

(b) under a registration statement that has been declared effective under the Securities Act;

(c) for so long as the Notes are eligible for resale under Rule 144A, to a person the seller reasonablybelieves is a QIB that is purchasing for its own account or for the account of another QIB andto whom notice is given that the transfer is being made in reliance on Rule 144A; or

(d) under any other available exemption from the registration requirements of the Securities Act;

subject in each of the above cases to any requirement of law that the disposition of the seller’s propertyor the property of an investor account or accounts be at all times within the seller or account’s controland in compliance with applicable state and other securities laws.

126

5. You also acknowledge that:

• the above restrictions on resale will apply from the closing date until the date that is one year(in the case of Rule 144A Notes) after the later of the closing date and the last date that the Issueror any of its affiliates was the owner of the Notes or any predecessor of the Notes (the “ResaleRestriction Period”), and will not apply after the applicable Resale Restriction Period ends;

• the Issuer and the Trustee reserve the right to require in connection with any offer, sale or othertransfer of Notes under clause (d) above the delivery of an opinion of counsel, certificationsand/or other information satisfactory to the Issuer and the Trustee; and

• each Note will contain a legend substantially to the following effect:

THE NOTES HAVE NOT BEEN REGISTERED UNDER THE U.S. SECURITIES ACT OF1933, AS AMENDED (THE “SECURITIES ACT”), OR THE SECURITIES LAWS OF ANYSTATE OR OTHER JURISDICTION, INCLUDING, WITHOUT LIMITATION, THE LAWSOF CANADA OR ANY PROVINCE OR TERRITORY THEREOF. NEITHER THE NOTESNOR ANY INTEREST OR PARTICIPATION HEREIN MAY BE REOFFERED, SOLD,ASSIGNED, TRANSFERRED, PLEDGED, ENCUMBERED OR OTHERWISE DISPOSEDOF IN THE ABSENCE OF SUCH REGISTRATION OR UNLESS SUCH TRANSACTION ISEXEMPT FROM, OR NOT SUBJECT TO, SUCH REGISTRATION.

THE HOLDER OF THE NOTES, BY ITS ACCEPTANCE HEREOF, AGREES ON ITS OWNBEHALF AND ON BEHALF OF ANY INVESTOR ACCOUNT FOR WHICH IT HASPURCHASED THE NOTES, TO OFFER, SELL OR OTHERWISE TRANSFER SUCHNOTES, PRIOR TO THE DATE (THE “RESALE RESTRICTION TERMINATION DATE”)THAT IS [IN THE CASE OF RULE 144A NOTES: ONE YEAR] AFTER THE LATER OF THEORIGINAL ISSUE DATE HEREOF AND THE LAST DATE ON WHICH PTTEP CANADAINTERNATIONAL FINANCE LIMITED (THE “COMPANY”) OR ANY AFFILIATE OF THECOMPANY WAS THE OWNER OF THE NOTES (OR ANY PREDECESSOR OF THENOTES), ONLY (A) TO THE COMPANY, (B) PURSUANT TO A REGISTRATIONSTATEMENT THAT HAS BEEN DECLARED EFFECTIVE UNDER THE SECURITIESACT, (C) FOR SO LONG AS THE NOTES ARE ELIGIBLE FOR RESALE PURSUANT TORULE 144A UNDER THE SECURITIES ACT, TO A PERSON IT REASONABLY BELIEVESIS A “QUALIFIED INSTITUTIONAL BUYER” AS DEFINED IN RULE 144A UNDER THESECURITIES ACT THAT PURCHASES FOR ITS OWN ACCOUNT OR FOR THEACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER TO WHOM NOTICE IS GIVENTHAT THE TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A UNDER THESECURITIES ACT, (D) PURSUANT TO OFFERS AND SALES THAT OCCUR OUTSIDETHE UNITED STATES WITHIN THE MEANING OF REGULATION S UNDER THESECURITIES ACT AND, IF TO A RESIDENT OF CANADA, PURSUANT TO ANEXEMPTION FROM ANY APPLICABLE REQUIREMENT TO FILE A PROSPECTUS INANY JURISDICTION IN CANADA, OR (E) PURSUANT TO ANOTHER AVAILABLEEXEMPTION FROM THE REGISTRATION REQUIREMENTS OF THE SECURITIES ACT,SUBJECT TO THE COMPANY’S AND THE TRUSTEE’S RIGHT PRIOR TO ANY SUCHOFFER, SALE OR TRANSFER PURSUANT TO CLAUSES (D) OR (E) TO IS REQUIRETHE DELIVERY OF AN OPINION OF COUNSEL, CERTIFICATION AND/ OR OTHERINFORMATION SATISFACTORY TO EACH OF THEM. THIS LEGEND WILL BEREMOVED UPON THE REQUEST OF THE HOLDER AFTER THE RESALERESTRICTION TERMINATION DATE. [IN THE CASE OF REGULATION S NOTES: BY ITSACQUISITION HEREOF, THE HOLDER HEREOF REPRESENTS THAT IT IS ACQUIRINGTHE NOTES IN AN OFFSHORE TRANSACTION IN ACCORDANCE WITH REGULATION SUNDER THE SECURITIES ACT. ]

YOU REPRESENT THAT EITHER (I) NO PORTION OF THE ASSETS USED BY YOU TOACQUIRE AND HOLD THE NOTES CONSTITUTES ASSETS OF (A) ANY EMPLOYEEBENEFIT PLAN SUBJECT TO SECTION 406 OF THE U.S. EMPLOYEE RETIREMENTINCOME SECURITY ACT OF 1974, AS AMENDED (“ERISA”), (B) ANY PLAN,ACCOUNT OR OTHER ARRANGEMENT SUBJECT TO SECTION 4975 OF THE U.S.INTERNAL REVENUE CODE OF 1986, AS AMENDED (THE “CODE”), (C) ANY ENTITYWHOSE UNDERLYING ASSETS ARE DEEMED FOR PURPOSE OF ERISA OR THE

127

CODE TO INCLUDE “PLAN ASSETS” BY REASON OF SUCH PLAN INVESTMENT INTHE ENTITY, OR (D) ANY EMPLOYEE BENEFIT PLAN SUBJECT TO ANY FEDERAL,STATE, LOCAL, NON-U.S. OR OTHER LAWS OR REGULATIONS THAT ARE SIMILARTO SUCH PROVISIONS OF ERISA OR THE CODE (COLLECTIVELY, “SIMILAR LAWS”),OR (II) THE PURCHASE AND HOLDING OF THE NOTES OR ANY INTERESTSTHEREIN BY YOU WILL NOT CONSTITUTE A NON-EXEMPT PROHIBITEDTRANSACTION UNDER SECTION 406 OF ERISA OR SECTION 4975 OF THE CODE ORA VIOLATION UNDER ANY APPLICABLE SIMILAR LAW.

THE HOLDER OF THE NOTES AGREES FOR THE BENEFIT OF THE COMPANY THATIF IT RESELLS THE NOTES INTO THAILAND, IT WILL RESELL SUCH NOTES ONLYTO QUALIFIED INSTITUTIONAL INVESTORS, AS DEFINED UNDER THE BANK OFTHAILAND REGULATIONS, WHO HAVE OBTAINED APPROVAL FROM THE BANK OFTHAILAND TO INVEST IN FOREIGN CURRENCY DENOMINATED NOTES. SUCHQUALIFIED INSTITUTIONAL INVESTORS CURRENTLY INCLUDE: (I) THEGOVERNMENT PENSION FUND, (II) THE SOCIAL SECURITY FUND, (III) PROVIDENTFUNDS, (IV) MUTUAL FUNDS (EXCLUDING PRIVATE FUNDS), (V) SECURITIESCOMPANIES PURCHASING NOTES FOR THEIR OWN ACCOUNTS OR OTHERINVESTORS’ ACCOUNTS, (VI) INSURANCE COMPANIES, (VII) FINANCIALINSTITUTIONS ESTABLISHED UNDER SPECIFIC ACTS, AND (VIII) LEGAL ENTITIESWHOSE PRINCIPAL BUSINESS IS MANUFACTURING, TRADING OR SERVICES ANDHAVING ASSETS ON THEIR BALANCE SHEETS OF AT LEAST BAHT 5 BILLION.

6. You represent and agree that:

(i) (a) you are not a resident of Canada; or

(b) if you are a resident of Canada you are an Accredited Investor or, as the case may be, aPermitted Client; and

(ii) you have been advised that the Issuer is relying on an exemption from the requirement toprovide you with a prospectus under applicable securities laws in Canada and that protectionsotherwise provided by such laws, including statutory rights of recession, will not be availableto you.

7. You acknowledge that the Issuer, the Company, the Initial Purchaser and others will rely upon the truthand accuracy of the above acknowledgments, representations and agreements. You agree that if anyof the acknowledgments, representations or agreements you are deemed to have made by yourpurchase of Notes is no longer accurate, you will promptly notify the Issuer, the Company and theInitial Purchaser. If you are purchasing any Notes as a fiduciary or agent for one or more investoraccounts, you represent that you have sole investment discretion with respect to each of those accountsand that you have full power to make the above acknowledgments, representations and agreements onbehalf of each account.

8. You acknowledge, understand and agree that: (a) you will, and each subsequent purchaser is requiredto, notify any subsequent purchaser of the Notes from you of the resale restrictions referred to in (4)above; and (b) no representation can be made as to the availability of any exemption provided by Rule144A for resale of the Notes.

9. You acknowledge that if you resell the Notes into Thailand, you will resell such Notes only to qualified“Investors,” as defined under the Bank of Thailand regulations, who have obtained approval from theBank of Thailand to invest in foreign currency denominated notes. Such qualified institutionalinvestors currently include: (i) the Government Pension Fund, (ii) the Social Security Fund, (iii)provident funds, (iv) mutual funds (excluding private funds), (v) securities companies purchasingNotes for their own accounts or other investors’ accounts, (vi) insurance companies, (vii) financialinstitutions established under specific acts, and (viii) legal entities whose principal business ismanufacturing, trading or services and having assets on their balance sheets of at least Baht 5 billion.

128

LEGAL MATTERS

Certain matters in connection with this offering as to New York law and U.S. federal law will be passed uponfor the Issuer and the Guarantor by Allen & Overy and for the Initial Purchaser by Clifford Chance. Certainmatters in connection with this offering as to Thai law will be passed upon for the Issuer and the Guarantor byAllen & Overy (Thailand) Co., Ltd., and for the Initial Purchaser by Clifford Chance (Thailand) Limited. Certainlegal matters in connection with this offering as to matters of Canadian law will be passed upon for the Issuer andthe Guarantor by Stikeman Elliott LLP.

129

INDEPENDENT ACCOUNTANTS

PTTEP’s audited consolidated financial statements as of and for the years ended December 31, 2008, 2009and 2010 have been included in this Offering Memorandum in reliance upon the reports of the Office of theAuditor General of Thailand, the auditor for state enterprises, dated February 17, 2009, February 17, 2010 andFebruary 17, 2011, and upon the authority of said office as experts in accounting and auditing. The Office of theAuditor General is the independent auditor with respect to PTTEP within the meaning of the standards establishedfor independent auditors in Thailand. PTTEP cannot give you assurance, however, that they would be consideredindependent auditors with respect to PTTEP within the meaning of such standards established in the United Statesor elsewhere.

The audited financial statements for SCP as of and for the year ended December 31, 2010 that have beenincluded in this Offering Memorandum have been audited without qualification by Ernst & Young, independentpublic accountants, as set forth in their report thereon, and in accordance with IFRS. Ernst & Young’s reportcontains an explanatory paragraph indicating that the Partnership adopted IFRS on January 1, 2009 with atransition date of January 1, 2009 and that Ernst & Young were not engaged to report on the restated comparativeinformation, and as such, it is unaudited.

130

GENERAL INFORMATION

1. The creation and issue of the Notes has been authorized by resolutions of PTTEP’s board of directors datedFebruary 27, 2009 and by resolutions of the Issuer’s board of directors dated March 21, 2011.

2. The issue of the Guarantee has been authorized by the resolutions of PTTEP’s board of directors datedFebruary 27, 2009.

3. Save as disclosed in this Offering Memorandum, there are no, nor have there been any, litigation orarbitration proceedings, including those which are pending or threatened, of which PTTEP is aware, whichmay have, or have had during the 12 months prior to the date of this Offering Memorandum, a materialadverse effect on PTTEP’s financial position.

4. Save as disclosed in this Offering Memorandum, there has been no material change in PTTEP’s financialor trading position since December 31, 2010 and, since such date, save as disclosed in this OfferingMemorandum, there has been no material adverse change in PTTEP’s financial position or prospects.

5. Copies of the following documents, all of which are published in English, may be inspected during normalbusiness hours at the offices of the Principal Paying Agent or the offices of Allen & Overy at 9/F, ThreeExchange Square, Central, Hong Kong after the date of this Offering Memorandum for so long as any ofthe Notes remains outstanding:

(a) PTTEP’s Memorandum and Articles of Association;

(b) the Issuer’s Memorandum and Articles of Association;

(c) the Indenture; and

(d) PTTEP’s audited consolidated financial statements for the years ended December 31, 2008, 2009 and2010.

6. The Notes are expected to be accepted for clearance through Clearstream, Banking, Euroclear and DTC. TheISIN and CUSIP for each of the Rule 144A Notes and the Regulation S Notes are as follows:

Rule 144A Notes Regulation S Notes

ISIN ........................................................................................... US74442AAA60 USC75088AA97CUSIP ........................................................................................ 74442A AA6 C75088 AA9

7. Approval-in-principle has been received from the SGX-ST for the listing of the Notes on the Official Listof the SGX-ST. The SGX-ST takes no responsibility for the correctness of any of the statements made oropinions or reports contained in this Offering Memorandum. Admission of the Notes to the Official List ofthe SGX-ST is not to be taken as an indication of the merits of the Issuer, the Guarantor or the Notes. Forso long as the Notes are listed on the SGX-ST and the rules of the SGX-ST so require, the Issuer shallappoint and maintain a paying agent in Singapore, where the Notes may be presented or surrendered forpayment or redemption, in the event that the Global Note is exchanged for Certificated Notes. In addition,an announcement of such exchange shall be made by or on behalf of the Issuer through the SGX-ST andsuch announcement will include all material information with respect to the delivery of the CertificatedNotes, including details of the paying agent in Singapore.

131

SUMMARY OF PRINCIPAL DIFFERENCES BETWEEN THAI GAAP AND IFRS

The following is a general summary of certain principal differences between Thai GAAP and IFRS asapplicable to PTTEP and its subsidiaries (collectively, the “Group”).

PTTEP has prepared audited financial statements for the years ended December 31, 2008, 2009 and 2010in accordance with Thai GAAP (the “financial statements”). The financial statements comprise the consolidatedfinancial statements of PTTEP and its subsidiaries (the “consolidated financial statements”) and the separatefinancial statements of PTTEP (the “Company only financial statements”). For the purposes of this OfferingMemorandum, a summary of certain significant differences between Thai GAAP and IFRS which are relevant tothe Group’s financial statements is provided below.

The differences identified below are limited to those significant differences that are appropriate to theGroup’s financial statements for the years ended December 31, 2008, 2009 and 2010. However, they should notbe construed as being exhaustive. The International Accounting Standard Board (“IASB”) and the Federation ofAccounting Professions (“FAP”) in Thailand have issued new pronouncements that may impact subsequentperiods and have significant on-going projects that could affect the differences between Thai GAAP and IFRSdescribed below and the impact of these differences relative to the Group’s financial statements in the future.Accordingly, no attempt has been made to identify future differences between Thai GAAP and IFRS as a resultof prescribed changes in accounting standards or to identify all future differences that may affect the Groupsfinancial statements as a result of transactions or events that may occur in the future.

Thai Accounting Standards (“TAS”) and accounting interpretations are issued by the FAP and endorsed bythe Supervisory Board on Audit Profession of the Business Development Department, the Ministry of Commerce.These standards and interpretations are supplemented by the Stock Exchange of Thailand’s requirements and theThai Securities and Exchange Commission’s requirements and announcements of the FAP. If Thai GAAP does notaddress a particular accounting issue, IFRS and U.S. GAAP may be used for guidance.

TAS were renumbered with effect from June 26, 2009 following the endorsement in the Government Gazetteand the announcement by the FAP in order to conform to the numbers used in the IFRS. Unless otherwise stated,references to TAS below are based on the renumbered TAS.

In making an investment decision, investors must rely upon their own examination of the Group, the termsof the offering and the financial information. Potential investors should consult their own professional advisers foran understanding of the differences between Thai GAAP and IFRS and how these differences might affect thefinancial information in this Offering Memorandum.

Financial Statements Presentation

TAS 1 Presentation of Financial Statements (“TAS 1”) provides guidance on the overall requirements for thepresentation of financial statements, guidelines for their structure and minimum requirements for their content.The format of the financial statements under Thai GAAP follows the format prescribed in Ministerial Regulationunder Accounting Act B.E. 2543.

Prior to the financial year beginning on January 1, 2009, guidance on the presentation of financial statementsunder IFRS was covered by IAS 1 Presentation of Financial Statements (“IAS 1”) which was similar to thoserequired under Thai GAAP. From January 1, 2009, IAS 1 was revised which resulted in a number of significantdifferences between Thai GAAP and IFRS. For example, IAS 1 (Revised) requires all changes in equity arisingfrom transactions with owners in their capacity as owners to be presented separately from non-owner changes inequity in the Statement of Comprehensive Income. An entity has a choice of presenting income and expenses inone statement (a statement of comprehensive income) or in two statements (an income statement and a statementof comprehensive income). In addition, IAS 1 (Revised) requires presentation of a statement of financial positionas at the beginning of the earliest comparative period when an entity applies an accounting policy retrospectivelyor makes a retrospective restatement of items in its financial statements, or when it reclassifies items in itsfinancial statements. This effectively means that the entity is required to present three years of statement offinancial positions in these instances.

TAS 1 has recently been revised based on IAS 1 (Revised) and will become effective on January 1, 2011.However, the TAS 1 (Revised) provides a one-time policy choice for an entity to present two years of financialpositions when TAS 1 (Revised) is adopted on January 1, 2011.

132

Property, Plant and Equipment

Under Thai GAAP, TAS 16 Property, Plant and Equipment does not clearly specify that each significantcomponent of an item of property, plant and equipment (“PPE”) with different useful life are required to beseparately identified and depreciated. Cost of each PPE acquired is recognized and depreciated as a single itemwithout the consideration of component approach. Useful lives and residual values of the PPE should be regularlyreviewed.

Under IFRS, IAS 16 Property Plant and Equipment requires each significant component of a PPE to beseparately identified and depreciated if the useful life of each significant component differs from othercomponents. In addition, useful lives and residual values of the PPE are required to be reviewed and adjusted, ifappropriate, at least annually. The effect of the changes in useful life and residual value is recognized prospectivelyas a change in estimate in the period that the changes occur.

TAS 16 has recently been revised based on IAS 16 (Revised) and will become effective on January 1, 2011.

Capitalization of Borrowing Costs

For Thai GAAP reporting purposes, the Group capitalizes interest cost on borrowings specifically taken outto finance the construction of PPE. Other borrowing costs are expensed.

Prior to January 1, 2009, IAS 23 Borrowing Costs (“IAS 23”) permits an entity to elect either to capitalizeor expense all borrowing costs directly attributable to the acquisition, construction or production of a qualifyingasset as part of the cost of that asset. IAS 23 was revised and the revision became effective on January 1, 2009for calendar year companies. IAS 23 (Revised) removes the accounting policy choices and requires all borrowingcosts arising from both specific and general borrowing which are used to fund the acquisition of the qualifyingassets to be capitalized. Additionally, IAS 23 (Revised) amended the definition of borrowing costs to includeinterest expense calculated using the effective interest method as described in IAS 39 Financial Instruments —Recognition and Measurement. As effective interest method is not required under Thai GAAP, difference existsin the measurement of borrowing costs under Thai GAAP and IFRS.

TAS 23 has recently been revised based on IAS 23 (Revised) and will become effective on January 1, 2011.TAS 23 will be similar to IAS 23 (Revised) except that the interest expense is calculated based on contractualinterest rate.

Accounting for Oil and Gas Exploration and Evaluation Activities and Oil and Gas Properties

There is currently no effective TAS that deals specifically with accounting for oil and gas exploration andevaluation (“E&E”) activities and oil and gas properties. Accordingly, the Group has adopted the followingaccounting policies:

• oil and gas exploration and production activities are accounted for using Successful Efforts Method;

• the cost of properties includes acquisition costs of concession rights or the portion of costs relating toproperties as well as decommissioning costs;

• exploratory costs, which are comprised of geological, geophysical costs and area reservation feesduring the exploration stage, are charged to expenses as incurred;

• exploratory drilling costs are initially capitalized. If exploratory wells do not establish proved reserves,are determined to be economically unsuccessful, or are not included in the plan to develop in the nearfuture, the related costs are charged as expenses; and

• development costs, irrespective of whether the costs relate to successful or unsuccessful developmentwells, are capitalized.

The capitalized acquisition costs of concession rights are depreciated by the unit of production method. Thecapitalized costs of proved properties are depreciated by the unit of production method, which is based onestimated proved recoverable reserves or proved development reserves. Changes in reserve and cost estimates arerecognized prospectively. Proved recoverable reserves and proved development reserves are calculated by theGroup’s engineers and information from the joint ventures.

133

Where the carrying amount of an asset is greater than its estimated recoverable amount, it is written downimmediately to its recoverable amount, and is charged to profit and loss.

Under IFRS, IFRS 6 Exploration for and Evaluation of Mineral Resources (“IFRS 6”), there is no formalcapitalization models prescribed for accounting for exploration and evaluation (“E&E”) expenditure. IFRS 6permits an entity to determine an IFRS accounting policy for E&E expenditure based on an entity’s currentnational GAAP accounting policies. If the E&E expenditures are capitalized, the entity will apply either the costmodel or the revaluation model in IAS 16 Property, Plant and Equipment or the model in IAS 38 Intangible Assets(“IAS 38”), depending on the classification of the E&E assets. Expenditures incurred in the development of oiland gas properties will be accounted for in accordance with the Accounting Framework and IAS 38 IntangibleAssets. IFRS 6 also provides specific impairment indicators for E&E assets. If an impairment indicator exists,impairment testing is required to be performed in accordance with IAS 36 Impairment of Assets.

IFRS 6 specifically requires disclosure of the entity’s accounting policies for exploration and evaluationexpenditures, including the recognition of exploration and evaluation assets and the amounts of assets, liabilities,income and expense and operating and investing cash flows arising from the exploration for and evaluation ofmineral resources.

Site Restoration and Decommissioning Costs

The Group is currently recognizing provision for decommissioning costs when it is probable that there is anobligation as a result of the past event and the amount of obligation can be reliably determined. For oil and gasproperties, the provision is provided at the onset of completion of the project and included as part of the oil andgas properties based on amounts determined by the Group’s own engineers and managerial judgment. There is noguidance for subsequent changes to the existing decommissioning costs under Thai GAAP.

Under IFRS, IAS 37 Provisions, Contingent Liabilities and Contingent Assets (“IAS 37”) requires anobligation to be recognized when 1) an enterprise has a present legal or constructive obligation as a result of a pastevent; (2) it is probable that an outflow of resources embodying economic benefits will be required to settle theobligation; and (3) a reliable estimate can be made of the amount of the obligation. Where the effect of the timevalue of money is material, the amount of a provision shall be the present value of the expenditures expected tobe required to settle the obligation. In addition, IFRIC 1 Changes in existing decommissioning, restoration andsimilar liabilities provides that when there is a change in estimates which may be due to changes in legislation,technology, timing of the decommissioning and management’s assumptions, the impact of such change should beadjusted to the cost of the asset to be decommissioned. However, where the change results in a reduction in thedecommissioning liability, the asset’s carrying amount shall not be reduced below zero. The excess must berecognized immediately in profit or loss. Where the change results in an increase in decommissioning liability andan increase in the cost of the asset, the entity must consider whether the new carrying amount is fully recoverable.If the new carrying amount is not fully recoverable, an impairment loss should be recognized in accordance withIAS 36 Impairment of Assets.

Foreign Currency Translation

There was no concept of functional currency under TAS 21 The Effects of Changes in Foreign ExchangeRates (“TAS 21”) which was effective for the financial years ended December 31, 2008, 2009 and 2010. Assets,liabilities and operating results of entity within the Group are recorded in each respective local currency and theGroup presented its financial statements in Baht.

IAS 21 The Effects of Changes in Foreign Exchange Rates (“IAS 21”) requires each entity to determine itsfunctional currency and measure its results and financial position in that currency. However, the entity may choosea presentation currency to present its financial statements.

Under IAS 21, foreign operations are translated into presentation currency of the reporting entity forconsolidation purposes. That is, assets and liabilities will be translated at the closing rate at the date of the financialposition, income and expenses will be translated at exchange rates at the dates of the transactions and the resultingexchange differences will be recognized in other comprehensive income.

In contrast, TAS 21 distinguishes between foreign operations that are integral to the operations of thereporting entity (referred to below as ‘integral foreign operations’) and foreign entities. A foreign operation thatis integral to the operations of the reporting entity carries on its business as if it were an extension of the reporting

134

enterprise’s operations. Therefore, the financial statements of the integral foreign operation will be translated asif the transactions of the foreign operation had been those of the reporting entity itself. On the other hand,translation procedures of a foreign entity’s financial statement for consolidation purposes follow the sameprocedures as those in IAS 21.

TAS 21 has recently been revised based on IAS 21 and will become effective on 1 January 2013. PTTEPwill adopt the revised TAS 21 on January 1, 2011.

Financial Instruments: Recognition and Measurement

While there is no one single TAS capturing accounting for all types of financial instruments similar to IFRS,there are a number of TAS standards which provide guidance on accounting for financial instruments such as TAS105 Accounting for Investment in Debt and Equity Securities (“TAS 105”) and TAS 101 Doubtful Accounts andBad Debts (“TAS 101”)

Under IFRS, IAS 39 Financial Instruments: Recognition and Measurement (“IAS 39”) has extensiveguidance on the recognition and measurement of financial instruments, including the categorization of financialassets and liabilities, accounting for derivatives and hedging activities and impairment. The IASB has also issuedIFRS 9 Financial Instruments (“IFRS 9”) which will eventually supersede IAS 39. IFRS 9 is effective for theannual period beginning on or after January 1, 2013 but early adoption is permitted. PTTEP will adopt IAS 39from January 1, 2011. Significant differences between Thai GAAP and IAS 39 as applicable to the Group for theyear ended 31 December 2008, 2009 and 2010 are as follow:

Categorization of Financial Assets and Liabilities

Categorization of financial assets and liabilities under Thai GAAP follows the general guidance in theFramework and in each respective standard. In contrast, IAS 39 requires financial assets to be categorized into 1)financial asset at fair value through profit or loss, 2) held to maturity investments, 3) loan and receivables and 4)available for sale financial assets. The categorization depends on the purpose for which the financial assets wereacquired. Financial liabilities are either categorized into financial liability at fair value through profit or loss orfinancial liability carried at amortized cost. All financial assets and liabilities are initially recognized at fair valuenet of transaction costs that are directly attributable to the acquisition or issue of the financial asset or financialliability. Subsequent accounting depends on their respective categories.

Derivative Financial Instruments

The Group enters into derivative contracts to manage its exposure from fluctuation of interest rate, foreignexchange rate and commodity price. Derivatives are off balance sheet and the Group recognizes realized derivativegain or loss on settlement.

Under IFRS, derivatives financial instruments are required to be marked to market at fair value andrecognized on balance sheet. Changes to fair value are recognized through profit and loss. If hedge accounting iselected and appropriate based upon the specific criteria of IAS 39, the impact of recording the derivativeinstrument is offset to the extent the hedging relationship is effective. If a hedge is designated as a fair value hedge,changes in the derivative’s fair value are recorded in profit and loss and the hedged item is marked to market forchanges in fair value associated with the hedged risk. If designated as a cash flow hedge, the effective portion ofthe hedge is recorded in equity as a component of other comprehensive income, and released from othercomprehensive income into earnings as the hedged item affects earnings. All ineffectiveness in the hedgingrelationship, as well as derivative instruments not qualifying for hedge accounting, is reflected in the statement ofincome immediately.

Financial guarantees

The Company provides full financial guarantees to institution investors and financial institutions forunsecured borrowings issued by its subsidiaries. The financial guarantees were disclosed in the consolidatedfinancial statements.

Under IAS 39, financial guarantee contracts are accounted for as financial liabilities and should initially berecognized at fair value by the issuer. Subsequent to the initial recognition, financial guarantee contracts aremeasured and recognized at the higher of the amount determined in accordance with IAS 37 Provisions,Contingent Liabilities and Contingent Assets, and the amount initially recognized at fair value less, whenappropriate, cumulative amortization of the initial amount recognized in accordance with IAS 18 Revenue.

135

Effective Interest Method

Under Thai GAAP, the Group currently recognized loans at fair value of the proceeds received, net oftransaction costs. Interest expenses are recognized based on contractual interest rate. Transaction costs areamortized straight line over the life of the loans.

IAS 39 requires loans to be initially recognized at fair value net of transaction costs. Unless designated asat fair value through profit or loss, the loans are subsequently carried at amortized using effective interest method.

Impairment of Financial Assets

TAS 101 provides limited guidance on impairment of accounts receivable. The Group has providedprovision for doubtful trade receivables based on the payment history and current financial status of debtors. Forthe financial statements presented, the Group has no trade receivables was considered impaired.

In accordance with IAS 39, impairment is recognized based on an incurred loss model. An entity shouldassess at each balance sheet date whether there is any objective evidence that a financial asset or group of assetsmay be impaired. If such impairment evidence exists, the impairment loss is measured as the difference betweenthe asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’soriginal effective interest rate. The impairment loss recognized is in profit and loss.

Derecognition of Financial Assets

There is no effective TAS guidance for derecognition of financial assets. The Company engages in accountsreceivable factoring. Such account receivables are written off when the future economic benefits and other majorrelevant benefits are transferred to the third party and the Company receives the funds from such factoring.

IAS 39 contains specific requirements that apply to the derecognition of all financial assets which must beapplied in strict sequence. The entity derecognizes the asset if an entity transfers substantially all the risks andrewards of ownership of the asset. Conversely, where substantially all the risks and rewards of ownership of theasset are retained, the entity continues to recognize the asset and the transaction is accounted for as a collateralizedborrowing. If an entity neither transfers nor retains substantially all the risks and rewards of ownership of theassets, it needs to determine whether it has retained control of the asset. Control is based on the transferee’spractical ability to sell the asset. The asset is derecognized if the entity has lost control. Accordingly, the risks andrewards approach should be evaluated first. Control analysis is only used where the risks and rewards approachdoes not provide a clear answer.

The difference between the amount received and the carrying amount of the asset is recognized in profit andloss on derecognition.

IAS 39 also contains guidance on partial derecognition of financial assets.

Financial Instruments Presentation and Disclosure

Thai GAAP addresses financial instruments presentation through TAS 32 Financial Instruments:Presentation and Disclosure (“TAS 32”), which is similar to the previous version of IAS 32 Financial Instruments:Presentation (“IAS 32”). The current version of IAS 32 revised the definitions of financial liabilities, and equityinstrument and provided additional guidance on the classification between financial liability and equityinstrument. It also provides additional guidance on classification of contracts settled in an entity’s own equityinstruments, puttable instruments and treasury shares.

Disclosure requirements under TAS 32 are not as extensive as those required by IFRS 7 FinancialInstruments: Disclosure (“IFRS 7”). IFRS 7 requires extensive qualitative and quantitative disclosure aboutexposure to risks rising from financial instruments, including specified minimum disclosures about credit risk,liquidity risk and market risk and how the entity manages those risks.

Business Combinations

Financial Year ended December 31, 2008 and 2009

TAS 43 Business Combinations (“TAS 43”), which was subsequently renumbered as TFRS 3, was based onIFRS 3 (2004). Accordingly, there was no significant difference between Thai GAAP and IFRS for the year ended31 December 2008 and 2009.

136

January 1, 2010 onwards

IFRS 3 (2004) was amended and was effective on January 1, 2010 for calendar year companies. There areseveral key differences between IFRS 3 (Revised) and TFRS 3 such as accounting for transaction costs, contingentconsideration and remeasurement of previously held interest.

IFRS 3 (Revised) requires transaction costs to be expensed as incurred. Such transaction costs directlyrelated to the acquisition are capitalized as part of the cost of the combinations under TFRS 3.

For contingent consideration, IFRS 3 (Revised) requires contingent consideration to be recognized at fairvalue on acquisition date even if it is not probable of payment. Accounting for subsequent changes in fair valueof contingent consideration depends on whether the contingent consideration is classified as assets, liabilities orequity. Under TFRS 3, contingent consideration is included in the cost of the business combination at theacquisition date if it is probable and can be reliably measured. Subsequent changes in fair value of contingentconsideration are adjusted to the cost of the combination and goodwill.

Under TFRS 3, non-controlling interest in the acquiree must be measured at the non-controlling interest’sproportionate share of the acquiree’s net assets. In contrast, IFRS 3 (Revised) provides a choice on anacquisition-by-acquisition basis to measure the non-controlling interest in the acquiree either at fair value or at thenon-controlling interest’s proportionate share of the acquiree’s net assets.

Under IFRS 3 (Revised), identifiable net assets of previously held interest is remeasured at fair value. Gainor loss from remeasurement is recognized in profit and loss. On the other hand, TFRS 3 requires each asset andliability to be measured at the fair value of at each step to determine goodwill attributable to that step. Anyadjustment to the fair value of the acquiree’s identifiable net assets relating to the previously held interests is arevaluation and is recognized in reserve.

TFRS 3 has recently been revised based on IFRS 3 (Revised) and will become effective on January 1, 2011.

Investments in Associates and Joint Ventures

PTTEP currently accounts for its investments in associates and joint ventures using the equity method andproportionate consolidation, respectively as permitted by TAS 28 Investments in Associates and TAS 31Investment in Joint Ventures in its consolidated financial statements. The accounting treatment is the same underIFRS.

For separate financial statements presentation purposes, TAS 28 and TAS 31 require the investment inassociates and joint ventures to be accounted by using cost method. Under IFRS, the entity has a choice ofaccounting for the investments either at cost or at fair value in accordance with IAS 39. Once elected, the sameaccounting must be applied to the same category of investments. Additionally, if the entity has elected to accountfor the investments at fair value in accordance with IAS 39 and IFRS 9 and the investments meet held for saleconditions in accordance with IFRS 5 Non-current Assets Held for Sale and Discontinued Operations, theinvestments will continue to be carried at fair value in accordance with IAS 39 and IFRS 9.

Consolidation

Prior to January 1, 2010, there was no significant difference between TAS 27 Consolidated FinancialStatements (“TAS 27”) and IAS 27 Consolidated Financial Statements (“IAS 27”). IAS 27 was revised and therevision became effective on January 1, 2010 for calendar year companies. Key differences between TAS 27 andIAS 27 (Revised) include:

• IAS 27 (Revised) changes the term ‘minority interest’ to ‘non-controlling interest’.

• IAS 27 (Revised) requires an entity to attribute total comprehensive income to the owners of the parentand to the non-controlling interests even if this results in the non-controlling interests having a deficitbalance.

• IAS 27 (Revised) requires changes in a parent’s ownership interest in a subsidiary that do not resultin the loss of control to be accounted for within equity. Such changes are recognized in profit and lossunder TAS 27.

137

• When an entity loses control of a subsidiary, IAS 27 (Revised) requires the entity to derecognize theassets and liabilities and related equity components of the former subsidiary. Any gain or loss isrecognized in profit and loss. Any investment retained in the former subsidiary is measured at its fairvalue at the date when control is lost.

TAS 27 has recently been revised based on IAS 27 (Revised) and will become effective on January 1, 2011.

Retirement Benefits

There is no currently effective TAS for accounting for employee benefits. On January 1, 2008, the Grouphad adopted IAS 19 Employee Benefits (“IAS 19”) for the purpose of accounting for its retirement benefitobligation under Thai Labour Law. The calculation of the retirement benefit obligation was performed by anindependent actuary using the Projected Unit Credit Method. On the adoption of IAS 19, the Group has electedto amortize the transition liabilities as expenses in the profit and loss on a straight-line basis over 5 years.

TAS 19 Employee Benefits has recently been issued based on IAS 19 and will become effective on January1, 2011.

Share-based Payments

There is no currently effective TAS for accounting for share based payments. The Group recognizes cashreceived from employees from its employee share ownership plan (“ESOP”) transactions when the employeesexercise the options at the exercise price. The proceeds received are credited to share capital and share premiumwhen the options are exercised. No share based payment expense was recognized in profit and loss.

In accordance with IFRS 2 Share-based Payments, an ESOP plan is an equity-settled share based paymenttransaction and should be recognized at fair value of the ESOP granted at grant date over the vesting period witha corresponding credit to equity. When the options are exercised and the shares are issued, the correspondingcredits with respect to proceeds received net of any directly attributable transaction costs are made to share capitaland share premium. Where the award is vested in installments over the vesting period, each installment is treatedas a separate share grant.

TFRS 2 Share-based Payments has recently been issued based on IFRS 2 and will become effective onJanuary 1, 2011 for share based payment transactions occurred after January 1, 2011.

Deferred Taxes

There is no effective TAS for accounting for deferred taxes. Although the Group has adopted IAS 12 IncomeTaxes to account for its deferred tax assets and liabilities, differences exist in the balance of deferred tax assetsand liabilities as reported and the amounts to be reported under IFRS as a result of the deferred tax effects of otherGAAP differences.

TAS Income Taxes has recently been issued based on IAS 12 and will become effective on 1 January 2013,early adoption is permitted.

Segment Reporting

The Group is currently presenting its primary and secondary segments information based on its businessoperation and geographical areas, respectively. The secondary segment format requires less disclosure.

Under IFRS, prior to January 1, 2009, IAS 14 Segment Reporting (“IAS 14”) prescribed similar disclosureas the Group’s current disclosure. From the financial year beginning on January 1, 2009, IAS 14 was supersededby IFRS 8 Operating Segments (“IFRS 8”). IFRS 8 requires segment information to be reported based on theentity’s operating segment. Operating segments are components of an enterprise in which separate financialinformation is available and is evaluated regularly by the chief operating decision maker in deciding how toallocate resources and in assessing performance. Generally, financial information is required to be reported on thesame basis that it is used internally for evaluating segment performance and deciding how to allocate resourcesto segments.

138

Impairment of Goodwill

Both TAS 38 Intangible Assets (“TAS 38”) and IAS 38 Intangible Assets (“IAS 38”) require goodwill to betested for impairment at least annually or when an impairment indicator exists. Goodwill is allocated to a cashgenerating unit or a group of cash generating units for the purpose of impairment testing. However, the level ofallocation cannot be larger than the operating segment. As operating segment is defined differently under ThaiGAAP and IFRS, difference exists in the goodwill allocation level for impairment testing under each GAAP.Accordingly, goodwill impairment loss recognized under each GAAP could potentially be different.

Related Party Transactions

The Group applies TAS 24 Related Party Transactions (“TAS 24”) for consolidated financial statementsdisclosure purposes and also discloses its related party transactions according to the Thai Security ExchangeCommission (“SEC”) requirements which include, among other things, the disclosure of the pricing policy forrelated party transactions.

The definition of related party under IAS 24 Related Party Transactions (“IAS 24”) is broader than thatunder TAS 24. Under IAS 24, related party covers parties with joint control over the entity, joint ventures in whichthe entity is a venture and post-employment benefit plans for the benefit of employees of the entity, or of any entitythat is a related party to that party. Additionally, IAS 24 also requires disclosure of compensation of keymanagement and type of compensation. Disclosure of pricing policy for related party transactions is permitted butnot required.

TAS 24 has recently been revised based on IAS 24 (Revised) and will become effective on January 1, 2011.

Disclosures

In general, the disclosure requirements for Thai GAAP are not as extensive as those required by IFRS. Areaswhere IFRS requires specific additional disclosures include, among others, related party transaction with respectto key management compensation, financial instruments and segment related disclosures.

139

GLOSSARY OF TECHNICAL TERMS

Unless otherwise indicated in the context, references to:

• “Appraisal wells” are to wells drilled after successful exploration to gain further information on newlydiscovered oil or gas reservoirs.

• “Agents” are to a dealer, manager or underwriter.

• “Bbls” are to barrels.

• “Bbls/d” are to barrels per day.

• “Billion” are to a thousand million.

• “Boe” are to barrels-of-oil equivalent.

• “Boe/d” are to barrels-of-oil equivalent per day.

• “BSCF” are to billion standard cubic feet.

• “Condensate” are to liquid hydrocarbons of very light crude oil composition that are gaseoussubsurface (high temperature and pressure), and condense into a liquid upon production and inresponse to surface temperature and pressure.

• “Development wells” are to wells drilled to exploit the hydrocarbon accumulation defined by anappraisal well.

• “Development costs” are to costs involved in bringing proved reserves to production. Developmentcosts include the cost of drilling development wells plus the production equipment and its installation.

• “Exploration wells” are to wells drilled in order to locate an undiscovered petroleum reservoir, eitherby discovering a new field or a new shallower or deeper reservoir in a previously discovered field.

• “EPPO” are to the Energy Policy and Planning Office.

• “Farm-in” are to acquiring an interest in a lease or concession owned by another operator on whichoil or gas has been discovered or is being produced.

• “Finding costs” are to costs of locating a field per barrel of oil or thousand standard cubic feet of gasreserves which include lease cost, G&G, overhead, and discovery well drilling and completion.

• “FLNG” are floating liquefied natural gas.

• “FPSO” are to floating production storage and offloading facilities.

• “G&G Cost” are to exploration geology and geophysics cost.

• “GSA” are to gas sale agreement.

• “GWH” are to Gigawatt hours.

• “JDA” are to Block A-18, B-17 and C-19 of the Malaysia-Thailand Joint Development Area.

• “KBoe/d” are to thousand of barrels-of-oil equivalent per day.

• “Kb/d” are to thousand of barrels per day.

• “LIBOR” are to the London Interbank Offered Rate.

• “Listed Notes” are to debt instruments or debentures that have been accepted for listing on a stockexchange.

140

• “Long Lead Items” are categorized as items that are difficult to source and/or will take a long periodto acquire.

• “LPG” are to liquefied petroleum gas which is propane gas or, less commonly, butane or apropane-butane mixture that has been compressed into liquid.

• “Mbbls” are to thousand barrels.

• “MMbbls” are to million barrels.

• “MMboe” are to million of barrels-of-oil equivalent.

• “MMbtu” are to million British Thermal Units.

• “MMSCF” are to million standard cubic feet.

• “MMSCFD” are to million standard cubic feet per day.

• “MMstb” are to million stock-tank barrels.

• “MTJDA” are to Malaysia-Thailand Joint Development Area.

• “Petroleum” are to hydrocarbons, including natural gas, natural gas liquids, crude oil and theirproducts.

• “Probable reserves” are to those unproved reserves which analysis of geological and engineering datasuggests are more likely than not to be recoverable. In this context, when probabilistic methods areused to estimate reserves, there should be at least 50% probability that the quantities actuallyrecovered will equal or exceed the sum of estimated proved plus probable reserves.

• “Proved developed reserves” are to the estimated quantities of petroleum expected to be recoveredfrom existing wells, equipments and operating method. They may be sub-grouped as producing andnon-producing.

• “Proved reserves” are to those quantities of petroleum which, by analysis of geological andengineering data, can be estimated with reasonable certainty to be commercially recoverable, from agiven date forward, from known reservoirs and under current economic conditions, operating method,and government regulations. In respect of both the SPE Petroleum Resources Management Systemand COGE Handbook, proved reserves means at least a 90% chance that quantities actually recoveredwill equal or exceed the estimates.

• “Proved undeveloped reserves” are to proved reserves that are expected to be recovered from newwells in undrilled acreage, or from deepening existing wells to a different reservoir, or where arelatively significant expenditure is required to recomplete an existing well or install production ortransportation facilities for primary or improved recovery project.

• “PSC” are to production sharing contracts.

• “Throughput” are to the amount of material processed by a production unit in a year or other periodas indicated.

• “Tonnes” or “tonnes” are to metric tonnes. A metric ton is equal to 1,000 kilograms, or approximately2,204.6 pounds.

• “TSCF” are to trillion standard cubic feet.

141

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND AUDITOR’S REPORTS

Page

Audited Financial Statements of PTTEP for the Years ended December 31, 2010, 2009 and 2008

Auditor’s Report and Financial Statements for the Years ended December 31, 2010 and 2009 . . . . . . . F-2

Auditor’s Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3

Consolidated Balance Sheets as at December 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . F-4

Consolidated Statements of Income for the Years ended December 31, 2010 and 2009 . . . . . . . . . . . . F-6

Consolidated Statements of Changes in Shareholders’ Equity for the Years ended December 31,2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7

Consolidated Statements of Cash Flows for the Years ended December 31, 2010 and 2009 . . . . . . . . . F-9

Notes to Financial Statements for the Years ended December 31, 2010 and 2009 . . . . . . . . . . . . . . . . F-11

Auditor’s Report and Financial Statements for the Years ended December 31, 2009 and 2008 . . . . . . . F-56

Auditor’s Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-57

Consolidated Balance Sheets as at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . F-58

Consolidated Statements of Income for the Years ended December 31, 2009 and 2008 . . . . . . . . . . . . F-60

Consolidated Statements of Changes in Shareholders’ Equity for the Years ended December 31,2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-61

Consolidated Statements of Cash Flows for the Years ended December 31, 2009 and 2008 . . . . . . . . . F-63

Notes to Financial Statements for the Years ended December 31, 2009 and 2008 . . . . . . . . . . . . . . . . F-65

Audited Financial Statements of SCP for the Year ended December 31, 2010

Audited Financial Statements for the Year ended December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . F-108

Auditor’s Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-109

Audited Statement of Financial Position as at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . F-110

Audited Statement of Loss and Comprehensive Loss for the Year ended December 31, 2010 . . . . . . . F-111

Audited Statement of Cash Flows for the Year ended December 31, 2010 . . . . . . . . . . . . . . . . . . . . F-112

Audited Statement of Changes in Partners’ Equity for the Year ended December 31, 2010 . . . . . . . . . F-113

Notes to the Audited Financial Statements for the Year ended December 31, 2010 . . . . . . . . . . . . . . . F-114

Unaudited Pro Forma Combined Financial Information of PTTEP as of and for theYear ended December 31, 2010

Unaudited Pro Forma Combined Balance Sheet as at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . F-132

Unaudited Pro Forma Combined Statement of Income for the Year ended December 31, 2010 . . . . . . F-133

Footnotes to Pro Forma Combined Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-134

F-1

AUDITOR’S REPORT AND FINANCIAL STATEMENTS

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED

AND SUBSIDIARIES

FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

F-2

AUDITOR’S REPORT

TO: THE SHAREHOLDERS OF PTT EXPLORATION AND PRODUCTION PUBLIC COMPANYLIMITED

The Office of the Auditor General of Thailand has audited the accompanying consolidated and the Companybalance sheets as at December 31, 2010 and 2009, the related consolidated and the Company statements ofincome, changes in shareholders’ equity, and cash flows for the years then ended of PTT Exploration andProduction Public Company Limited and subsidiaries and of PTT Exploration and Production Public CompanyLimited, respectively. The Company’s management is responsible for the correctness and completeness ofinformation presented in these financial statements. The responsibility of the Office of the Auditor General ofThailand is to express an opinion on these financial statements based on the audits and other auditors’ reports. TheOffice of the Auditor General of Thailand received the other auditors’ reports and used them as a basis in auditingand expressing an opinion on the consolidated and the Company financial statements. Assets, liabilities andexpenses audited by other auditors included in the consolidated financial statements for the year 2010 constitute65.92%, 17.62% and 37.85% and for the year 2009 constitute 67.02%, 25.93% and 47.11% respectively, andincluded in the Company financial statements for the year 2010 constitute 35.32%, 4.96% and 31.71% and for theyear 2009 constitute 33.54%, 3.51% and 37.77% respectively.

The Office of the Auditor General of Thailand conducted the audits in accordance with generally accepted auditingstandards. Those standards require that the Office of the Auditor General of Thailand plan and perform the auditto obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.An audit also includes assessing the accounting principles used and significant estimates made by management,as well as evaluating the overall financial statement presentation. The Office of the Auditor General of Thailandbelieves that the audits together with other auditors’ reports as above-mentioned provide a reasonable basis for theopinion.

In the opinion of the Office of the Auditor General of Thailand, based on the audits and other auditors’ reports,the consolidated and the Company financial statements referred to above present fairly, in all material respects,the consolidated and the Company financial position as at December 31, 2010 and 2009, and the consolidated andthe Company’s results of operations and cash flows for the years then ended of the consolidated PTT Explorationand Production Public Company Limited and subsidiaries and of PTT Exploration and Production PublicCompany Limited in accordance with generally accepted accounting principles.

(Signed) Poungchomnad Jariyajinda(Poungchomnad Jariyajinda)

Inspector General

(Signed) Doungporn Muennuch(Doungporn Muennuch)Director of Audit Office

February 17, 2011

F-3

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

BALANCE SHEETSAS AT DECEMBER 31, 2010 AND 2009

Unit : Baht

Consolidated The Company

Notes 2010 2009 2010 2009

AssetsCurrent Assets

Cash and cash equivalents ...................................... 7 59,514,757,315 48,677,769,437 43,369,134,422 35,027,409,870

Trade account receivable-parent company ............ 8 9,883,369,719 10,918,592,580 6,278,988,552 7,697,295,667

Trade accounts receivable ....................................... 9 1,844,842,304 3,345,572,004 78,447,233 47,856,171

Inventories .............................................................. 594,376,758 1,048,974,429 130,992,143 311,969,441

Materials and supplies, net .................................... 10 7,953,648,829 8,145,572,198 3,190,406,745 3,257,166,354

Other current assets

Working capital from co-venturers .................... 910,186,446 407,126,209 11,358,606 20,573,756

Other accounts receivable .................................. 11 1,530,941,000 3,685,134,238 820,499,720 1,012,558,540

Accrued interests receivable............................... 5,384,473 4,950,652 217,218,868 99,766,614

Other current assets ............................................ 2,838,659,552 2,550,165,062 1,053,440,235 1,037,542,199

Total Current Assets.............................................. 85,076,166,396 78,783,856,809 55,150,486,524 48,512,138,612

Non-current AssetsInvestments in subsidiaries...................................... 13.3 — — 23,873,135,929 23,873,135,929

Investments in associates ....................................... 13.4 877,483,190 922,311,301 930,000,000 930,000,000

Long-term loans to related parties ......................... 12.2 590,788,545 504,737,773 60,831,959,890 58,209,232,771

Property, plant and equipment, net ........................ 14, 15 226,332,468,695 206,705,301,913 93,323,988,127 84,330,156,861

Intangible assets, net ............................................... 16 3,939,023,342 3,977,379,942 301,269,168 330,919,994

Deferred income tax assets .................................... 17.2 13,824,291,614 8,543,179,497 573,119,147 —

Other non-current assets

Prepaid expenses................................................. 18 152,011,019 194,156,625 653,636 —

Deposit for the purchase of partnership units .. 19 10,311,744,600 — — —

Deferred remuneration under agreement ........... 919,346,709 978,906,799 919,346,709 978,906,799

Other non-current assets ................................... 20 196,228,709 100,779,096 127,044,594 24,861,602

Total Non-current Assets ...................................... 257,143,386,423 221,926,752,946 180,880,517,200 168,677,213,956

Total Assets .................................................................. 342,219,552,819 300,710,609,755 236,031,003,724 217,189,352,568

Notes to financial statements are an integral part of these financial statements.

(Signed) Anon Sirisaengtaksin(Anon Sirisaengtaksin)

President and Chief Executive Officer

(Signed) Sermsak Satchawannakul(Sermsak Satchawannakul)

Vice President, attached to Finance and Accounting Group

F-4

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

BALANCE SHEETS (Continued)AS AT DECEMBER 31, 2010 AND 2009

Unit : Baht

Consolidated The Company

Notes 2010 2009 2010 2009

Liabilities and Shareholders’ EquityCurrent Liabilities

Trade accounts payable .......................................... 1,958,454,321 918,725,737 203,758,721 270,317,656

Current portion of long-term debts......................... — 10,327,577,889 — 9,498,741,249

Short-term loans ...................................................... 21 7,944,731,692 1,934,955,131 7,944,731,694 999,204,995

Working capital to co-venturers.............................. 1,013,643,938 652,233,615 624,319,219 145,942,711

Accrued expenses .................................................... 18,274,349,327 20,726,274,992 9,857,650,381 8,870,960,142

Accrued interest payable ........................................ 552,136,275 238,509,384 166,820,822 238,509,384

Income tax payable.................................................. 22,447,945,269 19,037,505,829 17,709,397,093 15,094,309,098

Short-term provision................................................ 22 3,933,197,692 873,418,354 — —

Other current liabilities............................................ 2,072,133,819 1,486,391,497 1,276,934,477 950,690,568

Total Current Liabilities ....................................... 58,196,592,333 56,195,592,428 37,783,612,407 36,068,675,803

Non-current LiabilitiesBonds ....................................................................... 21 69,893,282,855 48,951,198,113 48,965,264,636 48,951,198,113

Finance lease liabilities ........................................... 23 — 10,556,720,810 — —

Deferred income tax liabilities................................ 17.2 15,780,122,712 14,992,994,481 10,161,310,405 11,202,642,515

Other non-current liabilities

Deferred income ................................................. 24 1,939,677,336 2,608,737,278 — —

Provision for employee benefits ........................ 25 1,560,118,603 1,164,681,340 1,435,477,615 1,104,779,664

Provision for decommissioning costs ................ 26 21,967,635,102 22,821,103,348 10,781,669,997 10,426,554,592

Other non-current liabilities ............................... 588,124,875 418,816,080 280,561,061 268,752,983

Total Non-current Liabilities................................ 111,728,961,483 101,514,251,450 71,624,283,714 71,953,927,867

Total Liabilities ........................................................... 169,925,553,816 157,709,843,878 109,407,896,121 108,022,603,670

Shareholders’ EquityShare capital ............................................................ 27

Authorized share capital

3,322,000,000 ordinary shares of Baht 1each .......................................................... 3,322,000,000 3,322,000,000 3,322,000,000 3,322,000,000

Issued and paid-up share capital

3,317,447,600 ordinary shares of Baht 1each .......................................................... 3,317,447,600 — 3,317,447,600 —

3,312,560,700 ordinary shares of Baht 1each .......................................................... — 3,312,560,700 — 3,312,560,700

Share premium......................................................... 14,182,932,340 13,784,668,840 14,182,932,340 13,784,668,840

Currency translation differences ............................ (2,952,766,002) (2,537,667,138) — —

Retained earnings

Appropriated

Legal reserve ................................................ 332,200,000 332,200,000 332,200,000 332,200,000

Reserve for expansion .................................. 16,900,000,000 16,900,000,000 16,900,000,000 16,900,000,000

Unappropriated ................................................... 140,514,185,065 111,209,003,475 91,890,527,663 74,837,319,358

Total Shareholders’ Equity ...................................... 172,293,999,003 143,000,765,877 126,623,107,603 109,166,748,898

Total Liabilities and Shareholders’ Equity ............ 342,219,552,819 300,710,609,755 236,031,003,724 217,189,352,568

Notes to financial statements are an integral part of these financial statements.

F-5

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF INCOMEFOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Unit : Baht

Consolidated The Company

Notes 2010 2009 2010 2009

RevenuesSales ......................................................................... 138,473,937,779 115,547,525,128 84,802,869,163 72,498,326,625

Revenue from pipeline transportation ................... 3,504,182,469 3,762,603,676 — —

Other revenues

Gain on foreign exchange .................................. 28 2,763,078,556 — — —

Interest income ................................................... 373,500,555 376,273,736 2,181,445,263 1,779,237,320

Other revenues.................................................... 29 2,457,598,458 651,837,175 764,040,632 103,917,372

Dividends received from related parties................. — — 4,080,024,000 1,946,998,450

Total Revenues ............................................. 147,572,297,817 120,338,239,715 91,828,379,058 76,328,479,767

ExpensesOperating expenses.................................................. 14,588,340,889 11,926,256,536 7,548,152,076 5,114,316,449

Exploration expenses............................................... 2,751,686,375 7,377,274,117 105,058,203 191,621,830

Administrative expenses.......................................... 5,971,630,724 5,061,922,671 3,576,652,547 2,371,567,203

Petroleum royalties and remuneration .................... 30 16,773,327,361 14,065,574,385 10,600,358,647 8,949,903,955

Depreciation, depletion and amortization ............... 36,825,398,201 29,856,004,386 20,907,209,698 17,765,146,850

Other expenses

Loss on foreign exchange .................................. 28 — 508,219,408 1,470,016,711 178,626,594

Loss from Montara incident............................... 31 456,651,041 9,085,875,964 — —

Management’s remuneration .............................. 32 185,521,124 156,083,519 185,521,124 156,083,519

Other expenses.................................................... 23 1,484,830,772 — — —

Total Expenses ............................................ 79,037,386,487 78,037,210,986 44,392,969,006 34,727,266,400

Income of operations .................................................. 68,534,911,330 42,301,028,729 47,435,410,052 41,601,213,367

Share of loss of associates ........................................... (44,828,066) (17,863,550) — —

Income before finance costs and income taxes ...... 68,490,083,264 42,283,165,179 47,435,410,052 41,601,213,367Finance costs................................................................. 2,540,537,457 1,870,328,040 1,969,519,057 1,783,674,802

Income before income taxes ..................................... 65,949,545,807 40,412,837,139 45,465,890,995 39,817,538,565Income taxes ................................................................. 17.1 24,210,571,252 18,259,240,291 15,978,889,725 14,765,441,218

Net income .................................................................. 41,738,974,555 22,153,596,848 29,487,001,270 25,052,097,347

Earnings per share 34

Basic earnings per share.......................................... 12.59 6.69 8.90 7.57

Diluted earnings per share ...................................... 12.59 6.69 8.89 7.56

Notes to financial statements are an integral part of these financial statements.

F-6

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITYCONSOLIDATED

FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Unit : Baht

Note

Share capitalissued and

paid-upShare

premium

Currencytranslationdifferences Legal reserve

Reserve forexpansion

Retainedearnings Total

Balance - as atJanuary 1, 2009 ....... 3,307,084,400 13,423,109,280 (2,281,147,979) 332,200,000 16,900,000,000 102,422,579,919 134,103,825,620

Share capital issued andpaid-up........................ 5,476,300 361,559,560 — — — — 367,035,860

Currency translationdifferences .................. — — (256,519,159) — — — (256,519,159)

Net income ...................... — — — — — 22,153,596,848 22,153,596,848

Dividends paid ................ — — — — — (13,367,173,292) (13,367,173,292)

Balance - as atDecember 31, 2009 ... 3,312,560,700 13,784,668,840 (2,537,667,138) 332,200,000 16,900,000,000 111,209,003,475 143,000,765,877

Share capital issued andpaid-up........................ 4,886,900 398,263,500 — — — — 403,150,400

Currency translationdifferences .................. — — (415,098,864) — — — (415,098,864)

Net income ...................... — — — — — 41,738,974,555 41,738,974,555

Dividends paid ................ 37 — — — — — (12,433,792,965) (12,433,792,965)

Balance - as atDecember 31, 2010 ... 3,317,447,600 14,182,932,340 (2,952,766,002) 332,200,000 16,900,000,000 140,514,185,065 172,293,999,003

Notes to financial statements are an integral part of these financial statements.

F-7

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITYTHE COMPANY

FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Unit : Baht

Note

Share capitalissued and

paid-up Share premium Legal reserveReserve forexpansion

Retainedearnings Total

Balance - as atJanuary 1, 2009 ..... 3,307,084,400 13,423,109,280 332,200,000 16,900,000,000 63,152,395,303 97,114,788,983

Share capital issued andpaid-up ...................... 5,476,300 361,559,560 — — — 367,035,860

Net income ................... — — — — 25,052,097,347 25,052,097,347

Dividends paid............... — — — — (13,367,173,292) (13,367,173,292)

Balance - as atDecember 31, 2009 . 3,312,560,700 13,784,668,840 332,200,000 16,900,000,000 74,837,319,358 109,166,748,898

Share capital issued andpaid-up ...................... 4,886,900 398,263,500 — — — 403,150,400

Net income..................... — — — — 29,487,001,270 29,487,001,270

Dividends paid............... 37 — — — — (12,433,792,965) (12,433,792,965)

Balance - as atDecember 31, 2010 . 3,317,447,600 14,182,932,340 332,200,000 16,900,000,000 91,890,527,663 126,623,107,603

Notes to financial statements are an integral part of these financial statements.

F-8

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Unit : Baht

Consolidated The Company

2010 2009 2010 2009

Cash flows from operating activitiesIncome before income taxes .................................. 65,949,545,807 40,412,837,139 45,465,890,995 39,817,538,565Adjustment to reconcile income before income

taxes to net cash provided by (used in)operating activitiesShare of loss of associates ............................... 44,828,066 17,863,550 — —Depreciation, depletion and amortization ........ 36,825,398,201 29,856,004,386 20,907,209,698 17,765,146,850Amortization of prepaid expenses..................... 137,382,781 71,899,139 74,885,365 71,325,558Amortization of exploration expenses............... 1,471,915,640 5,671,138,123 516,260 11,543,204(Gain) loss on disposal of assets....................... (340,521,321) 3,498,913,840 (520,880,139) 13,224,922Income recognized from deferred income ........ (643,892,634) 87,427,649 — —Dividends received from related parties ........... — — (4,080,024,000) (1,946,998,450)Loss from Montara incident .............................. — 3,105,525,354 — —Provision for employee benefits........................ 407,834,241 401,328,135 341,850,405 373,810,298Gain on foreign exchange.................................. (4,230,562,549) (844,492,213) (1,017,501,188) (458,293,451)Interest income (higher) less than interest

expenses ......................................................... 1,962,227,779 1,390,664,559 (242,110,604) (14,001,366)

101,584,156,011 83,669,109,661 60,929,836,792 55,633,296,130

Changes in operating assets and liabilities(Increase) decrease in trade accounts

receivable ...................................................... 1,401,935,209 (1,771,801,719) (30,593,490) (29,016,917)(Increase) decrease in trade account receivable

- parent company........................................... 1,004,178,434 (985,762,226) 1,418,307,116 (995,391,453)(Increase) decrease in inventories ..................... 351,824,285 (383,459,468) 47,580,989 (80,739,561)(Increase) decrease in materials and supplies,

net ................................................................. 143,645,784 (1,904,582,417) 54,102,903 (718,991,170)(Increase) decrease in working capital from

co-venturers.................................................... (498,270,627) 544,704,176 55,734,935 (12,412,761)(Increase) decrease in other accounts

receivable ....................................................... 2,036,143,118 (1,727,195,611) 195,702,847 392,031,685(Increase) decrease in other current assets........ (208,287,727) 91,134,537 41,153,672 (632,464,339)Increase in prepaid expenses ............................. (7,565,743) — (653,636) —Increase in other non-current assets .................. (103,001,234) (4,692,537) (102,182,993) (458,258)Increase in deferred income tax assets.............. — (3,435,836,005) — —(Decrease) increase in trade accounts payable . 1,198,960,038 (1,388,630,945) (66,648,193) 99,200,303(Decrease) increase in working capital to

co-venturers.................................................... 357,678,925 (319,857,191) 487,076,910 (176,142,891)(Decrease) increase in accrued expenses .......... (1,716,775,881) 1,787,258,986 1,092,638,688 141,965,431Increase in other current liabilities.................... 909,869,327 973,149,480 307,912,123 151,395,111Increase in deferred income .............................. 88,825 1,864,078 — —(Decrease) increase in other non-current

liabilities......................................................... 186,747,744 (959,333,045) 627,090 (1,095,631,492)Loss from translation adjustment ......................... (92,308,301) (91,568,450) — —Interest received from bank deposits ..................... 352,969,800 368,849,245 222,731,251 253,429,875Taxation paid .......................................................... (25,169,701,034) (31,576,865,911) (15,034,072,759) (18,304,621,803)

(19,851,869,058) (40,782,625,023) (11,310,582,547) (21,007,848,240)

Net cash provided by operatingactivities .................................................... 81,732,286,953 42,886,484,638 49,619,254,245 34,625,447,890

Notes to financial statements are an integral part of these financial statements.

F-9

(TRANSLATION)PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CASH FLOWS (Continued)FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009

Unit : Baht

Consolidated The Company

2010 2009 2010 2009

Cash flows from investing activities(Increase) decrease in loans to related parties ...... (86,050,772) 1,330,262,227 (2,525,466,881) (31,270,256,232)

Deposit for the purchase of partnership units ...... (10,311,744,600) — — —

Increase in investments in related parties.............. — (555,838,206) — (606,364,649)

Dividends received from related parties................ — — 4,080,024,000 1,946,998,450

Interest received from loans................................... 19,120,753 44,558,767 1,840,657,077 1,534,695,279

Increase in property, plant and equipment ............ (64,755,121,181) (59,388,765,720) (27,809,097,348) (20,571,106,781)

Increase in intangible assets................................... (41,331,251) (3,633,423,120) (37,721,632) (50,547,214)

Net cash used in investing activities.......... (75,175,127,051) (62,203,206,052) (24,451,604,784) (49,016,581,147)

Cash flows from financing activities(Decrease) increase in short-term loans ................ 5,999,675,422 (1,360,717,196) 6,923,393,000 (2,185,934,382)

Redemption of bonds ............................................. (9,500,000,000) — (9,500,000,000) —

Proceeds from bonds .............................................. 22,192,614,168 39,950,119,444 — 39,950,119,444

Interest paid ............................................................ (1,995,416,307) (1,439,081,012) (1,988,889,524) (1,437,378,671)

Proceeds from common stock................................ 403,150,400 367,035,860 403,150,400 367,035,860

Dividends paid........................................................ (12,433,221,900) (13,366,259,736) (12,433,221,900) (13,366,259,736)

Net cash provided by (used in) financingactivities .................................................... 4,666,801,783 24,151,097,360 (16,595,568,024) 23,327,582,515

Net increase in cash and cash equivalents ............... 11,223,961,685 4,834,375,946 8,572,081,437 8,936,449,258

Cash and cash equivalents at the beginning ofthe year .................................................................. 48,677,769,437 43,994,689,588 35,027,409,870 26,132,472,261

59,901,731,122 48,829,065,534 43,599,491,307 35,068,921,519

Adjustment for the effect of exchange rate changeson cash and cash equivalents ................................ (386,973,807) (151,296,097) (230,356,885) (41,511,649)

Cash and cash equivalents at the end of theyear ......................................................................... 59,514,757,315 48,677,769,437 43,369,134,422 35,027,409,870

Notes to financial statements are an integral part of these financial statements.

F-10

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIESNOTES TO FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009(UNIT: MILLION BAHT, EXCEPT AS NOTED)

1. General Information

PTT Exploration and Production Public Company Limited (the Company) is registered as a company in Thailand and listed on theStock Exchange of Thailand. The address of its registered office is 555/1 Energy Complex Building A, Floors 6 and 19-36, Vibhavadi-RangsitRoad, Chatuchak, Bangkok 10900.

The principal business operations of the Company, subsidiaries, and associates (the Group) are exploration and production of petroleumin Thailand and overseas, foreign gas pipeline transportation, and investment in projects strategically connected to the energy business.

As at December 31, 2010, the Group has operations related to the exploration and production of petroleum in 12 countries and hasinvestments in exploration and production projects with a percentage of interest as follows:

Project Country Operator

Company’spercentage of interest

2010 2009

PTT Exploration and Production PublicCompany Limited

Bongkot.......................................................... Thailand PTT Exploration and Production Plc. 44.4445 44.4445

Arthit .............................................................. Thailand PTT Exploration and Production Plc. 80 80

Arthit North ................................................... Thailand PTT Exploration and Production Plc. 100 100

Pailin .............................................................. Thailand Chevron Thailand Exploration andProduction, Ltd.

45 45

Sinphuhorm (E5 North)................................. Thailand Hess (Thailand) Ltd. 20 20

S1 ................................................................... Thailand PTTEP Siam Limited 25 25

Unocal III....................................................... Thailand Chevron Thailand Exploration andProduction, Ltd.

5 5

E5 ................................................................... Thailand ExxonMobil Exploration andProduction Khorat Inc.

20 20

Algeria Hassi Bir Rekaiz ............................. Algeria PTT Exploration and Production Plc. 24.5 —

PTTEP International Limited (PTTEPI)Yadana............................................................ Myanmar Total E&P Myanmar 25.50 25.50

Yetagun .......................................................... Myanmar Petronas Carigali Myanmar (HongKong) Ltd.

19.31784 19.31784

PTTEP 1......................................................... Thailand PTTEP International Limited 100 100

G4/43.............................................................. Thailand Chevron Offshore (Thailand) Ltd. 21.375 21.375

G9/43.............................................................. Thailand- PTTEP International Limited 100 100

Cambodia

L22/43 ............................................................ Thailand PTTEP International Limited 100 100

L53/43 & L54/43........................................... Thailand PTTEP International Limited 100 —

G4/48.............................................................. Thailand Chevron Pattani, Ltd. 5 —

Arthit (G9/48) ................................................ Thailand PTTEP International Limited 80 —

Bongkot (G12/48).......................................... Thailand PTTEP International Limited 44.4445 —

L21, 28 & 29/48 ........................................... Thailand PTTEP International Limited 70 —

A4, 5 & 6/48 ................................................. Thailand PTTEP International Limited 100 —

Unocal III (G6/50)......................................... Thailand Chevron Petroleum (Thailand), Ltd. 5 —

Pailin (G7/50) ................................................ Thailand Chevron Petroleum (Thailand), Ltd. 45 —

Arthit (G8/50) ................................................ Thailand PTTEP International Limited 80 —

Cambodia B ................................................... Cambodia PTTEP International Limited 33.333334 33.333334

Myanmar Zawtika 1 ..................................... Myanmar PTTEP International Limited 100 100

Myanmar M3, M4, M7 & M11 1 ................. Myanmar PTTEP International Limited 100 100

MTJDA -B17 ................................................. Thailand -Malaysia

Carigali-PTTEPI Operating CompanySendirian Berhad

50 50

PTTEP Offshore Investment CompanyLimited (PTTEPO)

B8/32 & 9A 2 ................................................ Thailand Chevron Offshore (Thailand) Ltd. 25.0010 25.0010

PTTEP Southwest Vietnam CompanyLimited (PTTEP SV)

Vietnam 52/97................................................ Vietnam Chevron Vietnam (Block 52), Ltd. 7 7

F-11

Project Country Operator

Company’spercentage of interest

2010 2009

PTTEP Kim Long Vietnam CompanyLimited (PTTEP KV)

Vietnam B & 48/95 ....................................... Vietnam Chevron Vietnam (Block B), Ltd. 8.50 8.50

PTTEP Hoang-Long Company Limited(PTTEP HL)

Vietnam 16-1 ................................................. Vietnam Hoang Long Joint Operating Company 28.50 28.50

PTTEP Hoan-Vu Company Limited(PTTEP HV)

Vietnam 9-2 ................................................... Vietnam Hoan-Vu Joint Operating Company 25 25

PTTEP Oman Company Limited(PTTEP OM)

Oman 44 ........................................................ Oman PTTEP Oman Company Limited 100 100

Oman 58 ........................................................ Oman PTTEP Oman Company Limited — 100

PTTEP Algeria Company Limited(PTTEP AG)

Algeria 433a & 416b..................................... Algeria — Groupement Bir Seba (fordevelopment phase)

35 35

— PetroVietnam Exploration &Production Corporation (forexploration phase)

PTTEP (Thailand) Limited (PTTEPT)Bongkot (G12/48).......................................... Thailand PTTEP (Thailand) Limited — 44.4445

Arthit (G9/48) ................................................ Thailand PTTEP (Thailand) Limited — 80

L53/43 & L54/43........................................... Thailand PTTEP (Thailand) Limited — 100

G4/48.............................................................. Thailand Chevron Pattani, Ltd. — 5

PTTEP Siam Limited (PTTEPS)Sinphuhorm (EU-1) ....................................... Thailand Hess (Thailand) Ltd. 20 20

B6/27 ............................................................ Thailand PTTEP Siam Limited 60 60

S1 ................................................................... Thailand PTTEP Siam Limited 75 75

L21, 28 & 29/48 ........................................... Thailand PTTEP Siam Limited — 70

A 4, 5 & 6/48 ................................................ Thailand PTTEP Siam Limited — 100

PTTEP Iran Company Limited (PTTEPIR)

Iran Saveh ...................................................... Iran PTTEP Iran Company Limited — 100

PTTEP Bengara I Company Limited(PTTEPB)

Indonesia Bengara-1 ..................................... Indonesia PT Medco E&P Bengara — 40

PTTEP Thai Projects Company Limited(PTTEP TP)

Unocal III (G6/50)......................................... Thailand Chevron Thailand Exploration andProduction., Ltd.

— 5

Pailin (G7/50) ................................................ Thailand Chevron Petroleum (Thailand)., Ltd. — 45

Arthit (G8/50) ................................................ Thailand PTTEP Thai Projects Company Limited — 80

PTTEP Australia Offshore Pty Limited(PTTEP AO)

Australia AC/P 36 ........................................ Australia Murphy Australia Oil Pty Ltd. 22.21 20

Australia WA 423 .......................................... Australia Murphy Australia Oil Pty Ltd. 30 30

PTTEP Bahrain Company Limited(PTTEP BH)

Bahrain 2........................................................ Bahrain PTTEP Bahrain Company Limited. 100 100

PTTEP Rommana Company Limited(PTTEPR)

Rommana ....................................................... Egypt Sipetrol International S.A. 30 30

PTTEP Semai II Limited (PTTEP SM)Indonesia Semai II......................................... Indonesia Murphy Semai Oil Co., Ltd 28.33 33.33

PTTEP Sidi Abd El Rahman CompanyLimited (PTTEP SAER)

Sidi Abd El Rahman Offshore ...................... Egypt Edison International SPA 30 30

PTTEP New Zealand Limited (PTTEPNZ)

New Zealand Great South............................. NewZealand

OMV New Zealand Limited 36 36

F-12

Project Country Operator

Company’spercentage of interest

2010 2009

PTTEP South Mandar Limited (PTTEPSMD)

Indonesia South Mandar................................ Indonesia PTTEP South Mandar Limited 67 —

PTTEP Malunda Limited (PTTEP ML)Indonesia Malunda ........................................ Indonesia PTTEP Malunda Ltd. 100 —

PTTEP Sadang Limited (PTTEP SD)Indonesia Sadang........................................... Indonesia Talisman Sadang B.V. 40 —

PTTEP South Sageri Limited (PTTEPSS)

Indonesia South Sageri.................................. Indonesia Talisman South Sageri B.V. 30 —

PTTEP Australia Perth Pty Ltd (PTTEPAP)

PTTEP Australasia * ..................................... Australia

* Details of operators and percentage of interest in PTTEP Australasia project are as follows:

Block Operator

Company’spercentage of interest

2010 2009

AC/L7, AC/L8, AC/P33, AC/P34 andAC/P40.........................................................

PTTEP Australasia (Ashmore Cartier) Pty Ltd 100 100

AC/L1, AC/L2 and AC/L3............................... PTTEP Australasia (Ashmore Cartier) Pty Ltd 89.6875 89.6875

AC/RL7............................................................. PTTEP Australasia (Ashmore Cartier) Pty Ltd 80 80

AC/P24.............................................................. PTTEP Australasia (Ashmore Cartier) Pty Ltd 60 60

AC/RL4 (Tenacious)......................................... PTTEP Australasia (Ashmore Cartier) Pty Ltd 100 75

AC/RL6 (Audacious), AC/P4, AC/RL4(exclusive of Tenacious), AC/RL5,AC/RL6 (exclusive of Audacious) andAC/P17.........................................................

PTTEP Australasia (Ashmore Cartier) Pty Ltd 50 50

AC/P32.............................................................. PTTEP Australasia (Ashmore Cartier) Pty Ltd 35 35

WA-378-P, WA-396-P and WA-397-P ............ Woodside Energy Limited 20 20

1 According to the project rearrangement, the Myanmar Zawtika project comprises concession block M9 and the northeast partof block M11, and the Myanmar blocks M3, M4, M7 and M11 excluding the northeast part of block M11.

2 PTTEPO has shareholding in Orange Energy Limited and B 8/32 Partners Limited, which holds the project’s concessions.

2. Basis of Financial Statement Preparation

The consolidated and the Company financial statements have been prepared in accordance with Thai generally accepted accountingprinciples under the Accounting Act, B.E. 2543, being those Thai Accounting Standards issued under the Accounting Profession Act, B.E. 2547including interpretation and accounting guidance announced by the Federation of Accounting Professions, as well as the financial reportingrequirements of the Securities and Exchange Commission under the Securities and Exchange Act, B.E. 2535.

The Group has adopted the International Accounting Standards (IASs) No. 12 “Income Taxes” and No. 19 “Employee Benefits”. Thecontent of these standards does not differ significantly from that of Thai Accounting Standards No. 12 and No. 19 as published in theGovernment Gazette. These accounting standards come into effect for periods beginning on or after January 1, 2013 and January 1, 2011,respectively.

Where the Group has entered into joint interest operations with other parties to participate in exploration, development and productionof petroleum businesses, the Group records its share of expenses, assets and liabilities incurred in accordance with the Statements ofExpenditures prepared by the operators of the Concession or the Production Sharing Contract. The Statements of Expenditures have beenaudited by another independent auditor on an annual basis and by the joint venture committee on a regular basis.

The consolidated and the Company financial statements have been prepared under the historical cost basis except as disclosed in theaccounting policies.

The preparation of financial statements in conformity with Thai generally accepted accounting principles requires management to makeestimates and assumptions that affect the amounts of assets, liabilities, revenues and expenses reported in the financial statements. Estimatesand assumptions are based on management’s experience and other information available which is reasonable in a particular circumstance.Although these estimates and assumptions are based on management’s best knowledge of current events and actions, actual results may differfrom these estimates and assumptions.

F-13

An English-language version of the consolidated and the Company financial statements has been translated from the statutory financialstatements which are prepared in the Thai language. In the event of a conflict or difference in the interpretation between the two languages,the Thai-language version of the statutory financial statements shall prevail.

3. Accounting Framework and Amendments to Accounting Standards, New Accounting Standards, New Financial ReportingStandards and New Financial Reporting Interpretations

The accounting framework and amendments to accounting standards, new accounting standards and new financial reporting standardswere published in the Government Gazette during the accounting period are as follows:

• Effective on May 26, 2010

Accounting framework (Revised 2009)

• Effective for periods beginning on or after January 1, 2011

Thai Accounting Standard No. 1 (Revised 2009) Presentation of Financial Statements

Thai Accounting Standard No. 2 (Revised 2009) Inventories

Thai Accounting Standard No. 7 (Revised 2009) Statement of Cash Flows

Thai Accounting Standard No. 8 (Revised 2009) Accounting Policies, Changes in Accounting Estimates andErrors

Thai Accounting Standard No. 10 (Revised 2009) Events after the Reporting Period

Thai Accounting Standard No. 11 (Revised 2009) Construction Contracts

Thai Accounting Standard No. 16 (Revised 2009) Property, Plant and Equipment

Thai Accounting Standard No. 17 (Revised 2009) Leases

Thai Accounting Standard No. 18 (Revised 2009) Revenue

Thai Accounting Standard No. 19 Employee Benefits

Thai Accounting Standard No. 23 (Revised 2009) Borrowing Costs

Thai Accounting Standard No. 24 (Revised 2009) Related Party Disclosures

Thai Accounting Standard No. 26 Accounting and Reporting by Retirement Benefit Plans

Thai Accounting Standard No. 27 (Revised 2009) Consolidated and Separate Financial Statements

Thai Accounting Standard No. 28 (Revised 2009) Investments in Associates

Thai Accounting Standard No. 29 Financial Reporting in Hyperinflationary Economies

Thai Accounting Standard No. 31 (Revised 2009) Interests in Joint Ventures

Thai Accounting Standard No. 33 (Revised 2009) Earnings per Share

Thai Accounting Standard No. 34 (Revised 2009) Interim Financial Reporting

Thai Accounting Standard No. 36 (Revised 2009) Impairment of Assets

Thai Accounting Standard No. 37 (Revised 2009) Provisions, Contingent Liabilities and Contingent Assets

Thai Accounting Standard No. 38 (Revised 2009) Intangible Assets

Thai Accounting Standard No. 40 (Revised 2009) Investment Property

Thai Financial Reporting Standard No. 2 Share-based Payment

F-14

Thai Financial Reporting Standard No. 3 (Revised2009)

Business Combinations

Thai Financial Reporting Standard No. 5 (Revised2009)

Non-current Assets Held for Sale and Discontinued Operations

Thai Financial Reporting Standard No. 6 Explorations for and Evaluation of Mineral Resources

Thai Financial Reporting Interpretations CommitteeNo. 15

Agreements for the Construction of Real Estate

• Effective for periods beginning on or after January 1, 2013

Thai Accounting Standard No. 12 Income Taxes

Thai Accounting Standard No. 20 (Revised 2009) Accounting for Government Grants and Disclosure ofGovernment Assistance

Thai Accounting Standard No. 21 (Revised 2009) The Effects of Changes in Foreign Exchange Rates

Commencing January 1, 2011, the Group will apply the amendments to accounting standards, new accounting standards, new financialreporting standards and new financial reporting interpretations as mentioned above. In addition, the Group will apply International AccountingStandard (IAS) 32 “Financial Instruments: Presentation”, IAS 39 “Financial Instruments: Recognition and Measurement” and InternationalFinancial Reporting Standard (IFRS) 7 “Financial Instruments: Disclosures”. The significant difference between Thai Accounting Standard(TAS) 105 “Accounting for Investment in Debt and Equity Securities” and IAS 39 relates to the categorization of certain investments in debtand equity securities. IAS 39 requires the financial assets, including investments in debt and equity securities to be categorized as set out inNote 4.1.2. However this has no impact on the measurement of the Group’s investment in debt and equity securities presented in the financialstatements. In addition, there is no conflict between the disclosures of financial instruments as required by IFRS 7 and TAS 107.

The Group’s management has analyzed that there is no significant impact of the amendments to accounting standards, new accountingstandards, new financial reporting standards and new financial reporting interpretations to the financial statements except as illustrated in Note4.

4. Impact of Newly Adopted Accounting Policies Being Applied on January 1, 2011

4.1 Impact of Newly Adopted Accounting Policies Being Applied Retrospectively

4.1.1 Thai Accounting Standard No. 21 (Revised 2009) “The Effects of Changes in Foreign Exchange Rates”

Thai Accounting Standard No. 21 (Revised 2009) requires the Company to determine its functional currency which is the currency ofthe primary economic environment in which the entity operates. Foreign currency transactions are required to be translated into the functionalcurrency using the spot exchange rate at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of suchtransactions and from the translation at year-end exchange rate of monetary items denominated in foreign currencies are recognized in thestatement of income in the period in which they are incurred.

However, the entity can translate the financial statements into the presentation currency, which may be different from the functionalcurrency. The results and financial position of entities whose functional currency differs from the presentation currency are translated into thepresentation currency as follows:

a) assets and liabilities are translated at the closing rate at the date of that statement of financial position;

b) income and expenses are translated at the spot exchange rate at the date of the transaction. However, the standard allows theuse of an estimated rate that is close to the spot exchange rate at the date of the transactions, for example the average exchangerate for the period. However, if exchange rates fluctuate significantly, the use of the average rate for a period is inappropriate;

c) all resulting exchange differences are recognized in other comprehensive income.

The Company’s management has determined that the USD is the functional currency of the Company, as it is the currency that has theprimary influence over sales and operating costs. The Company will apply this standard retrospectively. However, the Company is requiredto present its financial statements in Thai Baht (the presentation currency) in order to comply with the regulations of the Stock Exchange ofThailand and the Department of Business Development. The adoption of this accounting standard will have the following impacts on thefinancial statements:

Impact on the Consolidated Financial Statements

The net assets as at December 31, 2010 reported under the current accounting policy are Baht 172,294 million. After applyingthis standard, the net assets will be USD 5,405 million and reported as Baht 162,964 million after being translated into the presentationcurrency, the Thai Baht. The decrease in net assets of Baht 9,330 million results from the exchange rate at the financial statement date.In addition, the net assets presented in the Thai Baht presentation currency may increase or decrease due to the change in the exchangerate as at the end of each period.

F-15

The net profit for the year ended December 31, 2010 reported under the current accounting policy is Baht 41,739 million. Afterapplying this standard, the net profit will be USD 1,386 million reported as Baht 43,935 million after being translated into thepresentation currency, the Thai Baht. The increase in net profit of Baht 2,196 million is primarily due to the reduction in deferredincome tax liabilities resulting from the change in functional currency to the USD and the decrease in depreciation expenses resultingfrom the change in the exchange rate used in translating the financial statements into the Thai Baht presentation currency.

Impact on the Company’s Financial Statements

The net assets as at December 31, 2010 reported under the current accounting policy are Baht 126,623 million. After applyingthis standard, the net assets will be USD 3,924 million and reported as Baht 118,305 million after being translated into the presentationcurrency, the Thai Baht. The decrease in net assets of Baht 8,318 million results from the exchange rate at the financial statement date.In addition, the net assets presented in the Thai Baht presentation currency may increase or decrease due to the change in the exchangerate as at the end of each period.

The net profit for the year ended December 31, 2010 reported under the current accounting policy is Baht 29,487 million. Afterapplying this standard, the net profit will be USD 1,143 million and reported as Baht 36,265 million after being translated into thepresentation currency, the Thai Baht. The increase in net profit of Baht 6,778 million is primarily due to the reduction in deferredincome tax liabilities resulting from the change in functional currency to the USD and the decrease in depreciation expenses resultingfrom the change in the exchange rate used in translating the financial statements into the Thai Baht presentation currency.

4.1.2 International Accounting Standard No. 39 “Financial Instruments: Recognition and Measurement”

International Accounting Standard No. 39 incorporates extensive guidance on the recognition and measurement of financialinstruments, including the categorization of financial assets and liabilities, accounting for derivatives and impairment. The Group will applythis standard retrospectively as follows;

The Categorization of Financial Assets and Liabilities

The International Accounting Standard No. 39 requires financial assets to be categorized into 4 groups: 1) financial assets atfair value through profit or loss, 2) held-to-maturity investments, 3) loans and receivables and 4) available-for-sale financial assets. Thecategorization depends on the purpose for which the financial assets were acquired. Financial liabilities are either categorized as 1)financial liabilities at fair value through profit or loss 2) financial liabilities carried at amortized cost.

All financial assets and liabilities are initially recognized at fair value. Costs of financial assets or liabilities which are notcategorized as financial assets or liabilities at fair value through profit or loss are net of the transaction costs that are directly attributableto the acquisition or issue of the financial assets or financial liabilities. Subsequent accounting depends on their respective categories.

Recognition and Measurement of Financial Instruments

• Derivative Financial Instruments

Under the International Accounting Standard No. 39, derivative financial instruments are required to be marked to market atfair value and recognized on the balance sheet. Changes to fair value are recognized through the statement of income.

• Effective Interest Method

The International Accounting Standard No. 39 requires financial assets in the form of loans and receivables and held-to-maturityinvestments and financial liabilities measured at amortized costs to be initially recognized at fair value net of transaction costs and tobe subsequently carried at amortized cost using the effective interest method and recognized through the statement of income.

Impairment of Financial Assets

The International Accounting Standard No. 39 requires an entity to assess at each balance sheet date whether there is anyobjective evidence that a financial asset or group of financial assets may be impaired. If such impairment evidence exists, theimpairment loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flowsdiscounted at the financial asset’s original effective interest rate. The impairment loss is recognized in profit or loss.

Impact on the Consolidated Financial Statements

The net effect on the net assets as at December 31, 2010 is an increase of Baht 95 million, equivalent to USD 3 million, whichis primarily due to the recognition of derivative financial instruments.

The net effect on the net profit for the year ended December 31, 2010 is a decrease of Baht 161 million, equivalent to USD5 million, which is primarily due to the change in the fair value of derivative financial instruments during the year.

Impact on the Company’s Financial Statements

The net effect on the net assets as at December 31, 2010 is an increase of Baht 95 million, equivalent to USD 3 million, whichis primarily due to the recognition of derivative financial instruments.

The net effect on the net profit for the year ended December 31, 2010 is a decrease of Baht 162 million, equivalent to USD5 million, which is primarily due to the change in the fair value of derivative financial instruments during the year.

F-16

4.2 Impact of Newly Adopted Accounting Policies Being Applied Prospectively

4.2.1 Thai Accounting Standard No. 23 (Revised 2009) “Borrowing Costs”

Thai Accounting Standard No. 23(Revised 2009) requires an entity to capitalize the borrowing costs directly attributable to theacquisition, construction or production of a qualifying asset as part of the cost of that asset. The option of immediately expensing thoseborrowing costs will be removed.

4.2.2 International Accounting Standard No. 39 “Financial Instruments: Recognition and Measurement”

Hedge Accounting

Under International Accounting Standard No. 39, if hedge accounting is applied and it is appropriate based upon the specificcriteria of the International Accounting Standard No. 39, the impact of recording the derivative instrument is offset to the extent thatthe hedging relationship is effective. If a hedge is designated as a fair value hedge, changes in the derivative’s fair value are recognizedas gain or loss in the statement of income and the hedged item is marked to market for changes in fair value associated with the hedgedrisk.

If designated as a cash flow hedge, the portion of the gain or loss on the hedging instrument that is determined to be an effectivehedge shall be recognized in other comprehensive income and the ineffective portion of the gain or loss on the hedging instrument shallbe recognized in profit or loss.

4.2.3 Thai Financial Reporting Standard No. 2 “Share-based Payment”

Thai Financial Reporting Standard No.2 provides details of the accounting treatment for transactions in which an entity receives goodsor services as consideration for either:

• Equity instruments of the entity (equity-settled) which are recognized as equity; or

• Cash or other assets, where the amount is based on the price or value of the entity’s shares (cash-settled), which are recognizedas a liability.

The measurement of the transaction is based on the fair value of the goods or service received. The equity-settled transactions are notre-measured once the grant date fair value has been determined. The cash-settled transactions are required to be re-measured at each statementof financial position date and at the date of settlement, with the change in fair value recognized in the statement of income.

This standard shall be applied for the equity-settled transactions taking place on or after January 1, 2011.

4.2.4 Thai Financial Reporting Standard No. 3 (Revised 2009) “Business Combinations”

Thai Financial Reporting Standard No. 3 (Revised 2009) continues to apply the acquisition method to business combinations, unlessit is a combination involving entities or businesses under common control. Examples of significant changes in the revised standard are (a) allpayments to a business acquisition, including contingent considerations, shall be recognized at fair value on the acquisition date and changesin the fair value of contingent consideration classified as a liability are recognized in the statement of income, and (b) all acquisition-relatedcosts shall be recognized as expense in the period in which the costs are incurred. The revised standard shall be applied to businesscombinations from January 1, 2011.

4.2.5 Thai Financial Reporting Standard No. 6 “Exploration for and Evaluation of Mineral Resources”

Thai Financial Reporting Standard No. 6 states that exploration and evaluation assets (“E&E assets”) shall be initially recognized usingthe cost model and subsequently carried using the method defined in the Thai Accounting Standard No. 16 “Property, Plant and Equipment”or Thai Accounting Standard No. 38 “Intangible Assets”, depending on the classification of the E&E assets. However, this standard permitsan entity to determine an accounting policy for exploration and evaluation expenditures based on the entity’s current national GAAPaccounting policies, while expenditures incurred in the development of mineral resources will be accounted as assets in accordance with theAccounting Framework and the Thai Accounting Standard No. 38. This standard also specifically requires the entity to disclose the accountingpolicies for exploration and evaluation expenditure, including the recognition of E&E assets and the amounts of assets, liabilities, revenuesand expense and operating and investing cash flows arising from the exploration and evaluation of mineral resources.

4.3 Impact of Newly Adopted Accounting Policies on the Financial Statement Disclosures

4.3.1 Thai Accounting Standard No. 1 (Revised 2009) “Presentation of Financial Statements”

Thai Accounting Standard No. 1(Revised 2009) states that an entity shall present all income and expense items recognized in a periodin a single statement (the statement of comprehensive income) or in two statements (the separate statement of income and the statement ofcomprehensive income). In addition, this revised standard requires an entity to present a statement of financial position as at the beginningof the earliest comparative period in a complete set of financial statements when the entity makes a retrospective restatement or reclassifiesitems in the financial statements.

However, for the financial statements relating to the period beginning on or after January 1, 2011 that is the first period in which therevised standard is applied, the entity can choose to present a statement of financial position comprising only two statements without thestatement of financial position as at the beginning comparative period.

F-17

4.3.2 Thai Accounting Standard No. 24 (Revised 2009) “Related Party Disclosures”

Thai Accounting Standard No. 24 (Revised 2009) expands the definition of a related party to include a person or entity with jointcontrol over the entity, joint ventures in which the entity is a venturer and post-employment benefit plans for the benefit of employees of anentity or of a related entity.

4.3.3 International Financial Reporting Standard No. 7 “Financial Instruments: Disclosures”

International Financial Reporting Standard No. 7 requires extensive qualitative and quantitative disclosure about exposure to risksarising from financial instruments, including specified minimum disclosures about credit risk, liquidity risk and market risk and how the entitymanages those risks.

5. Significant Accounting Policies

5.1 Preparation of Consolidated Financial Statements

The consolidated financial statements comprise the Company, subsidiaries, associates and joint ventures. The major inter-companytransactions between the Company and subsidiaries are eliminated from the consolidated financial statements.

Subsidiaries

Subsidiaries are those entities over which the Group has the power to govern their financial and operating policies generallyaccompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that arecurrently exercisable or convertible, including potential voting rights held by another entity, are considered when assessing whether theGroup controls another entity. Subsidiaries are consolidated from the date on which control is transferred to the Group and are no longerconsolidated from the date that control ceases.

The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisitionis measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange,plus other costs directly attributable to the acquisition. Identifiable assets and liabilities acquired from a business combination aremeasured initially at their fair values at the acquisition date.

The excess of the cost of acquisition over the fair value of the Group’s share of the subsidiary’s identifiable net assets acquiredis recorded as goodwill; on the other hand, if the cost of acquisition is less than the fair value of the Group’s share of the subsidiary’sidentifiable net assets, the difference is recognized directly in the statement of income.

The investments in the subsidiaries are presented by using the cost method in the Company’s financial statements.

A list of subsidiaries is set out in Note 13.

Associates

Associates are those entities over which the Group has significant influence over their financial and operating policies, but doesnot control. Investments in associates are initially recognized at cost and are accounted for using the equity method in the consolidatedfinancial statements from the date on which the Group gains significant influence and are no longer consolidated from the date thatsignificant influence ceases.

The Group’s shares of the associates’ post-acquisition profits or losses are recognized in the statement of income, and its sharesof post-acquisition movements in surplus are recognized in reserves. The Group does not recognize further losses that exceed itsinvestment in the associates, unless it has incurred obligations or made payments on behalf of the associates.

Accounting policies of associates have been changed where necessary to ensure consistency with the policies adopted by theGroup.

The investments in the associates are presented by using the cost method in the Company’s financial statements.

A list of associates is set out in Note 13.

Joint Ventures

The Group’s interests in jointly controlled entities are accounted for by proportionate consolidation. Under this method, theGroup includes its shares of the joint ventures’ individual income, expenses, assets, liabilities and cash flows on a line-by-line basiswith similar items in the Group’s financial statements.

The Group’s interests in jointly controlled assets are accounted for by proportionate consolidation. Under this method, theGroup includes its shares of the assets, liabilities, expenses and cash flows based on Joint Operating Agreement on a line-by-line basiswith similar items in the Group’s financial statements.

Gains or losses from the joint ventures are presented by using the cost method in the Company’s financial statements.

For details of jointly controlled entities and jointly controlled assets, please refer to Note 13 and Note 1, respectively.

F-18

Related Parties

Related parties are those entities that directly or indirectly control, or are controlled by the Company, or are under commoncontrol with the Company. They also include holding companies, subsidiaries, fellow subsidiaries and associates.

In considering each relationship between parties, attention is directed to the substance of the relationship, not merely the legalform.

5.2 Foreign Currency Translation

Transactions included in the financial statements of each entity in the Group are measured using Thai Baht. The consolidated financialstatements are presented in Thai Baht.

Foreign currency transactions are translated into Thai Baht at the exchange rates ruling on the transaction dates. Monetary assets andliabilities denominated in foreign currency remaining at the balance sheet date are translated into Thai Baht at the exchange rate ruling on thebalance sheet date. Gains and losses arising from the settlement of foreign currency transactions and from the translation of monetary assetsand liabilities denominated in foreign currencies are recognized in the statement of income in the period in which they are incurred.

The monetary assets and liabilities of foreign operations are translated into Thai Baht using the average buying and selling ratesdetermined by the Bank of Thailand at year-end, whereas the statement of income is translated using the exchange rates ruling on thetransaction dates. Gains or losses from such translation are recognized in the statement of income in the period in which they are incurred.

The assets and liabilities of foreign entities are translated into Thai Baht using the average buying and selling rates determined by theBank of Thailand at year-end, whereas the statement of income is translated using average exchange rates during the period. Differences fromsuch translations have been presented under “Currency Translation Differences” in the shareholders’ equity.

5.3 Cash and Cash Equivalents

Cash and cash equivalents comprise cash on hand and at banks, and other short-term highly liquid investments with original maturitiesof three months or less from the date of acquisition.

5.4 Trade Accounts Receivable

Trade accounts receivable are carried at net realizable value. An allowance for doubtful accounts is provided, based on the Group’sreview of all outstanding receivable amounts at the balance sheet date. The amount of the allowance is the difference between the carryingamount of the receivable and the amount expected to be collected. Doubtful accounts are written off and recorded as expenses in the statementof income when they are identified.

Factoring Policy of Accounts Receivable

The factoring of accounts receivable is made on an arms-length basis. The company will write-off such accounts receivablewhen the future economic benefits and other major relevant benefits are transferred to the third party and the Company receives thefunds from such factoring.

5.5 Inventories

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average method. Net realizablevalue is the estimated selling price in the ordinary course of business less the costs of completion and selling expenses.

5.6 Materials and Supplies

Materials and supplies are stated at the average cost less the allowance for obsolete and unserviceable items used in petroleumexploration and production activities.

5.7 Borrowing Costs

Borrowing costs directly attributable to finance the construction of property, plant and equipment during the required period of timeor the preparation of the assets for their intended use are capitalized as part of the cost of the respective assets. All other borrowing costs areexpensed in the period in which they are incurred.

5.8 Property, Plant and Equipment

Property, plant and equipment are presented at cost, after deducting accumulated depreciation and the provision for the impairment ofassets.

F-19

• Oil and Gas Properties

The Company follows the Successful Efforts Method in accounting for its assets used for oil and gas exploration and productionactivities as follows:

Cost of Properties

Costs of properties comprise total acquisition costs of petroleum rights or the portion of costs applicable to properties as wellas the decommissioning costs.

Exploratory drilling costs are capitalized and will be classified as assets of the projects if their exploratory wells have identifiedproved reserves that have been found to be commercially producible. If, however, the exploratory wells have not identified provedreserves or have identified proved reserves but have not been found to be commercially producible, such drilling costs will be expensedin the statement of income.

Exploration costs, comprising geological and geophysical costs as well as area reservation fees during the exploration stage, arecharged to expenses when incurred.

Development costs, whether relating to the successful or unsuccessful development of wells, are capitalized.

Depreciation, Depletion and Amortization

The capitalized acquisition costs of petroleum rights are depleted and amortized using the unit of production method based onestimated proved reserves. Depreciation, depletion and amortization of exploratory wells, development, equipment and operating costsof support equipment as well as the decommissioning costs, except unsuccessful projects, are calculated on the unit of productionmethod based on estimated proved reserves or proved developed reserves. Changes in reserve estimates are recognized prospectively.

Proved reserves and proved developed reserves are calculated by the engineers of the Group and are based on the informationreceived from the joint ventures.

• Pipelines and Others

Costs of properties comprise purchase prices and other direct costs necessary to bring the asset to working condition suitable for itsintended use.

Depreciation of pipelines and others are determined using the straight-line method with an estimated useful life of 5 — 30 years.

Where the carrying amount of an asset is greater than its estimated recoverable amount, it is written down immediately to itsrecoverable amount.

Gains and losses on disposal of property, plant and equipment are determined by comparing proceeds with the carrying amount andare taken into account in the statement of income when incurred.

The cost of major renovations is included in the carrying amount of the asset when it is probable that future economic benefits in excessof the originally assessed standard of performance of the existing asset will flow to the Group.

Repair and maintenance costs are recognized as expenses when incurred.

5.9 Carried Costs under Petroleum Sharing Contract

Under Petroleum Sharing Contracts in which the government has a participation interest, some contracts require the contracting parties,excluding the government, to fund the costs of all exploration operations until the first development area is determined. During the explorationperiod, the contracting parties will carry an agreed upon proportion of the government’s exploration costs (carried costs). When the projectcommences production, such carried costs will be fully recouped without interest by the contracting parties from the production of petroleumunder the agreed procedures.

The Group classifies the transactions in respect of carried costs through various accounts based on petroleum activities using theSuccessful Efforts Method. They are mainly recorded in oil and gas properties in balance sheet and exploration expenses in the statement ofincome. (For details, please refer to Note 15.)

5.10 Intangible Assets

• Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the Group’s share of the net identifiable assets ofthe acquired subsidiaries or associates undertaking at the date of acquisition. Goodwill on acquisitions of subsidiaries is reported in theconsolidated balance sheets as an intangible asset. Goodwill on acquisitions of associates is included in investments in associates and is testedfor impairment as part of the overall balance of the investments in associates.

F-20

Goodwill is annually tested for impairment and carried at cost less accumulated impairment losses. Impairment losses on goodwill arenot reversed. Gains and losses on the disposal of an entity include the carrying amount of goodwill relating to the entity sold.

Goodwill is allocated to cash-generating units for the purpose of impairment testing. The allocation is made to a single cash-generatingunit or group of cash-generating units that are expected to benefit from the business combination in which the goodwill arose.

• Probable Reserves

Probable reserves represent reserves that were assessed by the Group at the time when there was a purchase of business. Probablereserves will be classified as oil and gas properties once they are proved reserves and amortized using the unit of production method.

• Other Intangible Assets

Other intangible assets comprise expenditures incurred for licenses acquired for computer software which are capitalized and amortizedusing the straight-line method over the remaining contract period, or a maximum of 10 years. The carrying amount is reviewed by the Groupand the allowance for impairment will be provided whenever events or circumstances indicate that the carrying amount may not be recoverable.

5.11 Impairment of Assets

Assets that have an indefinite useful life, for example goodwill, are not subject to amortization and are tested annually for impairment.Assets that are subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carryingamount may not be recoverable. An impairment loss is recognized for the amount by which the carrying amount of the assets exceeds itsrecoverable amount which is the higher of an asset’s fair value less costs to sell and its value in use, and is recorded in the statement of income.For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows.

Estimates of future cash flows used in the evaluation for impairment of assets related to petroleum production are made using riskassessment on field and reservoir performance and are inclusive of expectations about proved and unproved reserves.

Impairment, except when related to goodwill, is reversed as applicable to the extent that the events or circumstances that triggered theoriginal impairment change. If that is the case, the carrying amount of asset is increased to its recoverable amount. That increased amountcannot exceed the carrying amount that would have been determined, net of depreciation, if the Group did not recognize the impairment lossfor assets in prior year.

5.12 Deferred Income Taxes

Deferred income tax is provided in full, using the balance sheet liability method, on temporary differences arising between the tax basesof assets and liabilities and their carrying amounts in the financial statements. The principal temporary differences arise from depreciation ofproperty, plant and equipment, the amortization of decommissioning costs and the difference between the fair value of the acquired net assetsand their tax bases.

Tax rates currently enacted by the balance sheet date are used to determine deferred income tax.

Deferred tax assets are recognized to the extent that it is probable that future taxable profit will be available against which the temporarydifferences can be utilized.

Deferred income tax is provided on temporary differences arising from investments in subsidiaries, associates and joint ventures, exceptwhere the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will not reversein the foreseeable future.

Deferred income tax assets and liabilities can be offset only when they both relate to the same legal tax authority.

5.13 Deferred Remuneration under Agreement

According to the conditions in the Gas Sales Agreement of Arthit project, the Company has an obligation to make a payment to thebuyer (PTT) in its operation. The remuneration is classified as non-current asset, reported under the caption “Deferred Remuneration underAgreement”, and is amortized over the contract life using the straight-line method.

5.14 Borrowings

The Group records its borrowings at the fair value of the proceeds received, net of transaction costs incurred.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer the settlement of the liability forat least 12 months after the balance sheet date.

5.15 Leases

• Leases - where a Group company is the lessee

Leases of property, plant and equipment which substantially transfer all the risks and rewards of ownership to the lessee are classifiedas finance leases. Finance leases are capitalized at the inception of the lease at the lower of the fair value of the leased property or the presentvalue of the minimum lease payments. Each lease payment is allocated to the principal and to the finance charges so as to achieve a constant

F-21

interest rate on the finance balance outstanding. The outstanding rental obligations, net of finance charges, are included in liabilities. Theinterest element of the finance cost is charged to the statement of income over the lease period so as to achieve a constant periodic rate ofinterest on the remaining balance of the liability for each period. The property, plant and equipment acquired under finance leases aredepreciated over the shorter period of the useful life of the asset or the lease term.

Leases not transferring a significant portion of the risks and rewards of ownership to the lessee are classified as operating leases.Payments made under operating leases are charged to the statement of income on a straight-line basis over the lease period.

When an operating lease is terminated before the lease period has expired, any payment required to be made to the lessor by way ofpenalty is recognized as an expense in the period in which termination takes place.

• Leases - where a Group company is the lessor

Assets leased out under operating leases are included in property, plant and equipment in the balance sheets. They are depreciated overtheir expected useful lives on a basis consistent with other similar property, plant and equipment owned by the Group. Rental income isrecognized on a straight-line basis over the lease term.

5.16 Employee Benefits

The Group’s employees have become members in the following provident funds: “Employee of PTTEP Registered Provident Fund”,“Employee of PTTEP Registered Provident Fund 2”, “Sataporn Registered Provident Fund”, “TISCO Ruamtun 1 Registered Provident Fund”and “TISCO Ruamtun 2 Registered Provident Fund “.

The provident funds are funded by payments from employees and from the Group which are held in a separate trustee-administeredfund. The Group contributes to the funds at a rate of 3% - 15% of the employees’ salaries which are charged to the statement of income inthe period to which the contributions relate.

This obligation in respect of employees’ retirement benefits is presented in the balance sheets under the provision for employee benefitsas discussed in Note 25. In addition, the transitional liabilities will be amortized as expenses in the statement of income on a straight-line basisover 5 years.

The Group’s obligation in respect of the retirement benefit plans is calculated by estimating the amount of future benefits thatemployees will have earned in return for their services to the Company and subsidiaries in the current period and in future periods. Suchbenefits are discounted to the present value using the rate of government bond yields. The calculation is performed by an independent actuaryusing the Projected Unit Credit Method.

When the benefits under the plans change, the portion of the increased benefits relating to the past services of employees is recognizedin the statement of income on a straight-line basis over the average remaining period until the benefits become vested.

Salaries, wages, bonuses and contributions to the social security and provident funds are recognized as expenses when incurred.

5.17 Provisions

Provisions, excluding the provisions for employee benefits, are recognized when the Group has a present legal or constructiveobligation as a result of past events and it is probable that an outflow of resources will be required to settle the obligation and a reliable estimateof the amount can be made. Where the Group expects a provision to be reimbursed, for example under an insurance contract, thereimbursement is recognized as a separate asset when the reimbursement is virtually certain.

Provisions for Decommissioning Costs

The Group records a provision for decommissioning costs whenever it is probable that there is an obligation as a result of apast event and the amount of that obligation is reliable.

The Group recognizes provision for decommissioning costs, which is provided at the onset of completion of the project, for theestimate of the eventual costs that relate to the removal of the production facilities. These costs are included as part of the oil and gasproperties and are amortized based on proved reserves on a unit of production basis. The estimates of decommissioning costs aredetermined based on reviews and estimates by the Group’s own engineers and managerial judgment.

5.18 Capital Risk Management

The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to providereturns to shareholders and benefits to other stakeholders and to maintain an optimal capital structure to reduce the cost of capital.

5.19 Reserve for Expansion

The Group has a reserve for expanding its investments in new projects in the exploration phase, which is generally susceptible to highrisk, and for finding additional petroleum reserves. The reserve for expansion is set aside at no more than 35% of the net taxable income fromits exploration and production activities.

F-22

5.20 Income Recognition

Sales are recognized upon delivery of products and customer acceptance.

Service income from gas pipeline construction is recognized on the percentage of completion basis.

Interest income is recognized on a time proportion basis, taking into account the effective yield on the asset.

Revenues other than those mentioned above are recognized on an accrual basis.

5.21 Deferred Income under Agreements (Take-or-Pay)

Under Gas Sales Agreements, the Group has obligations to supply minimum quantities of gas to a customer in each contract year. Ifin any contract year, the customer has not taken the minimum quantities of gas according to the Gas Sales Agreements, customer shall payfor quantities of gas not taken (Take-or-Pay). Should the customer be unable to take the minimum contracted quantities in a given year, thevolume of gas that the customer has paid for but has not taken in that year (Make-up) can be taken free of charge in subsequent years. Paymentsreceived in advance under these agreements are recognized as deferred income. This deferred income is recognized in the statement of incomewhen the gas is subsequently taken. (For details, please refer to Note 24)

The Group made prepayments to the government of Myanmar for royalty related to cash received in advance under Take-or-PayAgreement. The prepayment will be expensed when the gas is subsequently taken by the customers. (For details, please refer to Note 18)

5.22 Income Taxes

The Group’s expenditures and revenues for tax purposes comprise:

• Current period tax which is calculated in accordance with the Petroleum Income Tax Act, B.E. 2514 and Amendment B.E. 2532and the Revenue Code

• Income tax in the Union of Myanmar

• Income tax in the Socialist Republic of Vietnam

• Corporate income tax in Australia

• Petroleum Resource Rent Tax in Australia

• Corporate income tax in the Sultanate of Oman

• Deferred income taxes, which are calculated as disclosed in Note 17.

5.23 Earnings per Share

Basic earnings per share are calculated by dividing the net income attributable to shareholders by the weighted average number ofordinary shares in issue during the year.

Diluted earnings per share are calculated by dividing the net income attributable to shareholders by the weighted average number ofordinary shares in issue during the year, adjusted with dilutive potential ordinary shares. The Company assumes that all dilutive potentialordinary shares are converted into ordinary shares in the earning per share calculation.

5.24 Segment Reporting

The segment details are primarily presented by the business operations and secondly by the geographical areas.

Business segments refer to parts of an entity that carry out business activities that are subject to risks and returns different from thoseof other business segments. Geographical segments refer to parts of an entity that carry out business operations within a particular economicenvironment that are subject to risks and returns different from those of components operating in other economic environments.

6. Major Estimates and Assumptions

In order to prepare the financial statements in conformity with the accounting standards, management is required to use estimates andassumptions which impact assets, liabilities, revenues and expenses. The data relating to the major assumptions and uncertainties in theestimate which may have an impact on the carrying amount of assets, liabilities, revenues and expenses presented in the financial statementsare as follows:

Estimate for Oil and Gas Reserves

Oil and gas reserves are key elements in the Group’s investment decision-making process which is focused on generating value. Theyare also important elements in testing for impairment. Changes in proved oil and gas reserves will also affect the present value of the net cashflows and the unit-of-production depreciation.

F-23

Proved reserves are the estimated quantities of petroleum that geological and engineering data demonstrate with reasonable certaintyto be recoverable in future years from known reservoirs under existing economic and operating conditions including government’s rules andregulations. The proved reserves have to be examined and assessed annually by the Group’s geologists and reservoir engineers.

Exploration Costs

Capitalized exploration drilling costs more than 12 months old are expensed unless (1) proved reserves are booked or (2) they havefound commercially producible quantities of reserves and they are subject to further exploration or appraisal activity. In making decisions aboutwhether to continue capitalizing exploration drilling costs for a period longer than 12 months, it is necessary to make judgments about thesatisfaction of each condition in the present event. If there is a change in one of these judgments in a subsequent period, the related capitalizedexploration drilling costs would be expensed in that period.

Impairment of Assets

Value in use of assets under consideration for impairment is assessed by the estimate for the discounted future cash flows. The expectedfuture cash flows is based on management’s estimates in relation to the future selling price, demand and supply in the market, margin rate andestimated future production volume. Expected future production volumes, which include both proved reserves as well as volumes that areexpected to constitute proved reserves in the future, are used for impairment testing because the Group believes this is the most appropriateindicator of expected future cash flows, used as a measure of value in use. The discounted rate for the impairment testing reflects the currentmarket assessment of the time value of money and the risk specific to the assets for which the future cash flow estimates have not beenadjusted.

Goodwill and Intangible Assets

For recognition and measurement of goodwill and intangible assets as of acquisition date including subsequent impairment testing,management uses estimated future cash flow from assets or cash-generating unit and appropriate discount rate for present value of future cashflow calculation.

Income Tax

The Group is subject to income taxes in numerous jurisdictions. Significant judgment is required in determining the worldwideprovision for income taxes due to the fact that there are many transactions and calculations for which the ultimate tax determination is uncertainduring the ordinary course of business. The Group recognizes liabilities for anticipated tax based on estimates of whether additional taxes willbe due. Where the final tax outcome of these matters is different from the amounts that were initially recorded, such differences will affectthe income tax and deferred tax provisions in the period in which such determination is made.

Deferred tax assets are recognized to the extent that it is probable that future taxable profits will be available against which thetemporary differences can be utilized. The management is required to make an estimate of the number of the deferred income tax assets thatshould be recognized by considering the assumption about the probable future tax benefits in each period. There may be uncertainty associatedwith the assumption used for the future taxable income in terms of whether any change will affect the recognition of the deferred tax asset.

Lease

In considering whether a lease agreement is an operating lease or a finance lease, management has exercised judgment in assessingterms and conditions of the agreement to ensure whether the risks and rewards of assets are transferred to the Group or not.

Employee Retirement Plans

The Group’s obligation regarding the retirement benefit plans is calculated by estimating the amount of future benefits that employeeswill have earned in return for their services to the Company and subsidiaries in the current and in future periods. The calculation is performedby an independent actuary using the Projected Unit Credit Method and the relevant assumptions which include financial and demographicassumptions as disclosed in Note 25.

When the benefits under the plans change, the portion of the increased benefits relating to the past services of employees is recognizedin the statement of income on a straight-line basis over the average remaining period until the benefits become vested. The expense isrecognized immediately in the statement of income when the benefits are paid.

Provisions

The provisions are recognized by the Group and presented in the balance sheets when there is an obligation as a result of a past eventand there is the possibility that the company will have to pay its beneficial assets for such an obligation when the amount can be reliablycalculated.

The Group records a provision for decommissioning costs whenever it is probable that there would be an obligation of a reliable amountas a result of a past event. The Group recognizes provision for decommissioning costs, which is provided at the onset of completion of theproject, for the estimate of the eventual costs that relate to the removal of the production facilities. These costs are included as part of the oiland gas properties and are amortized based on proved reserves on a unit of production basis. The estimates of decommissioning costs aredetermined based on reviews and estimates by the Group’s engineers and managerial judgment.

The provisions are based on the current situation such as regulations, technologies and prices. The actual results could differ from theseestimates as future confirming events occur.

F-24

7. Cash and Cash Equivalents

Cash and cash equivalents as at December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Cash on hand and at banks ....................................... 57,294.71 12,884.37 41,209.46 7,208.93

Cash equivalents

- Fixed deposits .................................................... 2,220.05 15,852.64 2,159.68 11,128.86

- Treasury bills .................................................... — 19,940.76 — 16,689.62

Total ........................................................................... 59,514.76 48,677.77 43,369.14 35,027.41

The interest rate on saving deposits held at call with banks is 0.04% — 4.50% per annum (2009: interest rate 0.07% - 3.75% perannum).

The interest rate on fixed deposits with banks is 0.33% — 5.00% per annum (2009: interest rate 0.30% - 3.97% per annum).

The interest rate on treasury bills is 1.11% - 1.75% per annum (2009: interest rate 0.78% - 1.76% per annum).

8. Trade Account Receivable — Parent Company

Trade Account receivable - parent company as at December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Sales of petroleum products...................................... 8,478.96 9,820.09 4,874.58 6,598.80

Gas pipeline construction service ............................. 1,110.41 1,098.50 1,110.41 1,098.50

Sales of topside equipment on platform................... 294.00 — 294.00 —

Total ........................................................................... 9,883.37 10,918.59 6,278.99 7,697.30

9. Trade Accounts Receivable

Trade accounts receivable as at December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Petro Summit Pty Ltd................................................ — 1,354.17 — —

Myanmar Oil and Gas Enterprise ............................. 787.84 611.80 — —

Chevron Product Company ....................................... 309.51 346.02 — 0.52

Star Petroleum Refining Co., Limited ...................... 247.39 512.47 68.99 36.62

Chevron U.S.A. INC. ................................................ — 238.84 — —

Shell International Eastern Trading Company.......... 222.51 — — —

Mercuria Energy Trading SA.................................... 198.54 — — —

Petrovietnam Exploration .......................................... — 137.31 — —

Ministry of Oil and Gas (Oman) .............................. 41.23 102.08 — —

Electricity Generating Authority of Thailand........... 35.39 40.38 8.85 10.09

Others......................................................................... 2.43 2.50 0.61 0.63

Total ........................................................................... 1,844.84 3,345.57 78.45 47.86

10. Materials and Supplies, Net

Materials and supplies, net as at December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Materials and supplies-at cost................................... 8,021.71 8,216.14 3,220.09 3,283.90

Provision for obsolescence........................................ (68.06) (70.57) (29.68) (26.73)

Materials and supplies, net........................................ 7,953.65 8,145.57 3,190.41 3,257.17

F-25

11. Other Accounts Receivable

During 2010, the Group transferred the other accounts receivable balance in respect of Stuart Petroleum Limited amounting to Baht1,356 million to exploration and production assets under “Property, Plant and Equipment”. The outstanding balance as at December 31, 2009from Stuart Petroleum Limited related to the drilling cost of the exploratory well Oliver 2 which was incurred as the Group entered into a Saleand Purchase Agreement with Auralandia Parties and Stuart Petroleum Limited (an Operator) to invest in a 100% participation interest inPetroleum Permits AC/P33 (Oliver Block). As of December 31, 2009, the transaction was conditional upon approval by the Australiangovernment. Approval was granted in February 2010.

12. Related Party Transactions

12.1 Revenues and Expenses with Related Parties

Significant transactions with related parties for the years ended December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Parent company - PTT Public Company Limited(PTT) ...................................................................

Sales revenue (world market reference price)..... 122,182.73 100,147.28 84,095.36 72,126.70

Revenue from disposal of assets.......................... 533.78 — 533.78 —

Rental revenue (market price).............................. — 21.07 — 21.07

Amortization of deferred remuneration underagreement......................................................... 59.56 59.56 59.56 59.56

Subsidiaries, associates and jointly controlledentities

Interest income ..................................................... 19.12 44.56 1,957.27 1,551.42

Management fees.................................................. — — 10.70 11.25

Rental expenses ................................................... 135.49 7.73 135.49 7.73

Interest expenses................................................... — — — 4.79

12.2 Long-term Loans to Related Parties

Long-term loans to related parties as at December 31, 2010 and 2009 comprised:

Consolidated The Company

Loans to 2010 2009 2010 2009

SubsidiariesPTTEPI ................................................................. — — 33,896.59 29,257.77

PTTEPO................................................................ — — 26,279.17 28,355.05

PTTEP Services .................................................... — — 76.20 106.41

AssociatesEnCo ..................................................................... 580.00 490.00 580.00 490.00

ShoreAir................................................................ 10.79 14.74 — —

Total ................................................................. 590.79 504.74 60,831.96 58,209.23

Movements of long-term loans to related parties for the year ended December 31, 2010 are as follows:

Consolidated The Company

Balance as at January 1, 2010 ........................................................................................ 504.74 58,209.23

Addition ........................................................................................................................... 90.00 41,694.76

Repayment ....................................................................................................................... (3.95) (39,045.54)

Currency translation differences ..................................................................................... — (26.49)

Balance as at December 31, 2010 .................................................................................. 590.79 60,831.96

The Company has loans to subsidiaries with an interest rate of 3.46% — 3.73% per annum (2009: interest rate 2.73% - 4.07% perannum). The subsidiaries shall occasionally repay the loans. In addition, the Company provided loans to an associate with an interest rate of3.15% - 3.60 % per annum (2009: interest rate 3.25% - 6.75 % per annum).

F-26

13.

Inve

stm

ents

inSu

bsid

iari

es,A

ssoc

iate

san

dJo

intl

yC

ontr

olle

dE

ntit

ies

13.1

Det

ails

ofth

esu

bsid

iari

es,

asso

ciat

es,

and

join

tlyco

ntro

lled

entit

ies

Com

pany

Reg

iste

red

Cou

ntry

Typ

eof

busi

ness

Pai

d-in

capi

tal1

Shar

ehol

ding

by

Per

cent

age

ofin

tere

st

Inve

stm

ents

Div

iden

dsfo

rth

eye

ars

Cos

tM

etho

dE

quit

yM

etho

d

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

Subs

idia

ries

PTT

EP

Inte

rnat

iona

lL

imite

d(P

TT

EPI

)...

Tha

iland

Petr

oleu

m20

,000

.00

20,0

00.0

0PT

TE

P10

0%10

0%20

,000

.00

20,0

00.0

041

,371

.03

35,7

46.4

6—

—

PTT

EP

Off

shor

eIn

vest

men

tC

ompa

nyL

imite

d...

......

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m0.

170.

17PT

TE

P75

%75

%0.

130.

1322

,705

.85

15,7

90.3

6—

—

(PT

TE

PO).

......

......

......

......

......

......

......

......

.PT

TE

PI25

%25

%0.

040.

047,

583.

885,

273.

35—

—

PTT

EP

Sout

hwes

tV

ietn

amC

ompa

nyL

imite

d(P

TT

EP

SV).

......

......

......

......

..C

aym

anIs

land

sPe

trol

eum

2.03

2.03

PTT

EPO

100%

100%

2.03

2.03

(227

.79)

(247

.76)

——

PTT

EP

Kim

Lon

gV

ietn

amC

ompa

nyL

imite

d(P

TT

EP

KV

)....

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m2.

032.

03PT

TE

PO10

0%10

0%2.

032.

03(3

96.7

3)(4

27.8

3)—

—

PTT

EP

Hoa

ng-L

ong

Com

pany

Lim

ited

(PT

TE

PH

L).

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m2.

122.

12PT

TE

PO10

0%10

0%2.

122.

12(6

,233

.14)

(6,7

65.9

6)—

—

PTT

EP

Hoa

n-V

uC

ompa

nyL

imite

d(P

TT

EP

HV

)....

......

......

......

......

......

......

.C

aym

anIs

land

sPe

trol

eum

2.16

2.16

PTT

EPO

100%

100%

2.16

2.16

(657

.50)

(1,1

67.9

8)—

—

PTT

EP

Om

anC

ompa

nyL

imite

d(P

TT

EP

OM

)....

......

......

......

......

......

......

Cay

man

Isla

nds

Petr

oleu

m2.

162.

16PT

TE

PO10

0%10

0%2.

162.

16(2

,046

.74)

(836

.54)

——

PTT

EP

Alg

eria

Com

pany

Lim

ited

(PT

TE

PA

G).

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m2.

102.

10PT

TE

PO10

0%10

0%2.

102.

10(2

,272

.27)

(2,4

39.4

2)—

—

PTT

EP

(Tha

iland

)L

imite

d(P

TT

EPT

)2

..T

haila

ndPe

trol

eum

100.

0010

0.00

PTT

EPI

100%

100%

100.

0010

0.00

(36.

23)

28.8

8—

—

PTT

EP

Serv

ices

Lim

ited

(PT

TE

PSe

rvic

es).

......

......

......

......

......

......

......

....

Tha

iland

Serv

ices

1.00

1.00

PTT

EP

25%

25%

0.25

0.25

9.73

2.72

—35

.99

PTT

EPI

75%

75%

1.59

1.59

22.3

21.

28—

—

PTT

EP

Siam

Lim

ited

(PT

TE

PS).

......

......

.T

haila

ndPe

trol

eum

100.

0010

0.00

PTT

EP

51%

51%

3,87

2.76

3,87

2.76

5,58

5.36

6,25

3.83

4,08

0.00

1,91

1.01

PTT

EPO

49%

49%

3,71

3.33

3,71

3.33

5,43

8.96

6,08

0.88

3,91

9.98

1,98

8.99

F-27

Com

pany

Reg

iste

red

Cou

ntry

Typ

eof

busi

ness

Pai

d-in

capi

tal1

Shar

ehol

ding

by

Per

cent

age

ofin

tere

st

Inve

stm

ents

Div

iden

dsfo

rth

eye

ars

Cos

tM

etho

dE

quit

yM

etho

d

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

PTT

EP

Iran

Com

pany

Lim

ited

(PT

TE

PIR

)....

......

......

......

......

......

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m1.

911.

91PT

TE

PO

M10

0%10

0%1.

911.

91(2

,142

.80)

(2,1

23.4

8)—

—

PTT

EP

Mer

angi

nC

ompa

nyL

imite

d(P

TT

EPM

)....

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m2.

052.

05PT

TE

PO10

0%10

0%2.

052.

05(4

51.9

7)(4

68.4

5)—

—

PTT

EP

Bah

rain

Com

pany

Lim

ited

(PT

TE

PB

H).

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m1.

901.

90PT

TE

PO

M10

0%10

0%1.

901.

90(3

92.7

2)(3

75.8

6)—

—

PTT

EP

Hol

ding

Com

pany

Lim

ited

(PT

TE

PH).

......

......

......

......

......

......

......

..C

aym

anIs

land

sPe

trol

eum

1.88

1.88

PTT

EPO

100%

100%

1.88

1.88

(5,1

89.0

6)(9

,326

.88)

——

PTT

EP

Indo

nesi

aC

ompa

nyL

imite

d(P

TT

EP

ID).

......

......

......

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m1.

881.

88PT

TE

PH10

0%10

0%1.

881.

88(6

06.5

9)(4

49.6

1)—

—

PTT

EP

Ben

gara

IC

ompa

nyL

imite

d(P

TT

EPB

)....

......

......

......

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m1.

881.

88PT

TE

PID

100%

100%

1.88

1.88

(271

.12)

(286

.88)

——

PTT

EP

Tha

iPr

ojec

tsC

ompa

nyL

imite

d(P

TT

EP

TP)

3...

......

......

......

......

......

......

Tha

iland

Petr

oleu

m1.

001.

00PT

TE

PT10

0%10

0%1.

001.

00(2

2.83

)(1

6.35

)—

—

PTT

EP

And

aman

Lim

ited

(PT

TE

PA

)....

.T

haila

ndPe

trol

eum

0.25

0.25

PTT

EPS

100%

100%

0.25

0.25

0.05

0.10

——

PTT

EP

Egy

ptC

ompa

nyL

imite

d(P

TT

EP

EG

)....

......

......

......

......

......

......

.C

aym

anIs

land

sPe

trol

eum

1.69

1.69

PTT

EPH

100%

100%

1.69

1.69

(1,0

18.0

4)(7

20.8

6)—

—

PTT

EP

Rom

man

aC

ompa

nyL

imite

d(P

TT

EPR

)....

......

......

......

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m1.

691.

69PT

TE

PE

G10

0%10

0%1.

691.

69(1

97.5

1)(5

3.64

)—

—

PTT

EP

Sidi

Abd

El

Rah

man

Com

pany

Lim

ited

(PT

TE

PSA

ER

)....

......

......

......

Cay

man

Isla

nds

Petr

oleu

m1.

691.

69PT

TE

PE

G10

0%10

0%1.

691.

69(8

17.8

3)(6

64.5

1)—

—

PTT

EP

Aus

tral

iaPt

yL

imite

d(P

TT

EP

AU

)*.

......

......

......

......

......

......

......

......

...A

ustr

alia

Petr

oleu

m1.

531.

53PT

TE

PH10

0%10

0%1.

531.

53(1

,426

.29)

(1,4

99.2

7)—

—

PTT

EP

Ban

glad

esh

Lim

ited

(PT

TE

PB

D).

......

......

......

......

......

......

......

......

......

Cay

man

Isla

nds

Petr

oleu

m1.

671.

67PT

TE

PH10

0%10

0%1.

671.

67(3

15.8

8)(3

37.9

1)—

—

PTT

EP

Mya

nmar

Lim

ited

(PT

TE

PM

YA

)1...

......

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m1.

591.

59PT

TE

PH10

0%10

0%1.

591.

591.

181.

45—

—

F-28

Com

pany

Reg

iste

red

Cou

ntry

Typ

eof

busi

ness

Pai

d-in

capi

tal1

Shar

ehol

ding

by

Per

cent

age

ofin

tere

st

Inve

stm

ents

Div

iden

dsfo

rth

eye

ars

Cos

tM

etho

dE

quit

yM

etho

d

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

PTT

EP

New

Zea

land

Lim

ited

(PT

TE

PN

Z)

......

......

......

......

......

......

......

......

......

Cay

man

Isla

nds

Petr

oleu

m1.

701.

70PT

TE

PH10

0%10

0%1.

701.

70(5

33.6

5)(4

76.7

8)—

—

PTT

EP

Sem

aiII

Lim

ited

(PT

TE

PSM

)..

Cay

man

Isla

nds

Petr

oleu

m1.

741.

74PT

TE

PID

100%

100%

1.74

1.74

(234

.04)

(160

.28)

——

PTT

EP

Aus

tral

iaPe

rth

Pty

Lim

ited

(PT

TE

PA

P)*...

......

......

......

......

......

......

Aus

tral

iaPe

trol

eum

1.20

1.20

PTT

EPH

100%

100%

1.20

1.20

(1,2

35.4

0)(5

,833

.44)

——

And

aman

Tran

spor

tatio

nL

imite

d(A

TL

)1

..C

aym

anIs

land

sG

aspi

pelin

etr

ansp

orta

tion

1.74

1.74

PTT

EPO

100%

100%

1.74

1.74

1.16

1.48

——

PTT

EP

Inte

rnat

iona

lH

oldi

ngC

ompa

nyL

imite

d(P

TT

EP

IH)

4...

......

......

......

.....

Cay

man

Isla

nds

Petr

oleu

m1.

771.

77PT

TE

PH10

0%10

0%1.

771.

77(4

2.68

)1.

48—

—

PTT

EP

Sout

hwes

tV

ietn

amPi

pelin

eC

ompa

nyL

imite

d...

......

......

......

......

.....

Cay

man

Isla

nds

Gas

pipe

line

1.64

—PT

TE

PH10

0%—

1.64

—1.

04—

——

(PT

TE

PSV

PC).

......

......

......

......

......

......

....

tran

spor

tatio

n

PTT

EP

FLN

GH

oldi

ngC

ompa

nyL

imite

d(P

TT

EP

FH)

1...

......

......

......

....

Hon

gK

ong

Petr

oleu

m0.

04—

PTT

EP

IH10

0%—

0.04

—(1

.02)

——

—

PTT

EP

Bra

zil

Hol

ding

Lim

ited

(PT

TE

PB

R)

1...

......

......

......

......

......

......

......

......

..C

aym

anIs

land

sPe

trol

eum

1.61

—PT

TE

PIH

100%

—1.

61—

1.32

——

—

PTT

EP

Net

herl

and

Hol

ding

Lim

ited

(PT

TE

PN

L).

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m1.

61—

PTT

EP

IH10

0%—

1.61

—(4

0.79

)—

——

JVM

arin

eL

imite

d(J

VM

arin

e)1

,5...

......

Cay

man

Isla

nds

Petr

oleu

m1.

61—

PTT

EP

IH10

0%—

1.61

—1.

32—

——

PTT

EP

Sout

hM

anda

rL

imite

d(P

TT

EP

SMD

)....

......

......

......

......

......

......

......

......

Cay

man

Isla

nds

Petr

oleu

m1.

61—

PTT

EP

ID10

0%—

1.61

—(3

2.27

)—

——

PTT

EP

Sout

hSa

geri

Lim

ited

(PT

TE

PSS

)....

......

......

......

......

......

......

......

......

....

Cay

man

Isla

nds

Petr

oleu

m1.

61—

PTT

EP

ID10

0%—

1.61

—(1

8.27

)—

——

PTT

EP

Sada

ngL

imite

d(P

TT

EP

SD).

.....

Cay

man

Isla

nds

Petr

oleu

m1.

61—

PTT

EP

ID10

0%—

1.61

—(1

1.92

)—

——

F-29

Com

pany

Reg

iste

red

Cou

ntry

Typ

eof

busi

ness

Pai

d-in

capi

tal1

Shar

ehol

ding

by

Per

cent

age

ofin

tere

st

Inve

stm

ents

Div

iden

dsfo

rth

eye

ars

Cos

tM

etho

dE

quit

yM

etho

d

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

PTT

EP

Mal

unda

Lim

tied

(PT

TE

PM

L).

..C

aym

anIs

land

sPe

trol

eum

1.61

—PT

TE

PID

100%

—1.

61—

(30.

38)

——

—

PTT

EP

Net

herl

ands

Coö

pera

tieU

.A.

(PT

TE

PN

C)

1...

......

......

......

......

......

.....

Net

herl

ands

Petr

oleu

m0.

02—

PTT

EP

IH1%

—0.

02—

(0.1

4)—

——

1.48

—PT

TE

PN

L99

%—

1.48

—(1

4.20

)—

——

PTT

EP

Can

ada

Lim

ited

(PT

TE

PC

A)

1...

Can

ada

Petr

oleu

m1.

47—

PTT

EP

NC

100%

—1.

47—

(14.

38)

——

—

Ass

ocia

tes

Ene

rgy

Com

plex

Com

pany

Lim

ited

(EnC

o)...

......

......

......

......

......

......

......

....

Tha

iland

Com

mer

ce1,

800.

001,

800.

00PT

TE

P50

%50

%90

0.00

900.

0076

2.45

803.

76—

—

PTT

ICT

Solu

tions

Com

pany

Lim

ited

(PT

TIC

T)

......

......

......

......

......

......

......

.T

haila

ndSe

rvic

es15

0.00

150.

00PT

TE

P20

%20

%30

.00

30.0

039

.61

40.0

3—

—

PTT

EP

AP

grou

p’s

Ass

ocia

tes

6...

......

......

Aus

tral

iaSe

rvic

es33

.77

33.7

7PT

TE

PA

AO

50%

50%

16.8

816

.88

75.4

278

.52

——

Join

tly

Con

trol

led

Ent

itie

s...

......

......

.....

Car

igal

i—

PTT

EPI

Ope

ratin

gC

ompa

nySd

nB

hd.

......

......

......

......

......

......

......

...M

alay

sia

Petr

oleu

m3.

683.

68PT

TE

PI50

%50

%1.

841.

841.

711.

70—

—

(CPO

C)

......

......

......

......

......

......

......

......

.....

Moa

ttam

aG

asT

rans

port

atio

nC

ompa

ny(M

GT

C).

......

......

......

......

......

......

......

.....

Ber

mud

aG

aspi

pelin

e0.

760.

76PT

TE

PO25

.5%

25.5

%0.

190.

191,

523.

111,

521.

842,

670.

683,

479.

45

tran

spor

tatio

n

Tani

ntha

yiPi

pelin

eC

ompa

nyL

LC

(TPC

)....

......

......

......

......

......

......

......

......

Cay

man

Isla

nds

Gas

pipe

line

2.62

2.62

PTT

EPO

19.3

178%

19.3

178%

445.

3344

5.33

1,37

9.92

1,34

7.68

1,59

0.05

1,98

2.92

tran

spor

tatio

n

Ora

nge

Ene

rgy

Lim

ited

(Ora

nge)

......

......

.T

haila

ndPe

trol

eum

100.

0010

0.00

PTT

EPO

53.9

496%

53.9

496%

13,5

67.6

913

,567

.69

7,10

6.33

7,85

4.78

1,99

3.81

1,43

5.68

F-30

Com

pany

Reg

iste

red

Cou

ntry

Typ

eof

busi

ness

Pai

d-in

capi

tal1

Shar

ehol

ding

by

Per

cent

age

ofin

tere

st

Inve

stm

ents

Div

iden

dsfo

rth

eye

ars

Cos

tM

etho

dE

quit

yM

etho

d

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

B8/

32Pa

rtne

rsL

imite

d(B

8/32

Part

ners

).T

haila

ndPe

trol

eum

110.

0011

0.00

PTT

EPO

25.0

009%

25.0

009%

4,52

3.69

4,52

3.69

2,13

1.56

2,77

8.88

992.

4433

2.14

PTT

FLN

GL

imite

d(P

TT

FLN

G).

......

....

Hon

gK

ong

Petr

oleu

m0.

02—

PTT

EP

FH50

%—

0.02

—(0

.74)

——

—

Rel

atio

nshi

p:T

heC

ompa

nydi

rect

lyor

indi

rect

lyho

lds

the

shar

esin

subs

idia

ries

,as

soci

ates

,an

djo

intly

cont

rolle

den

titie

s.Su

bsid

iari

es’

man

agem

ent

team

sar

efr

omth

eC

ompa

ny.

1A

sat

Dec

embe

r31

,20

10,

PTT

EP

MY

A,A

TL

,PT

TE

PFH

,PT

TE

PB

R,

JVM

arin

e,PT

TE

PN

Can

dPT

TE

PC

Aha

vesh

ares

rece

ivab

le.

2A

sat

Dec

embe

r24

,20

10,

PTT

EPT

has

regi

ster

edfo

rth

edi

ssol

utio

nw

ithth

eM

inis

try

ofC

omm

erce

and

isin

the

proc

ess

ofliq

uida

tion.

3A

sat

Nov

embe

r29

,20

10,

PTT

EP

TP

has

regi

ster

edfo

rth

edi

ssol

utio

nw

ithth

eM

inis

try

ofC

omm

erce

and

isin

the

proc

ess

ofliq

uida

tion.

4PT

TE

PW

estA

fric

aC

ompa

nyL

imite

dw

asch

ange

dto

PTT

EP

Inte

rnat

iona

lH

oldi

ngC

ompa

nyL

imite

d.

5PT

TE

PSo

uth

Am

eric

aH

oldi

ngL

imite

dw

asch

ange

dto

JVM

arin

eL

imite

d.

6PT

TE

PA

Pgr

oup’

sA

ssoc

iate

sar

eSh

oreA

irPt

yL

tdan

dT

roug

hton

Isla

ndPt

yL

td.

*D

etai

lsof

PTT

EP

AU

’san

dPT

TE

PA

Pgr

oup’

ssu

bsid

iari

esar

eas

follo

ws:

F-31

Company Registered countryPercentage of

interest

PTTEP Australia Pty Limited (PTTEP AU)’s subsidiaryPTTEP Australia Offshore Pty Limited (PTTEP AO) ................................................... Australia 100%

PTTEP Australia Perth Pty Limited (PTTEP AP) group’s subsidiaries ...............

PTTEP Australia Browse Basin Pty Limited (PTTEP AB) ........................................... Australia 100%

PTTEP Australia International Finance Pty Ltd (PTTEP AIF)...................................... Australia 100%

PTTEP Australasia Pty Limited (PTTEP AA)................................................................ Australia 100%

PTTEP Australia Timor Sea Pty Limited (PTTEP AT).................................................. Australia 100%

PTTEP Australasia (Finance) Pty Ltd (PTTEP AAF).................................................... Australia 100%

PTTEP Australasia (Petroleum) Pty Ltd (PTTEP AAP) ................................................ Australia 100%

Tullian Pty Ltd (PTTEP AAT) 1 ..................................................................................... Australia 100%

PTTEP Australasia (Operations) Pty Ltd (PTTEP AAO) .............................................. Australia 100%

PTTEP Australasia (Ashmore Cartier) Pty Ltd (PTTEP AAA)..................................... Australia 100%

PTTEP Australasia (Staff) Pty Ltd (PTTEP AAS)......................................................... Australia 100%

1 PTTEP Australasia (Tullian) Pty Ltd was changed to Tullian Pty Ltd

13.2 Investments in Subsidiaries, Associates, and Jointly Controlled Entities

Changes of investments in subsidiaries and associates which are accounted for using the equity method for the consolidated financialstatements and using the cost method for the Company’s financial statements are as follows:

Consolidated The Company

2010 2009 2010 2009

Net book value as at the beginning of the year....... 922.31 384.34 24,803.14 24,149.40

Share of net loss from investment after incometaxes ...................................................................... (44.83) (17.86) — —

Increase in investment............................................... — 552.14 — 653.74

Currency translation differences ............................... — 3.69 — —

Net book value as at the end of the year ................. 877.48 922.31 24,803.14 24,803.14

13.3 Investments in Subsidiaries

Investments in subsidiaries accounted for using the cost method for the Company’s financial statements are as follows:

The Company

2010 2009

PTTEP International Limited .......................................................................................... 20,000.00 20,000.00

PTTEP Offshore Investment Company Limited ........................................................... 0.13 0.13

PTTEP Services Limited ................................................................................................. 0.25 0.25

PTTEP Siam Limited ...................................................................................................... 3,872.76 3,872.76

Total ................................................................................................................................. 23,873.14 23,873.14

13.4 Investments in Associates

Investments in associates accounted for using the equity method for the consolidated financial statements and using the cost methodfor the Company’s financial statements are as follows:

Consolidated The Company

2010 2009 2010 2009

Energy Complex Company Limited ......................... 762.45 803.76 900.00 900.00

PTT ICT Solutions Company Limited ..................... 39.61 40.03 30.00 30.00

PTTEP AP group’s associates ................................... 75.42 78.52 — —

Total ........................................................................... 877.48 922.31 930.00 930.00

F-32

Share of assets, liabilities, income and gains (losses) from associates as at December 31, 2010 and 2009 are as follows:

EnCo ICTPTTEP AP group’s

associates

2010 2009 2010 2009 2010 2009

Assets ........................................... 4,017.18 3,943.98 264.49 176.36 85.83 92.85

Liabilities .................................... 3,254.73 3,140.22 224.88 136.33 10.41 14.33

Income.......................................... 417.15 13.60 236.11 170.70 30.70 74.99

Gains (losses)............................... (41.31) (33.65) (0.42) (6.90) (3.10) 22.69

F-33

13.5

Inve

stm

ents

inJo

intly

Con

trol

led

Ent

ities

Inve

stm

ents

injo

intly

cont

rolle

den

titie

sar

ere

cord

edin

the

Com

pany

’sfi

nanc

ials

tate

men

tsus

ing

the

cost

met

hod.

The

Com

pany

pres

ents

itssh

are

ofth

eas

sets

,lia

bilit

ies,

reve

nues

and

expe

nses

ofjo

intly

cont

rolle

den

titie

s,to

geth

erw

ithsi

mila

rite

ms,

unde

rsi

mila

rhe

adin

gsin

the

prop

ortio

nate

cons

olid

ated

fina

ncia

lst

atem

ents

.

Tra

nsac

tions

ofjo

intly

cont

rolle

den

titie

sar

ein

clud

edin

the

Com

pany

’sfi

nanc

ial

stat

emen

tsas

follo

ws:

CP

OC

MG

TC

TP

CO

rang

eB

8/32

Par

tner

sP

TT

FL

NG

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

Bal

ance

Shee

ts:

Cur

rent

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

193.

7462

2.09

735.

2968

2.82

447.

0835

8.24

3,33

0.33

3,40

1.07

855.

7699

5.71

0.02

—

Non

-cur

rent

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.—

—2,

423.

772,

830.

511,

367.

381,

585.

435,

800.

335,

905.

251,

890.

872,

176.

58—

—

Cur

rent

liabi

litie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...(1

92.0

3)(6

20.3

9)(1

8.20

)(1

9.73

)(2

1.44

)(2

3.31

)(2

,036

.32)

(2,1

07.1

2)(5

10.6

8)(4

74.7

9)(0

.76)

—

Non

-cur

rent

liabi

litie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..—

—(1

,388

.45)

(1,7

45.8

3)(4

28.5

7)(5

62.2

3)(2

,000

.75)

(1,9

95.4

6)(6

63.4

6)(7

35.7

6)—

—

Net

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...1.

711.

701,

752.

411,

747.

771,

364.

451,

358.

135,

093.

595,

203.

741,

572.

491,

961.

74(0

.74)

—

CP

OC

MG

TC

TP

CO

rang

eB

8/32

Par

tner

sP

TT

FL

NG

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

2010

2009

Stat

emen

tsof

Inco

me

:

Rev

enue

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

——

4,23

8.68

4,50

1.66

2,79

1.37

2,92

6.94

8,71

8.51

8,36

7.69

3,07

7.24

2,79

5.65

——

Exp

ense

s...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

——

(274

.70)

(273

.03)

(192

.16)

(190

.28)

(4,9

24.6

8)(5

,788

.18)

(1,7

43.0

3)(1

,934

.18)

(0.7

6)—

Inco

me

befo

rein

com

eta

xes

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

——

3,96

3.98

4,22

8.63

2,59

9.21

2,73

6.66

3,79

3.83

2,57

9.51

1,33

4.21

861.

47(0

.76)

—

Inco

me

taxe

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

——

(1,1

39.2

8)(1

,247

.01)

(766

.23)

(825

.95)

(1,9

10.1

7)(1

,255

.02)

(731

.01)

(342

.33)

——

Net

inco

me.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

——

2,82

4.70

2,98

1.62

1,83

2.98

1,91

0.71

1,88

3.66

1,32

4.49

603.

2051

9.14

(0.7

6)—

F-34

14. Property, Plant and Equipment, Net

Consolidated

Oil and Gas Properties

Pipeline Others Total

ProvedProperties

andRelated

ProducingProperties

UnprovedProperties

SupportEquipment

andFacilities

DecommissioningCosts

Historical costBalance as at January 1,

2009............................. 248,382.58 10,194.63 3,307.56 17,698.99 7,082.48 2,659.94 289,326.18Acquisition of

subsidiaries ................ 18,152.71 — 92.79 1,573.11 — — 19,818.61Increase ............................ 51,017.82 2,082.11 263.14 3,956.41 13.52 487.45 57,820.45Decrease .......................... (4,013.62) (3,843.83) (8.73) — — (57.03) (7,923.21)Reclassification ................ 7,064.68 (7,064.68) — — — — —Currency translation

differences*................. — — — — (319.47) — (319.47)

Balance as at December31, 2009 ...................... 320,604.17 1,368.23 3,654.76 23,228.51 6,776.53 3,090.36 358,722.56

Increase ............................ 49,351.69 1,425.12 410.25 4,136.00 45.20 1,191.43 56,559.69Decrease .......................... (1,285.58) (377.59) (47.82) — — (970.73) (2,681.72)Reclassification ................ (178.81) 178.81 14.75 — — (14.75) —Currency translation

differences*................. — — — — (654.20) — (654.20)

Balance as at December31, 2010 ...................... 368,491.47 2,594.57 4,031.94 27,364.51 6,167.53 3,296.31 411,946.33

Accumulateddepreciation

Balance as at January 1,2009............................. (109,634.59) — (2,139.31) (5,844.40) (2,460.22) (1,363.50) (121,442.02)

Acquisition ofsubsidiaries ................ — — (46.90) (6.73) — — (53.63)

Depreciation for theyear.............................. (26,951.55) — (236.21) (2,442.29) (230.48) (262.57) (30,123.10)

Decrease .......................... 0.23 — 9.30 (0.49) — 50.00 59.04Currency translation

differences*................. — — — — 104.18 — 104.18

Balance as at December31, 2009 ...................... (136,585.91) — (2,413.12) (8,293.91) (2,586.52) (1,576.07) (151,455.53)

Depreciation for theyear.............................. (31,288.69) (11.46) (303.77) (2,928.64) (231.29) (229.40) (34,993.25)

Decrease .......................... 100.31 — 51.36 (0.56) — 890.17 1,041.28Currency translation

differences*................. — — — — 265.88 — 265.88

Balance as at December31, 2010 ...................... (167,774.29) (11.46) (2,665.53) (11,223.11) (2,551.93) (915.30) (185,141.62)

Provision forimpairment losses

Balance as at January 1,2009............................. (468.04) (90.03) — — — — (558.07)

Increase ............................ (3.66) — — — — — (3.66)

Balance as at December31, 2009 ...................... (471.70) (90.03) — — — — (561.73)

Increase ............................ (0.54) — — — — — (0.54)Decrease........................... — 90.03 — — — — 90.03

Balance as at December31, 2010 ...................... (472.24) — — — — — (472.24)

Net book value as atDecember 31, 2009 .... 183,546.56 1,278.20 1,241.64 14,934.60 4,190.01 1,514.29 206,705.30

Net book value as atDecember 31, 2010 .... 200,244.94 2,583.11 1,366.41 16,141.40 3,615.60 2,381.01 226,332.47

Depreciation included in the statement of income for the year ended December 31, 2009 Baht 30,123.10 Million Million

Depreciation included in the statement of income for the year ended December 31, 2010 Baht 34,993.25 Million Million

* Differences from foreign exchange as a result of the account translation.

F-35

The Company

Oil and Gas Properties

Others Total

ProvedProperties

and RelatedProducingProperties

UnprovedProperties

SupportEquipment

andFacilities

DecommissioningCosts

Historical costBalance as at January 1, 2009 ............. 126,352.01 — 1,519.98 11,046.41 1,789.22 140,707.62

Increase ................................................ 20,054.29 — 15.60 737.17 459.39 21,266.45

Decrease ............................................... (11.73) — (3.70) — (56.09) (71.52)

Balance as at December 31, 2009 ....... 146,394.57 — 1,531.88 11,783.58 2,192.52 161,902.55

Increase ................................................ 27,352.54 9.64 155.33 1,358.15 1,065.48 29,941.14

Decrease ............................................... (255.71) — (47.82) — (947.96) (1,251.49)

Balance as at December 31, 2010 ....... 173,491.40 9.64 1,639.39 13,141.73 2,310.04 190,592.20

Accumulated depreciationBalance as at January 1, 2009 ............. (54,387.07) — (1,020.22) (3,102.42) (1,211.84) (59,721.55)

Depreciation for the year ..................... (16,510.02) — (58.99) (1,115.74) (218.81) (17,903.56)

Decrease ............................................... — — 3.70 — 49.02 52.72

Balance as at December 31, 2009 ....... (70,897.09) — (1,075.51) (4,218.16) (1,381.63) (77,572.39)

Depreciation for the year ..................... (19,186.45) — (77.70) (1,258.25) (184.04) (20,706.44)

Decrease ............................................... 94.87 — 47.82 — 867.93 1,010.62

Balance as at December 31, 2010 ....... (89,988.67) — (1,105.39) (5,476.41) (697.74) (97,268.21)

Net book value as at December 31,2009.................................................. 75,497.48 — 456.37 7,565.42 810.89 84,330.16

Net book value as at December 31,2010.................................................. 83,502.73 9.64 534.00 7,665.32 1,612.30 93,323.99

Depreciation included in the statement of income for the year ended December 31, 2009 Baht 17,903.56 Million

Depreciation included in the statement of income for the year ended December 31, 2010 Baht 20,706.44 Million

15. Carried Cost under Petroleum Sharing Contract

As at December 31, 2010, the Group presented carried costs under oil and gas properties and other non-current assets in the balancesheets and presented exploration expenses in the statement of income for the following projects:

Project

Carried Cost

Oil and GasProperties

OtherNon-Current

Assets

ExplorationExpenses

(Cumulativesince 2002 -

December 31,2010)

Vietnam 52/97............................................................................................................... — 30.42 —

Vietnam B & 48/95 ...................................................................................................... — 31.84 —

Vietnam 16-1 ................................................................................................................ 904.42 — 1,305.74

Vietnam 9-2 .................................................................................................................. 1,181.59 — 811.23

Algeria 433a & 416b.................................................................................................... 281.13 — 434.66

F-36

16. Intangible Assets, Net

Consolidated The Company

GoodwillProbableReserves

OtherIntangible

Assets Total

OtherIntangible

Assets

Historical costsBalance as at January 1, 2009.............................. — — 985.12 985.12 830.50

Increase.................................................................. — — 65.78 65.78 50.55

Acquisition of subsidiary ..................................... 184.82 3,382.68 — 3,567.50 —

Balance as at December 31, 2009........................ 184.82 3,382.68 1,050.90 4,618.40 881.05

Increase.................................................................. — — 41.32 41.32 37.72

Balance as at December 31, 2010........................ 184.82 3,382.68 1,092.22 4,659.72 918.77

Accumulated amortizationBalance as at January 1, 2009.............................. — — (566.78) (566.78) (485.94)

Amortization for the year ..................................... — — (74.24) (74.24) (64.19)

Balance as at December 31, 2009........................ — — (641.02) (641.02) (550.13)

Amortization for the year ..................................... — — (79.68) (79.68) (67.37)

Balance as at December 31, 2010........................ — — (720.70) (720.70) (617.50)

Net Book Value as at December 31, 2009........... 184.82 3,382.68 409.88 3,977.38 330.92

Net Book Value as at December 31, 2010........... 184.82 3,382.68 371.52 3,939.02 301.27

17. Income Taxes and Deferred Income Taxes

17.1 Income Taxes

Income taxes for the years ended December 31, 20 10 and 2009 are as follows :

Consolidated The Company

2010 2009 2010 2009

Petroleum income tax

Current tax expenses ............................................ 24,205.76 20,150.19 17,578.01 15,151.47

Deferred tax expenses .......................................... (796.82) (312.90) (1,026.55) (478.08)

Total ........................................................... 23,408.94 19,837.29 16,551.46 14,673.39

Income tax under Revenue Code

Current tax expenses ............................................ 424.96 (200.73) 15.33 80.85

Deferred tax expenses .......................................... (602.93) 0.58 (587.90) 11.20

Total ........................................................... (177.97) (200.15) (572.57) 92.05

Income tax in the foreign countries

Current tax expenses ............................................ 3,909.32 3,652.40 — —

Deferred tax expenses .......................................... (1,787.69) 111.19 — —

Total ........................................................... 2,121.63 3,763.59 — —

Petroleum Resource Rent Tax in Australia

Current tax expenses ............................................ — (191.06) — —

Deferred tax expenses .......................................... (1,142.03) (4,950.43) — —

Total ............................................................ (1,142.03) (5,141.49) — —

Total income taxes..................................................... 24,210.57 18,259.24 15,978.89 14,765.44

F-37

Income tax rates for the Group are as follows:

Tax Rate (%)

Petroleum income tax on petroleum businesses in Thailand pursuant to Petroleum Income Tax Act, B.E. 2514and 2532 ........................................................................................................................................................................ 50

Income tax under Revenue Code

Income tax for the Company ........................................................................................................................................ 25 - 30

Income tax for subsidiaries and jointly controlled entities.......................................................................................... 15 - 30

Corporate Income tax in the Union of Myanmar ............................................................................................................. 30

Corporate Income tax in the Republic of Vietnam ........................................................................................................... 50

Corporate income tax in Australia ..................................................................................................................................... 30

Petroleum Resource Rent Tax in Australia........................................................................................................................ 40

Corporate income tax in the Sultanate of Oman............................................................................................................... 55

17.2 Deferred Income Taxes

Deferred income taxes as at December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Deferred income tax assets

Petroleum income tax........................................... 562.83 172.32 — —

Income tax under Revenue Code......................... 632.35 44.20 573.12 —

Corporate income tax in foreign countries.......... 4,541.23 1,640.74 — —

Petroleum Resource Rent Tax in Australia.......... 8,087.88 6,685.92 — —

Total ............................................................ 13,824.29 8,543.18 573.12 —

Deferred income tax liabilities

Petroleum income tax........................................... 13,255.37 13,661.68 10,161.31 11,187.86

Income tax under Revenue Code......................... — 14.78 — 14.78

Corporate income tax in foreign countries.......... 2,524.75 1,316.53 — —

Total ............................................................ 15,780.12 14,992.99 10,161.31 11,202.64

Deferred income tax, net........................................... 1,955.83 6,449.81 9,588.19 11,202.64

Deferred income taxes presented by categories are as follows:

Consolidated The Company

2010 2009 2010 2009

Amortization of decommissioning costs andcurrency translation difference fromdecommissioning costs ........................................ 4,108.77 3,463.81 1,556.81 1,430.71

Provision for employee benefits ............................... 779.36 588.52 717.74 552.39

Provision for impairment losses................................ 236.12 235.85 — —

Depreciation............................................................... (19,668.53) (18,337.64) (12,435.86) (13,170.96)

Petroleum Resource Rent Tax in Australia............... 5,661.52 4,680.14 — —

Loss carried forward.................................................. 7,487.66 5,362.55 583.01 —

Unrealized foreign exchange in Australia ................ 1,076.08 (415.44) — —

Revaluation in value of oil and gas propertiesaccording to Australian law ................................. (1,482.15) (1,375.40) — —

Others......................................................................... (154.66) (652.20) (9.89) (14.78)

Total ........................................................................... (1,955.83) (6,449.81) (9,588.19) (11,202.64)

In addition to the corporate income tax, there is a Petroleum Resource Rent Tax imposed in Australia (PRRT) which is calculated atthe rate of 40% using the specific method. The Group records the current tax and the deferred tax arising from PRRT in the current periodby applying the same accounting policies with respect to valuation and disclosure as for the corporate income tax.

F-38

18. Prepaid Expenses

As at December 31, 2010, the major prepaid expenses totaling of Baht 142.19 million are the prepayments that PTTEPI made to thegovernment of the Union of Myanmar for the royalties of Yadana and Yetagun projects. These prepayments will be amortized when thedeferred income discussed in Note 24 is recognized.

19. Deposit for the purchase of partnership units

Deposit for the purchase of partnership units amounting to Baht 10,312 million were paid to Statoil Canada Ltd. and Statoil CanadaHolding Corp. as a result of entering into a Partnership Unit Sale Agreement (PUSA) to acquire a 40% of the partnership units in the Oil SandKai Kos Dehseh (KKD) field in Canada.

20. Other Non-current Assets

Other non-current assets as at December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Costs carried for PetroVietnam in projects:

- Vietnam B & 48/95 ........................................... 31.84 35.23 — —

- Vietnam 52/97.................................................... 30.42 33.67 — —

Deposits...................................................................... 132.10 29.72 126.89 24.74

Others ........................................................................ 1.87 2.16 0.15 0.12

Total ............................................................ 196.23 100.78 127.04 24.86

21. Short-term Loans and Bonds

Short-term loans and bonds as at December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Current LiabilitiesShort-term loans

- Bills of exchange ............................................... 7,944.73 999.20 7,944.73 999.20

- Other loans ......................................................... — 935.76 — —

Total short-term loans........................................... 7,944.73 1,934.96 7,944.73 999.20

Current portion of bonds...................................... — 9,500.00 — 9,500.00

Less: Deferred issuance expense of bonds.......... — (1.26) — (1.26)

Current portion of bonds, net............................... — 9,498.74 — 9,498.74

Total current liabilities ............................... 7,944.73 11,433.70 7,944.73 10,497.94

Non-current LiabilitiesBonds .................................................................... 70,105.91 49,000.00 49,000.00 49,000.00

Less: Deferred issuance expense of bonds.......... (212.63) (48.80) (34.74) (48.80)

Total non-current liabilities ........................ 69,893.28 48,951.20 48,965.26 48,951.20

Bills of Exchange

The Company launched the “PTTEP Short-term Financing Program” which involved the company’s inaugural issuance of Billsof Exchange (B/Es). The B/Es are to be issued monthly on a revolving basis to institutional and high net-worth investors, with a totalrevolving credit of up to Baht 50,000 million. As at December 31, 2010 the outstanding face value of B/Es was Baht 8,010 million.

Other loans

Other loans are secured loans valued in USD with a floating loan interest rate at LIBOR USD 1 month + 2% per annum.

F-39

Bonds

Unsecured and unsubordinated bonds as at December 31, 2010 and 2009 comprised:

Consolidated The Company

Interest rates(% per annum)

Maturitydates 2010 2009 2010 2009

Maturity date within 1 year

- Bonds Baht 3,500 million............. 4.88 February 12,2010 — 3,500.00 — 3,500.00

- Bonds Baht 6,000 million 1.......... 6MFDR + 0.99 June 15,2010 — 6,000.00 — 6,000.00

Maturity date between 1-3 years

- Bonds Baht 3,500 million ........... 3.91 June 15,2012 3,500.00 3,500.00 3,500.00 3,500.00

- Bonds Baht 18,300 million ......... 3.25 May 29,2012 18,300.00 18,300.00 18,300.00 18,300.00

- Bonds Baht 5,000 million ........... Year 1-2 : 3.00 May 29,2013 5,000.00 5,000.00 5,000.00 5,000.00

Year 3-4 : 4.00 or

6-M THB FIX +1.25 2

Maturity date between 3-5 years

- Bonds Baht 11,700 million........... 4.00 May 29,2014 11,700.00 11,700.00 11,700.00 11,700.00

- Bonds USD 500 million 3 ............ 4.152 July 19,2015 15,075.65 — — —

- Bonds USD 200 million ............... 4.152 August 4,2015 6,030.26 — — —

Maturity date over 5 years .............

- Bonds Baht 2,500 million 4.......... 3.30 March 27,2018 2,500.00 2,500.00 2,500.00 2,500.00

- Bonds Baht 3,000 million NC5 5. 5.13 June 15,2022 3,000.00 3,000.00 3,000.00 3,000.00

- Bonds Baht 5,000 million ........... 4.80 May 29,2019 5,000.00 5,000.00 5,000.00 5,000.00

Total par value of bonds ................. 70,105.91 58,500.00 49,000.00 58,500.00

Less: Deferred issuance expense ofbonds ........................................... (212.63) (50.06) (34.74) (50.06)

Total carrying value......................... 69,893.28 58,449.94 48,965.26 58,449.94

1 On September 4, 2007, the Company entered into an Interest Rate Swap Contract (IRS) for bonds amounting to Baht6,000 million with a financial institution to change the interest rate from a fixed rate at 3.60% per annum to a floatingrate at 6-month Fixed Deposit Rate plus 0.99% (6MFDR + 0.99%).

2 Minimum and maximum repayments are 3.25% and 6.00% per annum, respectively.

3 The Company has Optional Redemption rights. The redemption price is the sum of the bond par value, accrued interest,interest payable up to the day before the maturity date and Applicable Premium whereby the Applicable Premium is thehigher of the following:

(1) 1% per annum of the bond par value or

(2) Present value that is higher than the bond par value. Present value is the bond par value and the interestreceivable if the bond is redeemed on the maturity date minus accrued interest and interest payable to the dateof early redemption discounted using Treasury Rate as at the early redemption date plus 0.35% per annum.

4 On September 27, 2005, the Company entered into a Cross Currency Swap transaction with a bank to swap Baht forUSD 60.82 million. Under this agreement, interest was charged at the rate of 3.85% per annum. On May 2, 2007, theCompany swapped the USD with the same bank for Baht 2,500 million. Under this agreement, the interest rate wasreduced to 3.30% per annum until the expiry date.

5 NC5 (Non Call 5 years): the Company can redeem these bonds in the 5th year or in 2012.

F-40

22. Short-term Provision

Short-term provision as at December 31, 2010 and 2009 comprised:

Consolidated

2010 2009

Provision for decommissioning cost that will be due within 1 year ........................... 3,753.37 661.20

Provision for Montara incident ...................................................................................... 179.83 212.22

Total .................................................................................................................. 3,933.20 873.42

23. Finance Lease Liabilities

As at December 31, 2009, the finance lease liabilities are the liabilities relating to the use of the Floating Production Storage andOffloading (FPSO) vessel of the PTTEP Australasia project. The Group recorded the capital expenditure at the lower of the fair value of theleased property or the present value of the minimum lease payments and recorded the liabilities at the lease obligation value, net of financecharges. The Group recognized the assets from finance leases as “Oil and Gas Properties” under the caption “Property, Plant and Equipment”in the balance sheets.

During 2010, the Group agreed to purchase the leased asset (the FPSO vessel) amounting to Baht 13,535 million to reduce thesignificant burden of the interest expenses in future periods, so the finance lease agreement was terminated. The purchase price of the FPSOvessel was higher than its carrying value at the agreed purchase date. The difference of Baht 1,485 million was recognized as other expensesin relation to this contract. The purchase price of FPSO vessel was fully settled in October 2010.

24. Deferred Income

Deferred income comes from MGTC and TPC receiving advance payments for pipeline transportation from MOGE and PTTEPIreceiving advance payments from PTT for natural gas that PTT did not receive in 2000 - 2001 in accordance with the volumes stipulated inthe gas sales contract of the Yadana and Yetagun projects. The deferred income will be recognized by PTTEPI, MGTC and TPC when PTTreceives gas in future years. Deferred income as at December 31, 2010 and 2009 comprised:

Consolidated

2010 2009

Deferred income for the year 2000 ............................................................................... 1,866.47 2,343.58

Deferred income for the year 2001 ............................................................................... 73.21 265.16

Total .................................................................................................................. 1,939.68 2,608.74

25. Provision for Employee Benefits

The reconciliation details for the present value of the defined benefit obligation plans and liabilities recognized in the balance sheetsas at December 31, 2010 are as follows:

Consolidated The Company

Present value of the defined benefit obligation plans as at January 1, 2009 ............... 1,512.49 1,445.70

Current service cost......................................................................................................... 129.92 114.65

Interest cost...................................................................................................................... 84.12 80.47

Present value of the defined benefit obligation plans as at December 31, 2009 ......... 1,726.53 1,640.82

Current service cost......................................................................................................... 186.48 135.46

Interest cost...................................................................................................................... 78.18 70.81

Actuarial (gain) loss ........................................................................................................ (9.88) (90.49)

Benefit paid...................................................................................................................... (12.39) (11.15)

Present value of the defined benefit obligation plans as at December 31, 2010 ......... 1,968.92 1,745.45

Unrecognized transitional liabilities................................................................................ (374.57) (357.36)

Unrealized actuarial gain (loss) ...................................................................................... (34.23) 47.39

Net liabilities recognized in the balance sheets ............................................................. 1,560.12 1,435.48

F-41

Expenses recognized in the statements of income for the years ended December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Current service cost................................................... 186.48 129.92 135.46 114.65

Interest cost................................................................ 78.18 84.12 70.81 80.47

Transitional liabilities recognized during the year ... 187.28 187.28 178.68 178.69

Actuarial (gain) loss recognized during the year ..... (44.11) — (43.10) —

Expenses recognized in the statements of income... 407.83 401.32 341.85 373.81

Major Actuarial Assumptions

The Group’s financial assumptions

% per annum

Discount rate................................................................................................................................................................. 4.6

Inflation rate ................................................................................................................................................................. 2.0

Credit interest rate on provident funds........................................................................................................................ 4.1

The Group’s demographic assumptions

• Mortality assumption: The mortality rate is from Thailand Mortality Ordinary 1997 (TMO97) issued by the Office of theInsurance Commission. The TMO97 contains the results of the most recent mortality investigation of policyholders in lifeinsurance companies in Thailand. It is reasonable to assume that these rates would be reflective of the mortality experience ofthe working population in Thailand.

• Turnover rate assumption:

Age-related scale % per annum

Prior to age 30.................................................................................................................................................. 2.5-16.0

Age 30-39 ......................................................................................................................................................... 1.5- 8.0

Age 40 thereafter.............................................................................................................................................. 0.0- 4.0

The turnover rate above reflects the rate at which employees voluntarily resign from service. It does not include death, disability,and early retirement. The calculation for the employee benefits is based on such assumptions.

26. Provision for Decommissioning Costs

Provision for decommissioning costs remaining as at December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Provision for decommissioning costs ....................... 25,721.00 23,482.30 10,781.67 10,426.55

Less Current portion ................................................ (3,753.37) (661.20) — —

Non-current portion of provision fordecommissioning costs ......................................... 21,967.63 22,821.10 10,781.67 10,426.55

The current portion of the Group’s provision for decommissioning costs amounting to Baht 3,753.37 million is for the Jabiru and theChallis field of the PTTEP Australasia project which ceased the production in 2010.

Movements of provisions for decommissioning costs during the year 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Balance at the beginning of the year........................ 23,482.30 16,309.66 10,426.55 10,142.13

Currency translation differences ............................... (2,211.09) 109.55 (1,003.03) (452.75)

Additional provision ................................................. 5,757.68 7,063.09 1,358.15 737.17

Estimated liability incurred during the period.......... (1,307.89) — — —

Balance at the end of the year .................................. 25,721.00 23,482.30 10,781.67 10,426.55

F-42

27. Share Capital

The Company’s registered capital consists of 3,322 million ordinary shares at Baht 1 per share, or a total of Baht 3,322 million. OnNovember 8, 2010, the Company registered the change in its issued and fully paid-up capital to 3,317.45 million ordinary shares at Baht 1per share, or a total of Baht 3,317.45 million. The details of the change in the issued and fully paid-up ordinary shares are as follows:

Unit: Million Shares

Ordinary shares issued and fully paid-upBalance as at January 1, 2009 ..................................................................................................................................... 3,307.08

Share capital issued and paid-up ................................................................................................................................ 5.48

Balance as at December 31, 2009 ............................................................................................................................... 3,312.56

Share capital issued and paid-up ................................................................................................................................. 4.89

Balance as at December 31, 2010 ............................................................................................................................... 3,317.45

The Company has reserved 62 million ordinary shares for employees to purchase in accordance with warrants in the Employee StockOwnership Plan or ESOP for 5 continuous years. As at December 31, 2010, the employees had exercised the warrants to purchase 57.45 millionshares and there were 4.55 million reserved shares outstanding. The details are as follows:

Date of warrants issuedExercised price(Baht per share)

Exercised rightwarrant per

ordinary share

The number ofallotted shares(million shares)

The number ofreserved shares(million shares)

August 1, 2002* ........................................................ 22.2 1:5 9.78 0.22

August 1, 2003* ........................................................ 23.4 1:5 9.72 0.28

August 1, 2004* ........................................................ 36.6 1:5 13.61 0.39

August 1, 2005* ........................................................ 55.6 1:5 13.53 0.47

August 1, 2006 ......................................................... 91.2 1:5 10.81 3.19

Total ....................................................... 57.45 4.55

* As at December 31, 2010, the warrants issued on August 1, 2002, 2003, 2004 and 2005 had expired. The remaining warrantswhich cannot be exercised are 0.04, 0.06, 0.08 and 0.09 million shares, respectively.

28. Gain (Loss) on Foreign Currency Translation

Gain (loss) on foreign currency translation for the years ended December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Realized gain (loss) on foreign currencytranslation.............................................................. (1,534.71) (1,161.36) (2,488.13) (636.99)

Unrealized gain (loss) on foreign currencytranslation.............................................................. 4,297.79 653.14 1,018.11 458.36

Total ............................................................ 2,763.08 (508.22) (1,470.02) (178.63)

29. Other Revenues

The Group’s other revenues for the year ended December 31, 2010 mainly comprise the compensation received from the insurer inrelation to the Montara incident in Australia and revenues from disposal of assets amounting to Baht 1,369 million and Baht 534 million,respectively.

30. Petroleum Royalties and Remuneration

Petroleum royalties and remuneration for the years ended December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Petroleum royalties .................................................... 16,292.47 13,644.32 10,600.36 8,949.90

Special remuneration benefits ................................... 480.86 421.25 — —

Total ............................................................ 16,773.33 14,065.57 10,600.36 8,949.90

F-43

31. Montara Incident in Australia

The Montara incident refers to the uncontrolled leakage of oil and gas in the Montara field in the Timor Sea from the PTTEP Australasiaproject. During 2009, the Australian government set up the Montara Commission of Inquiry to investigate into the incident. On November 24,2010, the Australian Minister of Resources and Energy released the Montara Commission of Inquiry’s final report and findings, which remarkson PTTEP Australasia’s operations.

In response, the Group has been in continuous consultation with the Australian government and the related sector, and submitted theAction Plan of PTTEP Australasia Pty Ltd (PTTEP AA), a wholly owned subsidiary of PTTEP, to the Australian Government, which supportsthe recommendations in the Montara Commission of Inquiry’s final report and was designed to ensure that such an incident will not berepeated. The Commissioner commented in his report that the Action Plan is “comprehensive and impressive”. PTTEP AA has continuedworking with the Australian Government in execution of the Action Plan that has been implemented since the middle of 2010. Subsequentlyon February 4, 2011, the Australian Government revealed the Independent Review Report of the Action Plan and decided to allow PTTEP AAto continue its operation in Australia. PTTEP AA will enter into a binding Deed of Agreement with the Australian Government under whichindependent experts will monitor PTTEP AA’s implementation of the Action Plan for 18 months.

In terms of the damages arising from this event, the Group estimated the total expenditure which will be required to control the situationand recognized the whole amount of Baht 9,086 million, net of the recovery from the insurer of Baht 1,341 million, in 2009. In 2010, the Grouprecognized an additional expenditure of Baht 457 million, mainly comprising environmental expenses. In terms of indemnity, the Group hasinsurance in the financial amount of USD 270 million, equivalent to Baht 9,000 million (Baht 1,341 million of which was recognized in thefourth quarter of 2009 and Baht 1,369 million in the third quarter of 2010). However, the reimbursable amount will depend on the actualexpenses incurred and the conditions under the insurance policy. At present, the Group is in the process of claiming the outstanding insurancerecovery from the insurer.

32. Management’s Remuneration

Management’s remuneration for the years ended December 31, 2010 and 2009 comprised:

Consolidated The Company

2010 2009 2010 2009

Director’s remuneration............................................. 54.96 38.38 54.96 38.38

Senior management’s remuneration *....................... 130.56 117.70 130.56 117.70

Total ............................................................ 185.52 156.08 185.52 156.08

* Exclusive of the remuneration for senior management seconded to PTT.

The Company provided the warrants to purchase ordinary shares (as set out in Note 27) for senior management. As at December 31,2010, the remaining warrants were 0.01 million shares.

33. Expenses by Nature

Significant expenses by nature of the Group which comprise the expenses based on its percentage of interestin each project for the year ended December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Salary, wages and employees’ benefits..................... 2,872.31 3,017.61 1,278.35 888.18

Repair and maintenance ............................................ 1,973.08 1,566.62 1,248.80 900.79

Exploration well write-off ......................................... 1,471.92 5,671.14 0.52 11.54

Geological and geophysical ...................................... 984.83 1,706.13 38.37 180.08

34. Earnings per Share

Basic earnings per share for the years ended December 31, 2010 and 2009 are calculated as follows:

Consolidated The Company

2010 2009 2010 2009

Net income attributable to shareholders(Million Baht) ....................................................... 41,738.97 22,153.60 29,487.00 25,052.10

Weighted average number of outside ordinaryshares in issue during the year (Million Shares) 3,314.91 3,309.08 3,314.91 3,309.08

Basic earnings per share (Baht) ................................ 12.59 6.69 8.90 7.57

F-44

Diluted earnings per share is calculated based on the weighted average number of outside ordinary shares in issue during the yearadjusted with dilutive potential ordinary shares assuming that all dilutive potential ordinary shares are converted into ordinary shares. TheCompany has dilutive potential ordinary shares as a result from the warrants provided to employees in which the number of dilutive potentialordinary shares is calculated based on face value of the warrants (calculated from the weighted average price of the ordinary outstanding sharesduring the year). This calculation serves to determine the unpurchased shares to be added to the outside ordinary shares to compute the dilution;no adjustment is made to the net income.

Diluted earnings per share for the years ended December 31, 2010 and 2009 are calculated as follows:

Consolidated The Company

2010 2009 2010 2009

Net income attributable to shareholders(Million Baht) ....................................................... 41,738.97 22,153.60 29,487.00 25,052.10

Net income used to determine diluted earnings pershare (Million Baht) ............................................. 41,738.97 22,153.60 29,487.00 25,052.10

Weighted average number of outside ordinaryshares in issue during the year (Million Shares) 3,314.91 3,309.08 3,314.91 3,309.08

Adjustments for share options (Million Shares) ...... 1.27 2.63 1.27 2.63

Weighted average number of outside ordinaryshares for diluted earnings per share (MillionShares)................................................................... 3,316.18 3,311.71 3,316.18 3,311.71

Diluted earnings per share (Baht) ............................. 12.59 6.69 8.89 7.56

F-45

5.Se

gmen

tIn

form

atio

n

Pri

mar

yre

port

ing

-bu

sine

ssse

gmen

ts

Con

solid

ated

fina

ncia

lst

atem

ents

for

the

year

ende

dD

ecem

ber

31,

2010

Exp

lora

tion

and

prod

ucti

onP

ipel

ine

Oth

ers

Inte

r-co

mpa

nyE

limin

atio

nG

roup

’sto

tal

busi

ness

Tha

iland

Oth

erSo

uth

Eas

tA

sia

Aus

tral

iaM

iddl

eE

ast

and

Oth

ers

Sout

hE

ast

Asi

a

Rev

enue

s-

Thi

rdpa

rtie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

8,77

9.79

3,39

0.50

1,92

2.80

537.

863,

504.

18—

—18

,135

.13

-R

elat

edpa

rtie

s...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

112,

686.

959,

507.

73—

1,64

8.31

3,52

2.55

—(3

,522

.55)

123,

842.

99

Oth

erre

venu

es-

Thi

rdpa

rtie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..36

1.21

56.5

21,

373.

29—

3.28

1,24

8.93

(1,0

75.3

6)1,

967.

87

Tota

lR

even

ues

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

121,

827.

9512

,954

.75

3,29

6.09

2,18

6.17

7,03

0.01

1,24

8.93

(4,5

97.9

1)14

3,94

5.99

Ope

ratin

gex

pens

es...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...11

,197

.75

4,34

9.58

1,91

1.84

504.

6917

8.46

112.

19(3

,666

.17)

14,5

88.3

4

Adm

inis

trat

ive

expe

nses

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..2,

085.

8536

8.62

292.

6055

5.40

47.8

014

7.27

(160

.03)

3,33

7.51

Exp

lora

tion

expe

nses

-A

mor

tizat

ion

ofdr

yho

lean

dpr

ojec

t....

......

......

......

......

......

......

......

......

......

......

......

..75

.84

1,09

2.89

(5.9

6)30

9.14

——

—1,

471.

91

-G

eolo

gica

lan

dge

ophy

sica

l....

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

622.

9834

5.96

120.

8517

7.86

—12

.12

—1,

279.

77

Dep

reci

atio

n,de

plet

ion

and

amor

tizat

ion

......

......

......

......

......

......

......

......

......

......

......

......

.30

,399

.64

1,92

4.09

2,67

0.45

1,29

3.20

243.

4047

.31

—36

,578

.09

Roy

altie

san

dre

mun

erat

ion.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

15,2

23.8

11,

549.

51—

——

——

16,7

73.3

2

Los

sfr

omth

eM

onta

rain

cide

nt...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.—

—45

6.65

——

——

456.

65

Oth

erex

pens

es...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

——

1,48

4.83

——

——

1,48

4.83

Fore

ign

exch

ange

(gai

n)lo

ss...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

(2,0

75.8

2)(1

14.4

5)(3

,230

.52)

(7.9

7)—

5.31

—(5

,423

.45)

Shar

eof

loss

from

asso

ciat

es...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

——

3.10

——

41.7

3—

44.8

3

Tota

lE

xpen

ses.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

57,5

30.0

59,

516.

203,

703.

842,

832.

3246

9.66

365.

93(3

,826

.20)

70,5

91.8

0

Segm

ent

resu

lt...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

64,2

97.9

03,

438.

55(4

07.7

5)(6

46.1

5)6,

560.

3588

3.00

(771

.71)

73,3

54.1

9

Dep

reci

atio

n-

gene

ral

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(247

.31)

Adm

inis

trat

ive

expe

nses

-ge

nera

l....

......

......

......

......

......

......

......

......

......

......

......

......

......

..(2

,634

.12)

Ope

ratin

gpr

ofit

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

70,4

72.7

6

Oth

erin

com

e,ne

t....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..48

9.72

Fina

nce

cost

s-

Inte

rest

inco

me.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

373.

50

-In

tere

stex

pens

esan

dot

her

fina

nce

cost

s....

......

......

......

......

......

......

...(2

,540

.54)

Los

son

fore

ign

exch

ange

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(2,6

60.3

8)

Man

agem

ent’s

rem

uner

atio

n...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(185

.52)

Inco

me

befo

reta

x...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

65,9

49.5

4

Tax

-Pr

ojec

t...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

(24,

878.

47)

(2,2

50.8

9)4,

261.

66(1

,697

.02)

(1,9

05.5

2)(5

2.15

)(2

6,52

2.39

)

-G

roup

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

2,31

1.82

Net

Inco

me

(Los

s)...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...39

,419

.43

1,18

7.66

3,85

3.91

(2,3

43.1

7)4,

654.

8383

0.85

41,7

38.9

7

F-46

Con

solid

ated

fina

ncia

lst

atem

ents

for

the

year

ende

dD

ecem

ber

31,

2010

Exp

lora

tion

and

prod

ucti

onP

ipel

ine

Oth

ers

Inte

r-co

mpa

nyE

limin

atio

nG

roup

’sto

tal

busi

ness

Tha

iland

Oth

erSo

uth

Eas

tA

sia

Aus

tral

iaM

iddl

eE

ast

and

Oth

ers

Sout

hE

ast

Asi

a

Ass

ets

Segm

ent

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

174,

290.

9533

,006

.51

56,2

15.6

79,

181.

154,

144.

982,

288.

9127

9,12

8.17

Inve

stm

ents

unde

req

uity

met

hod

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.—

—75

.42

——

8,79

5.59

8,87

1.01

Una

lloca

ted

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

54,2

20.3

8

Con

solid

ated

tota

las

sets

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.34

2,21

9.56

Lia

bilit

ies

Segm

ent

liabi

litie

s...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

71,8

36.2

65,

313.

2310

,489

.69

3,49

9.74

1,41

5.06

281.

9392

,835

.91

Una

lloca

ted

liabi

litie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

77,0

89.6

4

Con

solid

ated

tota

llia

bilit

ies.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

169,

925.

55

Cap

ital

Exp

endi

ture

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...39

,156

.19

7,22

6.59

8,64

8.76

290.

87(6

09.0

0)1,

233.

4055

,946

.81

F-47

Con

solid

ated

fina

ncia

lst

atem

ents

for

the

year

ende

dD

ecem

ber

31,

2009

Exp

lora

tion

and

prod

ucti

onP

ipel

ine

Oth

ers

Inte

r-co

mpa

nyE

limin

atio

nG

roup

’sto

tal

busi

ness

Tha

iland

Oth

erSo

uth

Eas

tA

sia

Aus

tral

iaM

iddl

eE

ast

and

Oth

ers

Sout

hE

ast

Asi

a

Rev

enue

s-

Thi

rdpa

rtie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

9,14

0.18

3,63

4.88

2,04

8.22

576.

973,

762.

60—

—19

,162

.85

-R

elat

edpa

rtie

s...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

88,6

19.6

19,

755.

72—

1,77

1.95

3,66

2.42

—(3

,662

.42)

100,

147.

28

Oth

erre

venu

es-

Thi

rdpa

rtie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..17

8.06

—30

3.92

0.28

3.56

341.

76(1

89.4

6)63

8.12

Tota

lR

even

ues

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

97,9

37.8

513

,390

.60

2,35

2.14

2,34

9.20

7,42

8.58

341.

76(3

,851

.88)

119,

948.

25

Ope

ratin

gex

pens

es...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...8,

527.

824,

375.

892,

042.

2052

8.79

176.

9012

.93

(3,7

38.2

7)11

,926

.26

Adm

inis

trat

ive

expe

nses

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..2,

048.

5573

9.00

267.

5947

1.33

46.6

489

.21

(35.

11)

3,62

7.21

Exp

lora

tion

expe

nses

-A

mor

tizat

ion

ofdr

yho

lean

dpr

ojec

t....

......

......

......

......

......

......

......

......

......

......

......

..58

.18

83.1

32,

163.

853,

365.

98—

——

5,67

1.14

-G

eolo

gica

lan

dge

ophy

sica

l....

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

404.

5042

5.13

152.

0072

4.50

——

—1,

706.

13

Dep

reci

atio

n,de

plet

ion

and

amor

tizat

ion

......

......

......

......

......

......

......

......

......

......

......

......

.25

,770

.34

1,83

5.57

615.

791,

070.

9124

2.59

40.7

1—

29,5

75.9

1

Roy

altie

san

dre

mun

erat

ion.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

12,5

41.9

61,

523.

62—

——

——

14,0

65.5

8

Los

sfr

omth

eM

onta

rain

cide

nt...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.—

—5,

760.

83—

——

—5,

760.

83

Los

sfr

omda

mag

ew

ellh

ead

plat

form

......

......

......

......

......

......

......

......

......

......

......

......

......

——

3,32

5.04

——

——

3,32

5.04

Fore

ign

exch

ange

(gai

n)lo

ss...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

(1,0

29.6

9)(6

0.67

)96

5.85

(0.4

5)—

0.40

—(1

24.5

6)

Shar

eof

(gai

n)lo

ssfr

omas

soci

ates

......

......

......

......

......

......

......

......

......

......

......

......

......

...—

—(2

2.69

)—

—40

.55

—17

.86

Tota

lE

xpen

ses.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

48,3

21.6

68,

921.

6715

,270

.46

6,16

1.06

466.

1318

3.80

(3,7

73.3

8)75

,551

.40

Segm

ent

resu

lt...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

49,6

16.1

94,

468.

93(1

2,91

8.32

)(3

,811

.86)

6,96

2.45

157.

96(7

8.50

)44

,396

.85

Dep

reci

atio

n-

gene

ral

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(280

.09)

Adm

inis

trat

ive

expe

nses

-ge

nera

l....

......

......

......

......

......

......

......

......

......

......

......

......

......

..(1

,434

.71)

Ope

ratin

gpr

ofit

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

42,6

82.0

5

Oth

erin

com

e,ne

t....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

..13

.72

Fina

nce

cost

s-

Inte

rest

inco

me.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...37

6.27

-In

tere

stex

pens

esan

dot

her

fina

nce

cost

s....

......

......

......

......

......

......

......

(1,8

70.3

3)

Los

son

fore

ign

exch

ange

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(632

.79)

Man

agem

ent’s

rem

uner

atio

n...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

(156

.08)

Inco

me

befo

reta

x...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

40,4

12.8

4

Tax

-Pr

ojec

t.....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

(20,

941.

36)

(1,3

05.5

1)4,

957.

40(5

6.28

)(2

,072

.96)

(30.

81)

(19,

449.

52)

-G

roup

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

1,19

0.28

Net

Inco

me

(Los

s)...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

28,6

74.8

33,

163.

42(7

,960

.92)

(3,8

68.1

4)4,

889.

4912

7.15

22,1

53.6

0

F-48

Con

solid

ated

fina

ncia

lst

atem

ents

for

the

year

ende

dD

ecem

ber

31,

2009

Exp

lora

tion

and

prod

ucti

onP

ipel

ine

Oth

ers

Inte

r-co

mpa

nyE

limin

atio

nG

roup

’sto

tal

busi

ness

Tha

iland

Oth

erSo

uth

Eas

tA

sia

Aus

tral

iaM

iddl

eE

ast

and

Oth

ers

Sout

hE

ast

Asi

a

Ass

ets

Segm

ent

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

160,

578.

6128

,491

.46

48,1

83.9

29,

833.

724,

668.

862,

351.

24—

254,

107.

81

Inve

stm

ents

unde

req

uity

met

hod

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.—

—78

.52

——

843.

79—

922.

31

Una

lloca

ted

asse

ts...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.....

45,6

80.4

9

Con

solid

ated

tota

las

sets

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

.30

0,71

0.61

Lia

bilit

ies

Segm

ent

liabi

litie

s...

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

65,8

15.0

44,

587.

2024

,344

.90

2,36

2.62

1,65

1.97

524.

18—

99,2

85.9

1

Una

lloca

ted

liabi

litie

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

....

58,4

23.9

3

Con

solid

ated

tota

llia

bilit

ies.

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

157,

709.

84

Cap

ital

Exp

endi

ture

s....

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

......

...36

,300

.39

3,06

6.92

37,8

13.4

73,

526.

49(3

05.9

5)55

1.55

80,9

52.8

7

F-49

The Group is organized into the following business segments:

• Exploration and production: The Group operates in oil and gas exploration and production both domestically and overseas,either as an operator or as a joint venture partner with international oil and gas companies. Most domestic projects are locatedin the Gulf of Thailand. Overseas projects are located in Southeast Asia, the Middle East, North Africa, and Australia. As at thebalance sheet date, the Group had 19 projects in the production phase and 24 projects in the development and explorationphases.

• Overseas pipelines: The Group has investments with its joint venture partners to operate pipelines to transport natural gas fromthe exploration and production projects where the Group has working interests i.e., the Yadana and Yetagun projects.

• Others: The Group’s other operations consist mainly of investments in projects strategically connected to the energy business,which does not constitute a separately reportable segment.

Secondary reporting — geographical segments

The Group’s two main business segments are managed on a worldwide basis. They are operated in four main geographical areas:

Consolidated financial statements for the year ended December 31, 2010

Thailand

OtherSoutheast

Asia AustraliaMiddle Eastand others Group

Revenues - Third parties ........................... 8,779.79 6,894.68 1,922.80 537.86 18,135.13

- Related parties........................ 112,686.95 9,507.73 — 1,648.31 123,842.99

Segment assets............................................ 176,579.86 37,151.49 56,215.67 9,181.15 279,128.17

Investments under equity method .............. 8,795.59 — 75.42 — 8,871.01

Capital expenditures .................................. 40,389.59 6,617.59 8,648.76 290.87 55,946.81

Consolidated total assets ............................ 239,595.83 37,151.49 56,291.09 9,181.15 342,219.56

Consolidated financial statements for the year ended December 31, 2009

Thailand

OtherSoutheast

Asia AustraliaMiddle Eastand others Group

Revenues - Third parties ........................... 9,140.18 7,397.48 2,048.22 576.97 19,162.85

- Related parties........................ 88,619.61 9,755.72 — 1,771.95 100,147.28

Segment assets............................................ 162,929.85 33,160.32 48,183.92 9,833.72 254,107.81

Investments under equity method .............. 843.79 — 78.52 — 922.31

Capital expenditures ................................... 36,851.94 2,760.97 37,813.47 3,526.49 80,952.87

Consolidated total assets ............................ 209,454.13 33,160.32 48,262.44 9,833.72 300,710.61

36. Disclosure of Financial Instruments

Risk Management

The Group’s business and operations cause it to be exposed to the following key risks:

Market Risk

Market risk is the situation whereby changes in commodities prices, interest rates, and foreign exchange rates may positivelyor adversely impact the Group’s revenues, cash flows, assets, and liabilities.

Financial derivatives of various kinds are employed for the purpose of managing risk exposure to movements in prices ofcommodities, interest rates and foreign exchange rates.

• Price Risk

In 2010, the world oil price fluctuated and the Brent crude oil price was in the range of USD 67 — 95 per barrel. The Group’sproduct prices vary with those of world oil prices, which are subject to factors beyond its control, for instance, market demand andsupply, political and economic stability of various countries, OPEC’s production policy, oil reserves and the change in the globalclimate each season. Fluctuations in world oil prices affect the Group’s revenue and investment planning.

In this regard, when the world oil prices change, so do the prices of the Group’s crude oil and condensate. However, becauseof built-in natural gas pricing mechanisms found in the Gas Sale Agreement (GSA) which cushion natural gas prices from oil pricevolatility (Natural Hedge), when the reference oil prices change, the typical prices of natural gas — the Group’s main product — dochange in the same direction. Most of the Group’s contractual natural gas prices are adjusted every 6 or 12 months depending on thegas price formula of each project and should this price rise or fall, the natural gas price will move correspondingly to a certain degreecompared to the prices of crude oil and condensate.

F-50

The Group has realized the impact of prices on its revenue and profi ts. Therefore, the risk mitigation plan is routinely reviewedby the Risk Management Committee and endorsed by the Board for further action.

• Interest Rate Risk

The majority of the Group’s debts are subject to fixed interest rates, resulting in stable cash outflows. However, fixed interestrates would result in a higher interest expense if the market interest rates decrease. In order to manage the risk from falling interestrates, the Company has a policy to maintain a proper proportion between fixed-interest rate debts and floating-interest rate debts. TheCompany considers floating-interest rate borrowings as well as using the financial instruments, such as interest rate swap to swap fromfixed interest rate to floating rate in order to prevent interest rate risks. The Group considers costs, market conditions, and acceptablerisks in using the financial instrument to prevent the risk.

Furthermore, the Group’s short-term commercial papers (Bills of Exchange), featuring tenors of approximately from one to sixmonths, are subject to pricing based upon the latest comparable yield on Thai government treasuries.

• Foreign Currency Risk

Although the vast majority of the Group’s domestic and international business (revenues and expenses) are tied to the USD,the Group’s presentation currency remains in Thai Baht. Therefore, foreign exchange risk arises when transactions are denominated ina currency other than the presentation currency. Foreign exchange gains and losses are presented in Note 28.

The Group is aware of the risks surrounding financial assets and liabilities denominated in foreign currencies, as a result, theGroup has a policy of asset and liability management by which the structure and features of transactions regarding assets, liabilitiesand shareholders’ equity are aligned with each other.

Credit Risk

The Group seeks to ensure that sales of products are made to the customers with acceptable credit profiles, with theoverwhelming majority of sales being made to PTT Public Company Limited, PTTEP’s parent company. The credit risks are carefullyassessed and regularly reviewed.

Liquidity Risk

Liquidity risk is the risk that arises from the unavailability of viable sources of funding for the Group’s business activities.Future liabilities and interest expenses as at December 31, 2010 are as follows:

Maturity Date

2011

2012 20132014

onwards TotalRevolving3

Months6

Months12

Months

Baht bond at fixed interest rate

Principal ........................................ — — — — 21,800 5,000 22,200 49,000

Interest expenses........................... — 307 607 938 1,510 1,044 3,233 7,639

USD bond at fixed interest rate * ...

Principal ........................................ — — — — — — 21,106 21,106

Interest expenses........................... — 438 — 438 1,252 1,252 2,504 5,884

Baht bill of exchange ........................

Principal ........................................ 8,010 — — — — — — 8,010

Total principal and interestexpenses ........................................ 8,010 745 607 1,376 24,562 7,296 49,043 91,639

* Baht equivalent at the average rate of Baht 30.1513 per USD as of December 30, 2010, as announced by the Bank ofThailand.

The major assumptions for the data presented in the table above are that all the interest expenses are calculated based on thecontractual interest rate. The principal will remain unchanged until it is repaid at the maturity date.

The Group manages its liquidity risks by preparing cash flows forecasts and adjusting financial estimates regularly. The Groupoperates a Short-Term Financing Program in order to access Thailand’s capital market by issuing short-term debts securities, and Baht3,090 million in committed credit facilities with commercial banks. Such facilities are available subject to advanced notification tobanks for a period of at least 3 business days, based upon a pre-agreed interest rate. Of the total, Baht 3,000 million is subject to annualreview, while Baht 90 million is provided on a revolving basis.

F-51

The outstanding principal amounts and undrawn facilities are summarized below:

Credit Limit Undrawn Amounts

Short-term Commercial Papers *........................................................................ 50,000 41,990

Committed Bank Facilities.................................................................................. 3,090 3,090

* Short-term commercial papers mainly comprise Bills of Exchange (B/Es).

The Group’s Receivables Purchase Financing Facility has been launched for the purpose of converting credit terms to immediatecash to ensure flexible working capital.

The Company’s long-term debt ratings as assigned by prominent credit rating agencies for the years 2010 and 2009 are asfollows:

2010 2009

ForeignCurrency

DomesticCurrency

ForeignCurrency

DomesticCurrency

Rating Agency

Moody’s .................................................... A3 A3 A3 A2

Standard and Poor’s ................................ BBB+ BBB+ BBB+ BBB+

Japan Credit Rating ................................. A- A A- A+

TRIS Rating ............................................. — AAA — AAA

Fair Value of Financial Instruments

Since the majority of the financial assets are short-term and the loans carry interest at rates close to current market rates, themanagement believes that the fair value of the Company’s financial assets does not materially differ from its carrying value.

The Group calculated the fair value of long-term liabilities using the discounted cash flow based on a discounted rate ofborrowing with similar terms, while the cross currency interest and principal swaps were based on the quoted market rate. Details ofthe carrying value and fair value of these instruments are as follows:

As at December 31, 2010

Carrying amount Fair value

Baht 2,500 million of unsecured and unsubordinated bonds ........................... 2,500.00 2,570.40

Baht 6,500 million of unsecured and unsubordinated bonds

- Tranche 1, Baht 3,500 million ................................................................... 3,500.00 3,551.03

- Tranche 2, Baht 3,000 million ................................................................... 3,000.00 3,003.46

Baht 40,000 million of unsecured and unsubordinated bonds

- Tranche 1, Baht 18,300 million ................................................................. 18,300.00 18,396.53

- Tranche 2, Baht 5,000 million ................................................................... 5,000.00 5,065.70

- Tranche 3, Baht 11,700 million ................................................................. 11,700.00 11,887.42

- Tranche 4, Baht 5,000 million..................................................................... 5,000.00 5,210.44

USD 500 million of unsecured and unsubordinated bonds .............................. 15,075.65 15,068.67

USD 200 million of unsecured and unsubordinated bonds .............................. 6,030.26 5,977.77

Interest rate swap for Baht 2,500 million bonds................................................ — 220.94

Forward foreign exchange contracts................................................................... — (29.49)

Dividends

On March 31, 2010, the annual general meeting of the shareholders approved payment of a dividend for the year 2009 of Baht2.68 per share. The Company made an interim dividend payment for the first half-year operations of 2009 at the rate of Baht 1.48 pershare on August 28, 2009 and for the second half-year operations of 2009 at the rate of Baht 1.20 per share on April 9, 2010.

The Company estimated the dividend to its shareholders for the year 2010 at Baht 5.03 per share. The Company made an interimdividend payment for the first half-year operations of 2010 at the rate of Baht 2.55 per share on August 30, 2010 and still has to paythe dividend for the second half-year operations of 2010 at the rate of Baht 2.48 per share. This dividend will be paid upon approvalby the annual general meeting of the shareholders.

F-52

37. Commitment and Contingent Liabilities

• Commitment for the operating leases — the Group as a lessee

The future minimum lease payments for the non-cancellable operating leases as at December 31, 2010 and 2009 are as follows:

Consolidated The Company

2010 2009 2010 2009

Within 1 year ............................................................. 3,984.59 4,288.64 3,576.80 3,574.71

Between 1 - 5 years .................................................. 4,106.42 5,050.46 2,876.33 3,616.65

Over 5 years .............................................................. 2,828.67 3,434.34 8.92 10.95

Total ........................................................................... 10,919.68 12,773.44 6,462.05 7,202.31

• Commitment from loan agreements

As at December 31, 2010, the Company had a subordinated loan agreement with the Energy Complex Company Limited (EnCo), withthe loan limit of Baht 1,250 million. The agreement shall continue for 13 years and 6 months effective from April 2, 2009. The total of loansprovided by the Company as at December 31, 2010 was Baht 580 million.

• Obligation under Gas Sales Agreement (GSA)

According to Gas Sales Agreement of MTJDA B-17 Project, if the sellers fail to deliver the quantity of natural gas notified by the buyeron the date agreed upon, the buyer has the right to take the deficient quantity of natural gas (Shortfall) at a price equal to 75% of the currentprice applicable at the time the Shortfall occurred. PTT, the buyer, has nominated quantities of natural gas since late December 2009 butPTTEPI and joint venture partner, the seller, could not deliver the natural gas nominated by PTT. However, MTJDA-B17 Project started upits commercial production on February 5, 2010. PTTEPI and the joint venture partner may have an obligation for the Shortfall that occurredfrom late December 2009 to February 5, 2010 by selling the deficient amount of gas at the 75% discounted price as per GSA with theapproximate total cost for PTTEPI of Baht 108 million. Currently, negotiation between the buyer (PTT) and the sellers are in process.

• Contingent liabilities

• On August 26, 2010, PTTEP Australasia Pty Ltd (PTTEP AA) received a letter claiming compensation relating to the incidentof oil and natural gas leak in Montara area under PTTEP Australasia project from the Government of Indonesia. Subsequentlyon September 1, 2010, PTTEP AA submitted the letter rejecting the claim for the compensation because the evidence providedby the Government of Indonesia is considered unproven and unsubstantiated. No verifiable scientific evidence has yet beenprovided to support the claim.

In December 2010, PTTEP AA and the Government of Indonesia agreed to provide each other additional documents and willconduct a Joint Survey to verify the Government of Indonesia’s data on the claimed damage on the fisheries sector from theMontara oil spill. The discussion with the Government of Indonesia is on-going and more detailed data is expected to bediscussed by PTTEP AA and the Government of Indonesia in February, 2011. The compensation regarding this matter has notbeen finalized.

• As at December 31, 2010, the Company had contingent liabilities in the form of letters of guarantee amounting to Baht 2,252million in the Company’s financial statements and Baht 3,141 million in the consolidated financial statements.

38. Significant Events during the period

• On January 14, 2010, the Group established PTTEP Southwest Vietnam Pipeline Company Limited with registered capital ofUSD 50,000, consisting of 50,000 ordinary shares at USD 1 each, with 100% shareholding by PTTEP Holding CompanyLimited.

• On January 17, 2010, the Company signed the Petroleum Contract in block Hassi Bir Rekaiz in Algeria. The joint venturepartners consist of PTTEP (the operator), CNOOC International Limited (CNOOC) and Sonatrach with the participationinterests of 24.50%, 24.50%, and 51.00% respectively. The contract was announced in the Gazette of Algeria on May 26, 2010.PTTEP AG and CNOOC joined the Algeria 2009 Bid Round with a 50:50 share and were selected as the successful bidder ofthe block Hassi Bir Rekaiz in December 2009.

• On February 26, 2010, PTTEP Bengara I Company Limited (PTTEPB) signed the Withdrawal Agreement to withdrawn theentire 40% participation interest from Indonesia Bengara-1 Project. The withdrawal will be fully effective upon receivingapproval from BPMIGAS, an Indonesian government agency.

• On April 7, 2010, the Group established PTTEP FLNG Holding Company Limited with registered capital of HKD 10,000,consisting of 10,000 ordinary shares at HKD 1 each, with 100% shareholding by PTTEP International Holding CompanyLimited (former name: PTTEP West Africa Company Limited).

F-53

• On April 8, 2010, PTT Public Company Limited (PTT) made a payment to PTT Exploration and Production Public CompanyLimited (PTTEP) for the PTTEP office building at the market value of Baht 481 million. According to the PTTEP Board ofDirectors Meeting held on December 25, 2009, the PTTEP Board of Directors passed the resolution to approve the ownershipof the PTTEP office building, registered at 555 Vibhavadi-Rangsit Road, Chatuchak, Bangkok, to PTT.

• On May 7, 2010, the Group established 6 subsidiaries as follows:

• PTTEP South Mandar Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1each, with 100% shareholding by PTTEP Indonesia Company Limited

• PTTEP Malunda Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1 each,with 100% shareholding by PTTEP Indonesia Company Limited

• PTTEP Sadang Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1 each, with100% shareholding by PTTEP Indonesia Company Limited

• PTTEP South Sageri Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1 each,with 100% shareholding by PTTEP Indonesia Company Limited

• PTTEP Brazil Holding Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1each, with 100% shareholding by PTTEP International Holding Company Limited

• PTTEP Netherland Holding Limited with registered capital of USD 50,000, consisting of 50,000 ordinary shares at USD1 each, with 100% shareholding by PTTEP International Holding Company Limited.

• On May 10, 2010, the Group established PTTEP South America Holding Limited with registered capital of USD 50,000,consisting of 50,000 ordinary shares at USD 1 each, with 100% shareholding by PTTEP International Holding CompanyLimited.

• On May 14, 2010, PTTEP together with Talisman (Asia) Ltd. have been selected as the successful bidders in IndonesiaPetroleum Bidding Round 2009/2010, Indonesia, for 4 Petroleum Exploration and Production Blocks with the participationinterests as follows:

Block

PTTEP’sParticipation

Interest

(%)South Mandar ................................................................................................................................................... 67

Malunda ............................................................................................................................................................ 100

Sadang............................................................................................................................................................... 40

South Sageri...................................................................................................................................................... 30

• On June 3, 2010, the Group established PTTEP Australia International Finance Pty Ltd. with registered capital of AUD 50,000,consisting of 50,000 ordinary shares at AUD 1 each, with 100% shareholding by PTTEP Australia Perth Pty Ltd.

• PTTEP Oman Company Limited has relinquished the entire area of Exploration Block 58 in Sultanate of Oman after fulfillmentof the exploration work commitment. The withdrawal has been approved by the Ministry of Oil and Gas of Sultanate of Oman(MOG).

• On July 19, 2010, PTTEP Australia International Finance Pty Ltd (PTTEP AIF) issued unsecured and unsubordinated bonds toforeign institutional investors for the total amount of USD 500 million carrying a coupon with the fixed rate of 4.152% perannum, fully guaranteed by PTTEP with a tenor of five years. The bonds have been rated BBB+ by Standard and Poor’s andA3 by Moody’s.

• On July 22, 2010, the Thai Government approved PTTEP Siam Limited to transfer all of its 70% participation interests in blockL21/48, L28/48 and L29/48 and 100% participation interests in block A4/48, A5/48 and A6/48 to PTTEP International Limited.

• On August 4, 2010, PTTEP Australia International Finance Pty Ltd (PTTEP AIF) issued unsecured and unsubordinated bondsto institutional investors in Thailand for the total amount of USD 200 million carrying a coupon with the fixed rate of 4.152%per annum, fully guaranteed by PTTEP with a tenor of five years. The bonds have been rated BBB+ by Standard and Poor’sand A3 by Moody’s.

• On August 19, 2010, the Thai Government approved PTTEP Thai Projects Company Limited to transfer all of its 5%, 45% and80% participation interests in block G6/50, G7/50 and G8/50, respectively to PTTEP (Thailand) Limited.

• On September 17, 2010, the Indonesia Government approved PTTEP Semai II Limited (PTTEP SM) to transfer its 5%participation interests in the Indonesia Semai II Projects to PERTAMINA Company according to the policies of the Indonesiagovernment resulting in PTTEP SM having 28.33% participation interests in the Indonesia Semai II Projects.

F-54

• PTTEP FLNG Holding Company Limited (a subsidiary of PTTEP) and PTT International Singapore PTE. LTD (a subsidiaryof PTT Plc.) are joint shareholders of PTT FLNG Limited, which has a registered share capital of HKD 10,000, consisting of1,000 ordinary shares at HKD 10 per share. Each of the two companies holds a 50% participation interest in PTT FLNGLimited.

• On Nobmber 16, 2010, the Thai Government approved to PTTEP (Thailand) Limited to transfer all of its participation interestin 7 blocks, seven in total, to PTTEP International Limited, as follows:

Block

PTTEPI’sParticipation

Interest

(%)G6/50................................................................................................................................................................. 5

G7/50................................................................................................................................................................. 45

G8/50................................................................................................................................................................. 80

L53/43 and L54/43 ........................................................................................................................................... 100

G4/48................................................................................................................................................................. 5

G9/48................................................................................................................................................................. 80

G12/48............................................................................................................................................................... 44.4445

• On November 24, 2010, PTTEP Offshore Investment Company Limited signed loan agreements with four financial institutions,The Bank of Tokyo-Mitsubishi UFJ, Ltd., Mizuho Corporate Bank, Ltd., Oversea-Chinese Banking Corporation Limited andSumitomo Mitsui Banking Corporation. The loans have been fully guaranteed by PTTEP, with USD 500 million total creditfacilities and a five-year tenor.

• On November 29, 2010, PTTEP Thai Projects Company Limited registered its dissolution with the Ministry of Commerce andis in the process of liquidation.

• On December 1, 2010, the Group established two subsidiaries, as follows:

• PTTEP Netherlands Coöperatie U.A. was funded USD 50,000 by PTTEP International Holding Company Limited and PTTEPNetherland Holding Limited with 1% and 99% interests, respectively.

• PTTEP Canada Limited has a registered share capital of CAD 50,000, consisting of 50,000 ordinary shares at CAD 1 each, with100% shareholding by PTTEP Netherlands Coöperatie U.A.

• On December 1, 2010, PTTEP Offshore Investment Company Limited signed a loan agreement with Mizuho Corporate Bank,Ltd. The loan has been fully guaranteed by PTTEP with USD 75 million credit facilities and a five-year tenor.

• On December 9, 2010, the Company signed a loan agreement with Thanachart Bank Plc. with USD 50 million credit facilitiesand a five-year tenor.

• On December 24, 2010, PTTEP (Thailand) Limited registered its dissolution with the Ministry of Commerce and is in theprocess of liquidation.

• On November 22, 2010, PTTEP Netherland Holding Limited entered into the Partnership Unit Sale Agreement to acquire 40%participation interest in the Partnership from Statoil Canada Ltd. and Statoil Canada Holdings Corp., a subsidiary of Statoil ASA(Statoil), for the investment in the Canada Oil Sands Kai Kos Dehseh (KKD) Project in Canada. The consideration price forthe acquisition of the participation interests in the KKD Oil Sands Project was USD 2,280 million. Of the total, Baht 10,312million was paid in advance as the deposit for the purchase of the partnership units (as set out in Note 19). The CanadianGovernment approved this transaction on December 21, 2010. The Partnership Unit Sale Agreement comes into effect onJanuary 21, 2011. The 40% participation interest is retrospectively effective from January 1, 2011.

The Canada Oil Sands KKD Project is a significant oil sands deposit in Canada covering an area of 257,200 acres with an estimated4.3 billion barrels of recoverable Bitumen resources (independently assessed by an external petroleum consultant). The Canada Oil Sands KKDProject is a project utilising Steam Assisted Gravity Drainage (SAGD) technology with an expected project life of over 40 years.

39. Events after the Balance Sheet Date

The Board of Directors of the Company authorized for the issue of these financial statements on February 17, 2011.

F-55

AUDITOR’S REPORT AND FINANCIAL STATEMENTS

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED

AND SUBSIDIARIES

FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

F-56

AUDITOR’S REPORT

TO: THE SHAREHOLDERS OF PTT EXPLORATION AND PRODUCTION PUBLIC COMPANYLIMITED

The Office of the Auditor General of Thailand has audited the accompanying consolidated and the Companybalance sheets as at December 31, 2009 and 2008, the related consolidated and the Company statements ofincome, changes in shareholders’ equity, and cash flows for the years then ended of PTT Exploration &Production Public Company Limited and subsidiaries and of PTT Exploration & Production Public CompanyLimited respectively. The Company’s management is responsible for the correctness and completeness ofinformation presented in these financial statements. The responsibility of the Office of the Auditor General ofThailand is to express an opinion on these financial statements based on the audits and other auditors’ reports.The Office of the Auditor General of Thailand received the other auditors’ reports and used them as a basis inauditing and expressing an opinion on the consolidated and the Company financial statements. Assets, liabilitiesand expenses of the joint venture projects audited by other auditors, included in the consolidated financialstatements for the year 2009 constitute 67.02%, 25.93% and 47.11% and for the year 2008 constitute 56.39%,9.43% and 31.74% respectively, and included in the Company financial statements for the year 2009 constitute33.54%, 3.51% and 37.77% and for the year 2008 constitute 39.85%, 5.54% and 30.37% respectively.

The Office of the Auditor General of Thailand conducted the audits in accordance with generally acceptedauditing standards. Those standards require that the Office of the Auditor General of Thailand plan and performthe audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financialstatements. An audit also includes assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. The Office of the AuditorGeneral of Thailand believes that the audits together with other auditors’ reports as above-mentioned provide areasonable basis for the opinion.

In the opinion of the Office of the Auditor General of Thailand, based on the audits and other auditors’reports, the consolidated and the Company financial statements referred to above present fairly, in all materialrespects, the consolidated and the Company financial position as at December 31, 2009 and 2008, and theconsolidated and the Company’s results of operations and cash flows for the years then ended of the consolidatedPTT Exploration & Production Public Company Limited and subsidiaries and of PTT Exploration & ProductionPublic Company Limited in accordance with generally accepted accounting principles.

(Signed) Poungchomnad Jariyajinda(Poungchomnad Jariyajinda)

Inspector General

(Signed)Janya Pengpreecha(Janya Pengpreecha)

Director of Audit GroupActing Director of Audit Office

February 17, 2010

F-57

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

BALANCE SHEETSAS AT DECEMBER 31, 2009 AND 2008

Unit : Baht

Consolidated The Company

Notes 2009 2008 2009 2008

AssetsCurrent Assets

Cash and cash equivalents . . . . . . 7 48,677,769,437 43,994,689,588 35,027,409,870 26,132,472,261Trade account receivable-parentcompany . . . . . . . . . . . . . . . . . 8 10,918,592,580 9,939,682,052 7,697,295,667 6,701,904,214

Trade accounts receivable . . . . . . 9 3,345,572,004 1,586,942,852 47,856,171 18,836,825Inventories . . . . . . . . . . . . . . . . . . 1,048,974,429 320,367,591 311,969,441 28,622,046Materials and supplies, net . . . . . 10 8,145,572,198 6,414,793,357 3,257,166,354 2,549,691,646Other current assets

Working capital fromco-venturers . . . . . . . . . . . 407,126,209 905,606,084 20,573,756 17,569,650

Other accountsreceivable . . . . . . . . . . . . . 11 3,685,134,238 1,740,176,616 1,012,558,540 1,456,475,444

Accrued interestreceivables . . . . . . . . . . . . 4,950,652 42,291,574 99,766,614 108,721,799

Other current assets . . . . . . . 2,550,165,062 2,007,482,012 1,037,542,199 364,128,102

Total Current Assets . . . . . . . . . . 78,783,856,809 66,952,031,726 48,512,138,612 37,378,421,987

Non-current AssetsInvestments in subsidiaries . . . . . 13.3 — — 23,873,135,929 23,719,401,729Investments in associates . . . . . . . 13.4 922,311,301 384,336,645 930,000,000 430,000,000Long-term loans to relatedparties . . . . . . . . . . . . . . . . . . . 12.2 504,737,773 1,835,000,000 58,209,232,771 26,939,292,192

Property, plant and equipment,net . . . . . . . . . . . . . . . . . . . . . . 14, 15 206,705,301,913 167,326,087,378 84,330,156,861 80,986,067,642

Intangible assets, net . . . . . . . . . . 16 3,977,379,942 418,343,856 330,919,994 344,559,759Deferred income tax assets . . . . . 17.2 8,543,179,497 6,995,813 — —Other non-current assets

Prepaid expenses . . . . . . . . . 18 194,156,625 194,730,206 — —Deferred remunerationunder agreement . . . . . . . 978,906,799 1,038,466,889 978,906,799 1,038,466,889

Other non-current assets . . . 19 100,779,096 99,423,924 24,861,602 24,403,343

Total Non-current Assets . . . . . . . 221,926,752,946 171,303,384,711 168,677,213,956 133,482,191,554

Total Assets . . . . . . . . . . . . . . . . . . . . . 300,710,609,755 238,255,416,437 217,189,352,568 170,860,613,541

Notes to financial statements are an integral part of these financial statements.

(Signed) Anon Sirisaengtaksin(Anon Sirisaengtaksin)

President and Chief Executive Officer

(Signed) Sermsak Satchawannakul(Sermsak Satchawannakul)

Manager, Finance

F-58

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

BALANCE SHEETS—(Continued)AS AT DECEMBER 31, 2009 AND 2008

Unit: Baht

Notes

Consolidated The Company

2009 2008 2009 2008

Liabilities and Shareholders’ EquityCurrent Liabilities

Trade accounts payable . . . . . . . . . . . . . . . 918,725,737 2,245,413,374 270,317,656 172,045,983Current portion of long-term debts . . . . . . 20, 21 10,327,577,889 — 9,498,741,249 —Short-term loans . . . . . . . . . . . . . . . . . . . . 20 1,934,955,131 2,985,956,821 999,204,995 2,985,956,821Working capital to co-venturers . . . . . . . . 652,233,615 983,840,136 145,942,711 324,508,233Accrued expenses . . . . . . . . . . . . . . . . . . . 20,726,274,992 15,960,297,268 8,870,960,142 8,821,069,916Accrued interest payable . . . . . . . . . . . . . . 238,509,384 109,834,658 238,509,384 109,834,658Income tax payable . . . . . . . . . . . . . . . . . . 19,037,505,829 26,048,878,498 15,094,309,098 18,125,660,794Short-term provision . . . . . . . . . . . . . . . . . 22 873,418,354 — — —Other current liabilities . . . . . . . . . . . . . . . 1,486,391,497 1,115,673,137 950,690,568 802,104,389

Total Current Liabilities . . . . . . . . . . . . . . 56,195,592,428 49,449,893,892 36,068,675,803 31,341,180,794

Non-current LiabilitiesBonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 48,951,198,113 18,488,054,449 48,951,198,113 18,488,054,449Finance lease liabilities . . . . . . . . . . . . . . . 21 10,556,720,810 — — —Deferred income tax liabilities . . . . . . . . . 17.2 14,992,994,481 15,232,222,334 11,202,642,515 11,669,519,859Other non-current liabilities

Deferred income . . . . . . . . . . . . . . . . 23 2,608,737,278 2,534,432,248 — —Remuneration under agreement . . . . 24 — 1,122,636,800 — 1,122,636,800Provision for employee benefits . . . . 25 1,164,681,340 763,353,205 1,104,779,664 730,969,366Provision for decommissioningcosts . . . . . . . . . . . . . . . . . . . . . . . 26 22,821,103,348 16,309,665,236 10,426,554,592 10,142,130,637

Other non-current liabilities . . . . . . . 418,816,080 251,332,653 268,752,983 251,332,653

Total Non-current Liabilities . . . . . . . . . . 101,514,251,450 54,701,696,925 71,953,927,867 42,404,643,764

Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . 157,709,843,878 104,151,590,817 108,022,603,670 73,745,824,558

Shareholders’ EquityShare capital . . . . . . . . . . . . . . . . . . . . . . . 27

Authorized share capital3,322,000,000 ordinary sharesof Baht 1 each . . . . . . . . . . . . 3,322,000,000 3,322,000,000 3,322,000,000 3,322,000,000

Issued and paid-up share capital3,312,560,700 ordinary sharesof Baht 1 each . . . . . . . . . . . . 3,312,560,700 — 3,312,560,700 —

3,307,084,400 ordinary sharesof Baht 1 each . . . . . . . . . . . . — 3,307,084,400 — 3,307,084,400

Share premium . . . . . . . . . . . . . . . . . . . . . 13,784,668,840 13,423,109,280 13,784,668,840 13,423,109,280Currency translation differences . . . . . . . . (2,537,667,138) (2,281,147,979) — —Retained earnings

AppropriatedLegal reserve . . . . . . . . . . . . . . . 332,200,000 332,200,000 332,200,000 332,200,000Reserve for expansion . . . . . . . . 16,900,000,000 16,900,000,000 16,900,000,000 16,900,000,000

Unappropriated . . . . . . . . . . . . . . . . . 111,209,003,475 102,422,579,919 74,837,319,358 63,152,395,303

Total Shareholders’ Equity . . . . . . . . . . . . . . . . 143,000,765,877 134,103,825,620 109,166,748,898 97,114,788,983

Total Liabilities and Shareholders’ Equity . . . . 300,710,609,755 238,255,416,437 217,189,352,568 170,860,613,541

Notes to financial statements are an integral part of these financial statements.

F-59

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF INCOMEFOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

Unit: Baht

Notes

Consolidated The Company

2009 2008 2009 2008

RevenuesSales . . . . . . . . . . . . . . . . . . . . . . 115,547,525,128 132,620,657,176 72,498,326,625 78,889,220,818Revenue from pipelinetransportation . . . . . . . . . . . . . 3,762,603,676 4,131,144,739 — —

Other revenuesGain on foreignexchange . . . . . . . . . . . . 28 — 117,995,132 — —

Interest income . . . . . . . . . 376,273,736 942,229,325 1,779,237,320 1,352,956,003Other revenues . . . . . . . . . . 29 651,837,175 2,195,116,629 103,917,372 2,121,703,916

Dividend received from relatedparties . . . . . . . . . . . . . . . . . . . — — 1,946,998,450 4,454,521,150

Total Revenues . . . . . 120,338,239,715 140,007,143,001 76,328,479,767 86,818,401,887

ExpensesOperating expenses . . . . . . . . . . 11,926,256,536 10,528,529,760 5,114,316,449 6,171,757,769Exploration expenses . . . . . . . . . 7,377,274,117 8,273,388,955 191,621,830 326,741,483Administrative expenses . . . . . . 5,061,922,671 4,497,136,341 2,371,567,203 2,371,749,552Petroleum royalties andremuneration . . . . . . . . . . . . . 30 14,065,574,385 17,328,157,956 8,949,903,955 9,973,538,159

Depreciation, depletion andamortization . . . . . . . . . . . . . . 29,856,004,386 23,285,725,104 17,765,146,850 12,879,949,415

Other expensesLoss on foreignexchange . . . . . . . . . . . . 28 508,219,408 — 178,626,594 177,503,361

Loss from MontaraIncident . . . . . . . . . . . . . 31 9,085,875,964 — — —

Derivative loss onhedging . . . . . . . . . . . . . — 904,488,124 — —

Management’sremuneration . . . . . . . . . 32 156,083,519 159,426,460 156,083,519 159,426,460

Total Expenses . . . . . . 78,037,210,986 64,976,852,700 34,727,266,400 32,060,666,199Loss from the investments inassociates . . . . . . . . . . . . . . . . . . . . (17,863,550) (12,402,173) — —

Income before finance costs andincome taxes . . . . . . . . . . . . . . . . . 42,283,165,179 75,017,888,128 41,601,213,367 54,757,735,688

Finance costs . . . . . . . . . . . . . . . . . . . 1,870,328,040 840,822,921 1,783,674,802 840,822,921

Income before income taxes . . . . . . . 40,412,837,139 74,177,065,207 39,817,538,565 53,916,912,767Income taxes . . . . . . . . . . . . . . . . . . . 17.1 18,259,240,291 32,502,229,315 14,765,441,218 19,554,946,839

Net income . . . . . . . . . . . . . . . . . . . . . 22,153,596,848 41,674,835,892 25,052,097,347 34,361,965,928

Earnings per share . . . . . . . . . . . . . . . 34Basic earnings per share . . . . . . 6.69 12.62 7.57 10.41Diluted earnings per share . . . . . 6.69 12.60 7.56 10.39

Notes to financial statements are an integral part of these financial statements.

F-60

PTTEXPLORATIO

NANDPRODUCTIO

NPUBLIC

COMPANYLIM

ITEDANDSU

BSIDIA

RIE

S

STATEMENTSOFCHANGESIN

SHAREHOLDERS’

EQUIT

YCONSO

LID

ATED

FORTHEYEARSENDEDDECEMBER31,2009AND2008

Unit:

Baht

Note

Sharecapital

issued

andpa

id-up

Share

prem

ium

Currencytran

slation

differences

Legal

reserve

Reserve

for

expa

nsion

Retained

earnings

Total

Balan

ce—as

atJanu

ary1,

2008

..................

3,297,420,300

12,859,030,620

(2,315,109,076)

332,200,00016,900,000,000

75,713,280,888

106,786,822,732

Sharecapitalissuedand

paid-up

................

9,664,100

564,078,660

——

——

573,742,760

Currencytranslation

differences

.............

——

33,961,097

——

—33,961,097

Netincome

...............

——

——

—41,674,835,892

41,674,835,892

Dividends

paid

............

——

——

—(14,965,536,861)

(14,965,536,861)

Balan

ce—as

atDecem

ber31,

2008

..................

3,307,084,400

13,423,109,280

(2,281,147,979)

332,200,00016,900,000,000

102,422,579,919134,103,825,620

Sharecapitalissuedand

paid-up

................

5,476,300

361,559,560

——

——

367,035,860

Currencytranslation

differences

.............

——

(256,519,159)

——

—(256,519,159)

Netincome

...............

——

——

—22,153,596,848

22,153,596,848

Dividends

paid

............

37—

——

——

(13,367,173,292)

(13,367,173,292)

Balan

ce—as

atDecem

ber31,

2009

..................

3,312,560,700

13,784,668,840

(2,537,667,138)

332,200,00016,900,000,000

111,209,003,475143,000,765,877

Notes

tofinancialstatementsarean

integralpartof

thesefinancialstatements.

F-61

PTTEXPLORATIO

NANDPRODUCTIO

NPUBLIC

COMPANYLIM

ITEDANDSU

BSIDIA

RIE

S

STATEMENTSOFCHANGESIN

SHAREHOLDERS’

EQUIT

YTHECOMPANY

FORTHEYEARSENDEDDECEMBER31,2009AND2008

Unit:

Baht

Note

Sharecapital

issued

andpa

id-up

Share

prem

ium

Legal

reserve

Reserve

for

expa

nsion

Retained

earnings

Total

Balan

ce—as

atJanu

ary1,2008

......

3,297,420,300

12,859,030,620

332,200,000

16,900,000,000

43,755,966,236

77,144,617,156

Sharecapitalissuedandpaid-up..

.....

9,664,100

564,078,660

——

—573,742,760

Netincome

..................

.....

——

——

34,361,965,928

34,361,965,928

Dividends

paid

....................

——

——

(14,965,536,861)

(14,965,536,861)

Balan

ce—as

atDecem

ber31,2008

...

3,307,084,400

13,423,109,280

332,200,000

16,900,000,000

63,152,395,303

97,114,788,983

Sharecapitalissuedandpaid-up.......

5,476,300

361,559,560

——

—367,035,860

Netincome

.......................

——

——

25,052,097,347

25,052,097,347

Dividends

paid

....................

37—

——

—(13,367,173,292)

(13,367,173,292)

Balan

ce—as

atDecem

ber31,2009

...

3,312,560,700

13,784,668,840

332,200,000

16,900,000,000

74,837,319,358

109,166,748,898

Notes

tofinancialstatementsarean

integralpartof

thesefinancialstatements.

F-62

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CASH FLOWSFOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

Unit : Baht

Consolidated The Company

2009 2008 2009 2008

Cash flows from operating activitiesIncome before income taxes . . . . . . . . . . . . . . . . . . 40,412,837,139 74,177,065,207 39,817,538,565 53,916,912,767Adjustment to reconcile income before incometaxes to net cash provided by (used in)operating activitiesLoss from the investment in associates . . . . . 17,863,550 12,402,173 — —Depreciation, depletion and amortization . . . . 29,856,004,386 23,285,725,104 17,765,146,850 12,879,949,415Amortization of prepaid expenses . . . . . . . . . 71,899,139 91,103,649 71,325,558 50,233,566Amortization of exploration expenses . . . . . . 5,671,138,123 6,306,832,353 11,543,204 49,138,679(Gain) loss on disposal of assets . . . . . . . . . . . 3,498,913,840 3,944,973 13,224,922 (3,779,913)Income recognized from deferred income . . . 87,427,649 (531,164,451) — —Dividends received from related parties . . . . . — — (1,946,998,450) (4,454,521,150)Loss from Montara Incident . . . . . . . . . . . . . . 3,105,525,354 — — —Provision for employee benefits . . . . . . . . . . . 401,328,135 383,993,603 373,810,298 358,630,116(Gain) loss on foreign exchange . . . . . . . . . . . (844,492,213) 404,138,149 (458,293,451) 192,248,923Interest income (higher) less than interestexpenses . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,390,664,559 (112,276,103) (14,001,366) (523,002,781)

83,669,109,661 104,021,764,657 55,633,296,130 62,465,809,622

Changes in operating assets and liabilities(Increase) decrease in trade accountsreceivable . . . . . . . . . . . . . . . . . . . . . . . . . . (1,771,801,719) 645,111,436 (29,016,917) 7,420,382

(Increase) decrease in trade accountsreceivable—parent company . . . . . . . . . . . (985,762,226) 532,109,874 (995,391,453) 204,070,978

(Increase) decrease in inventories . . . . . . . . . (383,459,468) 269,744,507 (80,739,561) 66,301,919Increase in materials and supplies, net . . . . . . (1,904,582,417) (2,132,213,265) (718,991,170) (510,880,514)(Increase) decrease in working capital fromco-venturers . . . . . . . . . . . . . . . . . . . . . . . . 544,704,176 (542,588,984) (12,412,761) 21,464,771

(Increase) decrease in other accountsreceivable . . . . . . . . . . . . . . . . . . . . . . . . . . (1,727,195,611) (303,559,427) 392,031,685 (585,698,470)

(Increase) decrease in other current assets . . . 91,134,537 187,690,039 (632,464,339) (102,810,538)Increase in prepaid expenses . . . . . . . . . . . . . — (1,481,053) — —(Increase) decrease in other non-currentassets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,692,537) 401,140 (458,258) (38,306)

Increase in deferred income tax assets . . . . . . (3,435,836,005) — — —(Decrease) increase in trade accountspayable . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,388,630,945) 457,912,159 99,200,303 32,952,307

Decrease in working capital toco-venturers . . . . . . . . . . . . . . . . . . . . . . . . (319,857,191) (463,259,008) (176,142,891) (310,757,099)

Increase in accrued expenses . . . . . . . . . . . . . 1,787,258,986 2,472,569,488 141,965,431 1,057,516,487(Decrease) increase in other currentliabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 973,149,480 (433,156,055) 151,395,111 52,229,239

(Decrease) increase in deferred income . . . . . 1,864,078 (64,070) — —(Decrease) increase in other non-currentliabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . (959,333,045) 8,235,036 (1,095,631,492) 8,235,036

Loss from translation adjustment . . . . . . . . . . . . . . (91,568,450) (121,795,791) — —Interest received from bank deposits . . . . . . . . . . . 368,849,245 823,534,151 253,429,875 461,221,432Taxation paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (31,576,865,911) (23,156,096,469) (18,304,621,803) (11,623,794,094)

(40,782,625,023) (21,756,906,292) (21,007,848,240) (11,222,566,470)

Net cash provided by operatingactivities . . . . . . . . . . . . . . . . . . . . . . . 42,886,484,638 82,264,858,365 34,625,447,890 51,243,243,152

F-63

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

STATEMENTS OF CASH FLOWS—(Continued)FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

Unit : Baht

Consolidated The Company

2009 2008 2009 2008

Cash flows from investing activities(Increase) decrease in loans to relatedparties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,330,262,227 (1,235,000,000) (31,270,256,232) (11,803,085,718)

Increase in investments in related parties . . . (555,838,206) — (606,364,649) —Dividends received from related parties . . . . — — 1,946,998,450 4,454,521,150Interest received from loans . . . . . . . . . . . . . 44,558,767 82,624,440 1,534,695,279 884,692,404Increase in property, plant and equipment . . (59,388,765,720) (48,983,884,767) (20,571,106,781) (19,914,774,583)Increase in intangible assets . . . . . . . . . . . . . (3,633,423,120) (140,377,695) (50,547,214) (72,227,586)

Net cash used in investing activities . . . (62,203,206,052) (50,276,638,022) (49,016,581,147) (26,450,874,333)

Cash flows from financing activities(Decrease) increase in short-term loans . . . . (1,360,717,196) 2,905,842,370 (2,185,934,382) 2,905,842,370Proceeds from bonds . . . . . . . . . . . . . . . . . . . 39,950,119,444 — 39,950,119,444 —Interest paid . . . . . . . . . . . . . . . . . . . . . . . . . . (1,439,081,012) (750,726,127) (1,437,378,671) (750,726,127)Proceeds from common stock . . . . . . . . . . . . 367,035,860 573,742,760 367,035,860 573,742,760Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . (13,366,259,736) (14,963,994,605) (13,366,259,736) (14,963,994,605)

Net cash provided by (used in)financing activities . . . . . . . . . . . . . . 24,151,097,360 (12,235,135,602) 23,327,582,515 (12,235,135,602)

Net increase in cash and cash equivalents . . . . . . . . . . . 4,834,375,946 19,753,084,741 8,936,449,258 12,557,233,217Cash and cash equivalents at the beginning of theyear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,994,689,588 24,012,741,011 26,132,472,261 13,504,898,492

48,829,065,534 43,765,825,752 35,068,921,519 26,062,131,709Adjustment for the effect of exchange rate changes oncash and cash equivalents . . . . . . . . . . . . . . . . . . . . . (151,296,097) 228,863,836 (41,511,649) 70,340,552

Cash and cash equivalents at the end of the year . . . . . 48,677,769,437 43,994,689,588 35,027,409,870 26,132,472,261

Notes to financial statements are an integral part of these financial statements.

F-64

PTT EXPLORATION AND PRODUCTION PUBLIC COMPANY LIMITED AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTSFOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008

(UNIT: MILLION BAHT, EXCEPT AS NOTED)

1. General Information

PTT Exploration and Production Public Company Limited (the Company) is registered as a company inThailand and listed on the Stock Exchange of Thailand. The address of its registered office is 555/1 EnergyComplex Building A, Floors 6 and 19-36, Vibhavadi-Rangsit Road, Chatuchak, Bangkok 10900.

The principal business operations of the Company, subsidiaries, and associates (the Group) are explorationand production of petroleum in Thailand and overseas, foreign gas pipeline transportation, and investment inprojects strategically connected to the energy business.

As at December 31, 2009, the Group has operations in 13 countries and investments in exploration andproduction projects with percentages of interest as follows:

Project Country Operator Company’s percentage of interest

2009 2008

PTT Exploration and Production Public Company Limited

Bongkot . . . . . . . . . . . . . . . . . . Thailand PTT Exploration and ProductionPlc.

44.4445 44.4445

Arthit . . . . . . . . . . . . . . . . . . . . Thailand PTT Exploration and ProductionPlc.

80 80

Arthit North . . . . . . . . . . . . . . . Thailand PTT Exploration and ProductionPlc.

100 100

Pailin . . . . . . . . . . . . . . . . . . . . Thailand Chevron Thailand Exploration andProduction, Ltd.

45 45

Sinphuhorm (E5 North) . . . . . . Thailand Hess (Thailand) Ltd. 20 20S1 . . . . . . . . . . . . . . . . . . . . . . . Thailand PTTEP Siam Limited 25 25Unocal III . . . . . . . . . . . . . . . . Thailand Chevron Thailand Exploration and

Production, Ltd.5 5

E5 . . . . . . . . . . . . . . . . . . . . . . Thailand ExxonMobil Exploration andProduction Khorat Inc.

20 20

PTTEP International Limited (PTTEPI)

Yadana . . . . . . . . . . . . . . . . . . . Myanmar Total E&P Myanmar 25.50 25.50Yetagun . . . . . . . . . . . . . . . . . . Myanmar Petronas Carigali Myanmar

(Hong Kong) Ltd.19.3178 19.3178

PTTEP 1 . . . . . . . . . . . . . . . . . Thailand PTTEP International Limited 100 100G4/43 . . . . . . . . . . . . . . . . . . . . Thailand Chevron Offshore (Thailand) Ltd. 21.375 21.375G9/43 . . . . . . . . . . . . . . . . . . . . Thailand- PTTEP International Limited 100 100

CambodiaL22/43 . . . . . . . . . . . . . . . . . . . Thailand PTTEP International Limited 100 100Cambodia B . . . . . . . . . . . . . . . Cambodia PTTEP International Limited 33.333334 33.333334Myanmar M9 & M11 . . . . . . . Myanmar PTTEP International Limited 100 100Myanmar M3, M4 & M7 . . . . Myanmar PTTEP International Limited 100 100MTJDA-B17 . . . . . . . . . . . . . . Thailand -

MalaysiaCarigali-PTTEPI OperatingCompany Sendirian Berhad

50 50

F-65

Project Country Operator Company’s percentage of interest

2009 2008

PTTEP Offshore Investment Company Limited (PTTEPO)

B8/32 & 9A1 . . . . . . . . . . . . . . Thailand Chevron Offshore (Thailand) Ltd. 25.0010 25.0010New Zealand Great South . . . . New Zealand OMV New Zealand Limited — 36

PTTEP Southwest Vietnam Company Limited (PTTEP SV)

Vietnam 52/97 . . . . . . . . . . . . . Vietnam Chevron Vietnam (Block52), Ltd.

7 7

PTTEP Kim Long Vietnam Company Limited (PTTEP KV)

Vietnam B & 48/95 . . . . . . . . . Vietnam Chevron Vietnam (Block B), Ltd. 8.50 8.50

PTTEP Hoang-Long Company Limited (PTTEP HL)

Vietnam 16-1 . . . . . . . . . . . . . . Vietnam Hoang Long JointOperating Company

28.50 28.50

PTTEP Hoan-Vu Company Limited (PTTEP HV)

Vietnam 9-2 . . . . . . . . . . . . . . . Vietnam Hoan-Vu Joint OperatingCompany

25 25

PTTEP Oman Company Limited (PTTEP OM)

Oman 44 . . . . . . . . . . . . . . . . . Oman PTTEP Oman CompanyLimited

100 100

Oman 58 . . . . . . . . . . . . . . . . . Oman PTTEP Oman CompanyLimited

100 100

PTTEP Algeria Company Limited (PTTEP AG)

Algeria 433a & 416b . . . . . . . . Algeria Petrovietnam ExplorationProduction Corporation

35 35

PTTEP (Thailand) Limited (PTTEPT)

Bongkot (G 12/48) . . . . . . . . . Thailand PTTEP (Thailand) Limited 44.4445 44.4445Arthit (G 9/48) . . . . . . . . . . . . . Thailand PTTEP (Thailand) Limited 80 84L 53/43 & L 54/43 . . . . . . . . . . Thailand PTTEP (Thailand) Limited 100 100G4/48 . . . . . . . . . . . . . . . . . . . . Thailand Chevron Pattani, Ltd. 5 —

PTTEP Siam Limited (PTTEPS)

Sinphuhorm (EU-1) . . . . . . . . . Thailand Hess (Thailand) Ltd. 20 20B 6/272 . . . . . . . . . . . . . . . . . . . Thailand PTTEP Siam Limited 60 100S1 . . . . . . . . . . . . . . . . . . . . . . . Thailand PTTEP Siam Limited 75 75L 21, 28 & 29/48 . . . . . . . . . . . Thailand PTTEP Siam Limited 70 70A 4, 5 & 6/48 . . . . . . . . . . . . . . Thailand PTTEP Siam Limited 100 100

PTTEP Iran Company Limited (PTTEP IR)

Iran Saveh . . . . . . . . . . . . . . . . Iran PTTEP Iran Company Limited 100 100

PTTEP Merangin Company Limited (PTTEPM)

Indonesia Merangin-1 . . . . . . . Indonesia PT Medco E&P Merangin — 40

F-66

Project Country Operator Company’s percentage of interest

2009 2008

PTTEP Bengara I Company Limited (PTTEPB)

Indonesia Bengara-1 . . . . . . . . Indonesia PT Medco E&P Bengara 40 40

PTTEP Thai Projects Company Limited (PTTEP TP)

Unocal III (G 6/50) . . . . . . . . . Thailand Chevron Petroleum Thailand Ltd. 5 5Pailin (G 7/50) . . . . . . . . . . . . . Thailand Chevron Petroleum Thailand

Ltd.45 45

Arthit (G 8/50) . . . . . . . . . . . . . Thailand PTTEP Thai ProjectsCompany Limited

80 80

PTTEP Australia Offshore Pty Limited (PTTEP AO)

Australia AC/P 36 . . . . . . . . . . Australia Murphy Australia Oil Pty Ltd. 20 20Australia WA 423 . . . . . . . . . . Australia Murphy Australia Oil Pty Ltd. 30 30

PTTEP Bangladesh Limited (PTTEP BD)

Bangladesh 17 & 18 . . . . . . . . People’sRepublic ofBangladesh

Total E&P Bangladesh — 30

PTTEP Bahrain Company Limited (PTTEP BH)

Bahrain 2 . . . . . . . . . . . . . . . . . Bahrain PTTEP Bahrain CompanyLimited.

100 100

PTTEP Rommana Company Limited (PTTEPR)

Rommana . . . . . . . . . . . . . . . . Egypt Sipetrol International S.A. 30 30

PTTEP Semai II Limited (PTTEP SM)

Indonesia Semai II . . . . . . . . . . Indonesia Murphy Semai Oil Co., Ltd 33.33 33.33

PTTEP Sidi Abd El Rahman Company Limited (PTTEP SAER)

Sidi Abd El RahmanOffshore . . . . . . . . . . . . . . . . Egypt Edison International SPA 30 30

PTTEP New Zealand Limited (PTTEP NZ)

New Zealand Great South . . . . New Zealand OMV New Zealand Limited 36 —

PTTEP Australia Perth Pty Ltd (PTTEP AP)

PTTEP Australasia* . . . . . . . . Australia

F-67

* Details of operators and percentage of interest in PTTEP Australasia project are as follows:

Block Operator Company’s percentage of interest

2009 2008

AC/L7, AC/L8, AC/P34, andAC/P40 . . . . . . . . . . . . . . . . . . . . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 100 —

AC/L1, AC/L2 and AC/L3 . . . . . . . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 89.6875 —AC/RL7 . . . . . . . . . . . . . . . . . . . . . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 80 —AC/P24 . . . . . . . . . . . . . . . . . . . . . . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 60 —AC/RL4 and AC/RL5 (Tenacious) . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 75 —AC/RL6 (Audacious), AC/P4, AC/RL4,AC/RL5, AC/RL6 and AC/P17 . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 50 —

AC/P32 . . . . . . . . . . . . . . . . . . . . . . . . . . PTTEP Australasia (Ashmore Cartier) Pty Ltd 35 —WA-378-P, WA-396-P andWA-397-P . . . . . . . . . . . . . . . . . . . . . . Woodside Energy Limited 20 —

1 PTTEPO has shareholding in Orange Energy Limited and B 8/32 Partners Limited, which hold project’s concessions.2 The project name was changed from Nang Nuan to B6/27 and the transfer of 40% interest to Nippon Oil Exploration Limited (NOEX)

was approved by the Thai Government on July 27, 2009.

2. Basis of Financial Statement Preparation

The consolidated and the Company financial statements have been prepared in accordance with Thaigenerally accepted accounting principles under the Accounting Act B.E. 2543, being those Thai AccountingStandards issued under the Accounting Profession Act B.E. 2547 including interpretation and accountingguidance announced by the Federation of Accounting Professions, as well as the financial reporting requirementsof the Securities and Exchange Commission under the Securities and Exchange Act B.E. 2535.

The consolidated and the Company financial statements have been prepared in accordance with theannouncement by the Department of Business Development relating to the requirement of minimum line items inthe financial statements B.E. 2552 dated January 30, 2009 pursuant to the third paragraph of section 11 of theAccounting Act B.E. 2543. This announcement is effective for the accounting period beginning on or afterJanuary 1, 2009. The application of such announcement has no significant impact on the financial statements.

The Group has adopted the International Accounting Standards (IASs) No. 12 “Income Taxes” and No. 19“Employee Benefits” which have not yet been addressed by the Thai Accounting Standards.

Where the Group has entered into joint interest operations with other parties to participate in exploration,development and production of petroleum businesses, the Group records its share of expenses, assets andliabilities incurred in accordance with the Statements of Expenditures prepared by the operators of theConcession or the Production Sharing Contract. The Statements of Expenditures have been audited by anotherindependent auditor on an annual basis and by the joint venture committee on a regular basis.

The consolidated and the Company financial statements have been prepared under the historical cost basisexcept as disclosed in the accounting policies.

The preparation of financial statements in conformity with Thai generally accepted accounting principlesrequires management to make estimates and assumptions that affect the amounts of assets, liabilities, revenuesand expenses reported in the financial statements. Estimates and assumptions are based on management’sexperience and other information available which is reasonable in a particular circumstance. Although theseestimates and assumptions are based on management’s best knowledge of current events and actions, actualresults may differ from these estimates.

F-68

An English-language version of the consolidated and the Company financial statements has been translatedfrom the statutory financial statements which are prepared in Thai-language. In the event of a conflict ordifference in the interpretation between the two languages, the Thai-language version of the statutory financialstatements shall prevail.

3. New Accounting Standards, New Financial Reporting Standards, New Accounting Guidance andAmendments to Accounting Standards

Thai Accounting Standards were renumbered with effect from June 26, 2009 following the endorsement inthe Government Gazette and the announcement by the Federation of Accounting Professions in order to conformto the numbers used in the International Financial Reporting Standards.

Accounting standards, financial reporting standards and accounting guidance that are effective for the periodbeginning on or after January 1, 2009 and revised accounting framework are as follows:

Thai Accounting Standard No. 36 (Revised 2007) “Impairment of Assets”

Thai Financial Reporting Standard No. 5 (Revised 2007) “Non-current Assets Held for Sale andDiscontinued Operations”

Accounting Guidance for Leasehold Right

Accounting Guidance for Business Combination under Common Control

Accounting Framework (Revised 2007)

These accounting standards, financial reporting standards, accounting guidance and accounting frameworkdo not have a material impact on the Group’s financial statements being presented.

The revised accounting standards and new accounting standards which are effective for the period beginningon or after January 1, 2011 and January 1, 2012 and which have not been early adopted by the Group are asfollows:

• Effective for the period beginning on or after January 1, 2011

Thai Accounting Standard No. 24 (Revised 2007) “Related Party Disclosure”

Thai Accounting Standard No. 40 “Investment Property”

• Effective for the period beginning on or after January 1, 2012

Thai Accounting Standard No. 20 “Accounting for Government Grants andDisclosure of Government Assistance”

The Company’s management have determined that the revised standards and the new standards will nothave any significant impact on the Group’s financial statements being presented.

4. Significant Accounting Policies

4.1 Preparation of Consolidated Financial Statements

The consolidated financial statements comprise the Company, subsidiaries, associates and joint ventures.The major inter-company transactions between the Company and subsidiaries are eliminated from theconsolidated financial statements.

F-69

Subsidiaries

Subsidiaries are those entities over which the Group has the power to govern their financial and operatingpolicies generally accompanying a shareholding of more than one half of the voting rights. The existence andeffect of potential voting rights that are currently exercisable or convertible, including potential voting rights heldby another entity, are considered when assessing whether the Group controls another entity. Subsidiaries areconsolidated from the date on which control is transferred to the Group and are no longer consolidated from thedate that control ceases.

The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. Thecost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilitiesincurred or assumed at the date of exchange, plus other costs directly attributable to the acquisition. Identifiableassets and liabilities acquired from a business combination are measured initially at their fair values at theacquisition date.

The excess of the cost of acquisition over the fair value of the Group’s share of the identifiable net assetsacquired is recorded as goodwill; on the other hand, if the cost of acquisition is less than the fair value of the netassets of the subsidiary acquired, the difference is recognized directly in the income statement.

The investments in the subsidiaries are presented by using the cost method in the Company’s financialstatements.

The details of subsidiaries is set out in Note 13. The effects of acquisitions of subsidiaries are shown inNote 6.

Associates

Associates are those entities over which the Group has significant influence over their financial policies andoperations, but does not control. Investments in associates are initially recognized at cost and are accounted forusing the equity method in the consolidated financial statements from the date on which the Group gainssignificant influence and are no longer consolidated from the date that significant influence ceases.

The Group’s shares of the associates’ post-acquisition profits or losses are recognized in the incomestatement, and the share of post-acquisition movements in surplus is recognized in reserves. The Group does notrecognize further losses that exceed its investment in the associates, unless it has incurred obligations or madepayments on behalf of the associates.

Accounting policies of associates have been changed where necessary to ensure consistency with thepolicies adopted by the Group.

The investments in the associates are presented by using the cost method in the Company’s financialstatements.

A list of associates is set out in Note 13.

Joint Ventures

The Group’s interests in jointly controlled entities are accounted for by proportionate consolidation. Underthis method, the Group includes its shares of the joint ventures’ individual income, expenses, assets, liabilitiesand cash flows on a line-by-line basis with similar items in the Group’s financial statements.

The Group’s interests in jointly controlled assets are accounted for by proportionate consolidation. Underthis method, the Group includes their shares of the assets, liabilities, expenses and cash flows based on JointOperating Agreement on a line-by-line basis with similar items in the Group’s financial statements.

F-70

Gains or losses from the joint ventures are presented by using the cost method in the Company’s financialstatements.

For details of jointly controlled entities and jointly controlled assets, please refer to Note 13 and Note 1,respectively.

Related Parties

Related parties are those entities that directly or indirectly control, or are controlled by the Company, or areunder common control with the Company. They also include holding companies, subsidiaries, fellow subsidiariesand associates.

In considering each relationship between parties, attention is directed to the substance of the relationship,not merely the legal form.

4.2 Foreign Currency Translation

Transactions included in the financial statements of each entity in the Group are measured using Thai Baht.The consolidated financial statements are presented in Thai Baht.

Foreign currency transactions are translated into Thai Baht at the exchange rates ruling on the transactiondates. Monetary assets and liabilities denominated in foreign currency remaining at the balance sheet date aretranslated into Thai Baht at the exchange rate ruling on the balance sheet date. Gains and losses arising from thesettlement of foreign currency transactions and from the translation of monetary assets and liabilitiesdenominated in foreign currencies are recognized in the income statement in the period in which they occur.

The monetary assets and liabilities of foreign operations are translated into Thai Baht using the averagebuying and selling rates determined by the Bank of Thailand at year-end, whereas the income statement istranslated using the exchange rates ruling on the transaction dates. Gains or losses from such translation arerecognized in the income statement in the period in which they occur.

The assets and liabilities of foreign entities are translated into Thai Baht using the average buying andselling rates determined by the Bank of Thailand at year-end, whereas the income statement is translated usingaverage exchange rates during the period. Differences from such translation have been presented under thecaption “Currency translation differences” in the shareholders’ equity.

4.3 Cash and Cash Equivalents

Cash and cash equivalents comprise cash on hand and at banks, and other short-term highly liquidinvestments with original maturities of three months or less from the date of acquisition.

4.4 Trade Accounts Receivable

Trade accounts receivable are carried at net realizable value. An allowance for doubtful accounts isprovided, based on the company’s review of all outstanding receivable amounts at the balance sheet date. Theamount of the allowance is the difference between the carrying amount of the receivable and the amountexpected to be collected. Doubtful accounts are written off and recorded as expenses in the income statementwhen they are identified.

Factoring Policy of Accounts Receivable

The factoring of accounts receivable is made on an arms-length basis. The company will write-off suchaccounts receivable when the future economic benefits and other major relevant benefits are transferred to thethird party and the Company receives the funds from such factoring.

F-71

4.5 Inventories

Inventories are stated at the lower of cost or net realizable value. Cost is determined by the weightedaverage method. Net realizable value is the estimated selling price in the ordinary course of business less thecosts of completion and selling expenses.

4.6 Materials and Supplies

Materials and supplies are stated at the average cost less the allowance for obsolete and unserviceable itemsused in petroleum exploration and production activities.

4.7 Borrowing Costs

Borrowing costs directly attributable to finance the construction of property, plant and equipment during therequired period of time or the preparation of the assets for their intended use are capitalized as part of the cost ofthe respective assets. All other borrowing costs are expensed in the period in which they are incurred.

4.8 Property, Plant and Equipment

Property, plant and equipment are presented at cost, after deducting accumulated depreciation and theprovision for the impairment of assets.

• Oil and Gas Properties

The Company follows the Successful Efforts Method in the accounting for its assets used for oil andgas exploration and production activities as follows:

Cost of Properties

Costs of properties comprise total acquisition costs of petroleum rights or the portion of costsapplicable to properties as well as the decommissioning costs.

Exploratory drilling costs are capitalized and will be classified as assets of the projects if theirexploratory wells have found proved reserves that have been found to be commercially producible. If,however, the exploratory wells have not found proved reserves, such drilling costs will be expensed in theincome statement.

Exploration costs, comprising geological and geophysical costs as well as area reservation fees duringthe exploration stage, are charged to expenses when incurred.

Development costs, whether relating to the successful or unsuccessful development of wells, arecapitalized.

Depreciation, Depletion and Amortization

The capitalized acquisition costs of petroleum rights are depleted and amortized using unit ofproduction method based on estimated proved recoverable reserves. Depreciation, depletion andamortization of exploratory wells, development, equipment and operating costs of support equipment aswell as the decommissioning costs, except unsuccessful projects, are calculated on the unit of productionmethod based on estimated proved reserves or proved developed reserves. Changes in reserve estimates arerecognized prospectively.

Proved reserves and proved developed reserves are calculated by the engineers of the Group and theinformation received from the joint ventures.

F-72

• Pipelines and Others

Costs of properties comprise purchase prices and other direct costs necessary to bring the asset toworking condition suitable for its intended use.

Depreciation of pipelines and others are determined using the straight-line method with an estimateduseful life of 5 – 30 years.

Where the carrying amount of an asset is greater than its estimated recoverable amount, it is written downimmediately to its recoverable amount.

Gains and losses on disposal of property, plant and equipment are determined by referring to their carryingamount and are taken into account in the income statement when incur.

The cost of major renovations is included in the carrying amount of the asset when it is probable that futureeconomic benefits in excess of the originally assessed standard of performance of the existing asset will flow tothe Group.

Repair and maintenance costs are recognized as expenses when incur.

4.9 Carried Costs under Petroleum Sharing Contract

Under Petroleum Sharing Contracts in which the government has a participation interest, some contractsrequire the contracting parties, excluding the government, to fund the costs of all exploration operations until thefirst development area is determined. During the exploration period, the contracting parties will carry an agreedupon proportion of the government’s exploration costs (carried costs). When the project commences production,such carried costs shall be fully recouped without interest by the contracting parties from the production ofpetroleum under the agreed procedures.

The Group classifies the transactions of carried costs through various accounts based on petroleum activitiesunder the Successful Efforts Method. They are mainly recorded in oil and gas properties in balance sheet andexploration expenses in the income statement. (For details, please refer to Note 15.)

4.10 Intangible Assets

• Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the Group’s share ofthe net identifiable assets of the acquired subsidiaries or associates undertaking at the date of acquisition.Goodwill on acquisitions of subsidiaries is reported in the consolidated balance sheet as an intangible asset.Goodwill on acquisitions of associates is included in investments in associates and is tested for impairmentas part of the overall balance.

Goodwill is annually tested for impairment and carried at cost less accumulated impairment losses.Impairment losses on goodwill are not reversed. Gains and losses on the disposal of an entity include thecarrying amount of goodwill relating to the entity sold.

Goodwill is allocated to cash-generating units for the purpose of impairment testing. The allocation ismade to a single cash-generating unit or group of cash-generating units that are expected to benefit from thebusiness combination in which the goodwill arose.

F-73

• Probable Reserves

Probable reserves represent reserves that were assessed by the Group at the time when there was apurchase of business. Probable reserves will be classified as oil and gas properties once they are provedreserves and amortized using the unit of production method.

• Other Intangible Assets

Other intangible assets comprise expenditures incurred for licenses acquired for computer softwarewhich are capitalized and amortized using the straight-line method over the remaining of the contractperiod, or a maximum of 10 years. The carrying amount is reviewed by the Group and the allowance forimpairment will be provided whenever events or circumstances indicate that the carrying amount may notbe recoverable.

4.11 Impairment of Assets

Assets that have an indefinite useful life, for example goodwill, are not subject to amortization and aretested annually for impairment. Assets that are subject to amortization are reviewed for impairment wheneverevents or changes in circumstances indicate that the carrying amount may not be recoverable. An impairmentloss is recognized for the amount by which the carrying amount of the assets exceeds its recoverable amountwhich is the higher of an asset’s fair value less costs to sell and value in use, and is recorded in the incomestatement. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there areseparately identifiable cash flows.

Estimates of future cash flows used in the evaluation for impairment of assets related to petroleumproduction are made using risk assessment on field and reservoir performance and are inclusive of expectationsabout proved and unproved reserves volumes.

Impairments, except those related to goodwill, are reversed as applicable to the extent that the events orcircumstances that triggered the original impairment have changed. If that is the case, the carrying amount ofasset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount thatwould have been determined, net of depreciation, if the Group did not recognize the impairment loss for assets inprior year.

4.12 Deferred Income Taxes

Deferred income tax is provided in full, using the balance sheet liability method, on temporary differencesarising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Theprincipal temporary differences arise from depreciation of property, plant and equipment, the amortization ofdecommissioning costs and the difference between the fair value of the acquired net assets and their tax bases.

Tax rates enacted or substantively enacted by the balance sheet date are used to determine deferred incometax.

Deferred tax assets are recognized to the extent that it is probable that future taxable profit will be availableagainst which the temporary differences can be utilized.

Deferred income tax is provided on temporary differences arising from investments in associates and jointlycontrolled entities, except where the timing of the reversal of the temporary difference can be controlled and it isprobable that the temporary difference will not reverse in the foreseeable future.

Deferred income tax assets and liabilities can be offset only when they both relate to the same legal taxauthority.

F-74

4.13 Deferred Remuneration under Agreement

According to the conditions in the Gas Sales Agreement of Arthit project, the Company has an obligation tomake a payment to the buyer (PTT) in its operation. The remuneration is classified as non-current asset, reportedunder the caption deferred remuneration under agreement, and is amortized over the contract life using thestraight-line method.

4.14 Borrowings

The Group records its borrowings with the fair value of the proceeds received, net of transaction costsincurred.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer thesettlement of the liability for at least 12 months after the balance sheet date.

4.15 Leases

• Leases—where a Group company is the lessee

Leases of property, plant and equipment which substantially transfer all the risks and rewards ofownership to the lessee are classified as finance leases. Finance leases are capitalized at the inception of thelease at the lower of the fair value of the leased property or the present value of the minimum leasepayments. Each lease payment is allocated to the principal and to the finance charges so as to achieve aconstant interest rate on the finance balance outstanding. The outstanding rental obligations, net of financecharges, are included in liabilities. The interest element of the finance cost is charged to the incomestatement over the lease period so as to achieve a constant periodic rate of interest on the remaining balanceof the liability for each period. The property, plant and equipment acquired under finance leases isdepreciated over the shorter period of the useful life of the asset or the lease term.

Leases not transferring a significant portion of the risks and rewards of ownership to the lessee areclassified as operating leases. Payments made under operating leases are charged to the income statement ona straight-line basis over the lease period.

When an operating lease is terminated before the lease period has expired, any payment required to bemade to the lessor by way of penalty is recognized as an expense in the period in which termination takesplace.

• Leases—where a Group company is the lessor

Assets leased out under operating leases are included in property, plant and equipment in the balancesheet. They are depreciated over their expected useful lives on a basis consistent with other similar property,plant and equipment owned by the Group. Rental income is recognized on a straight-line basis over the leaseterm.

4.16 Employee Benefits

The Group’s employees have become members in the following provident funds: “Employee of PTTEPRegistered Provident Fund”, “Employee of PTTEP Registered Provident Fund 2”, “Sataporn RegisteredProvident Fund”, “TISCO Ruamtun 1 Registered Provident Fund” and “TISCO Ruamtun 2 Registered ProvidentFund.”

F-75

The provident funds are funded by payments from employees and from the Group which are held in aseparate trustee-administered fund. The Group contributes to the funds at a rate of 3 – 15 % of the employees’salaries which are charged to the income statement in the period to which the contributions relate.

This obligation is presented in the balance sheets under the provision for employee benefits as discussed inNote 25. In addition, the transitional liabilities will be amortized as expenses in the income statement on astraight-line basis over 5 years.

The Group’s obligation in respect of the retirement benefit plans is calculated by estimating the amount offuture benefits that employees will have earned in return for their services to the Company and subsidiaries in thecurrent period and in future period. Such benefits are discounted to the present value using the rate ofgovernment bond yields. The calculation is performed by an independent actuary using the Projected Unit CreditMethod.

When the benefits under the plans are changed, the portion of the increased benefits relating to the pastservices of employees is recognized in the income statement on a straight-line basis over the average remainingperiod until the benefits become vested. The expense is recognized immediately in the income statement whenthe benefits are paid.

Salaries, wages, bonuses and contributions to the social security and provident funds are recognized asexpenses when incurred.

4.17 Provisions

Provisions, excluding the provisions for employee benefits, are recognized when the Group has a presentlegal or constructive obligation as a result of past events and it is probable that an outflow of resources will berequired to settle the obligation and a reliable estimate of the amount can be made. Where the Group expects aprovision to be reimbursed, for example under an insurance contract, the reimbursement is recognized as aseparate asset when the reimbursement is virtually certain.

Provisions for Decommissioning Costs

The Group records a provision for decommissioning costs whenever it is probable that there is an obligationas a result of a past event and the amount of that obligation is reliable.

The Group recognizes provision for decommissioning costs, which are provided at the onset of completionof the project, for the estimate of the eventual costs that relate to the removal of the production facilities. Thesecosts were included as part of the oil and gas properties and were amortized based on proved reserves on a unit ofproduction basis. The estimates of decommissioning costs have been determined based on reviews and estimatesby the Group’s own engineers and managerial judgment.

4.18 Capital Risk Management

The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a goingconcern in order to provide returns to shareholders and benefits to other stakeholders and to maintain an optimalcapital structure to reduce the cost of capital.

4.19 Reserve for Expansion

The Group has a reserve for expanding its investments in new projects in the exploration phase, which aregenerally susceptible to high risk, and for finding additional petroleum reserves. The reserve for expansion is setaside at no more than 35% of the net taxable income from its exploration and production activities.

F-76

4.20 Income Recognition

Sales are recognized upon delivery of products and customer acceptance. Service income from gas pipelineconstruction is recognized on the basis of percentage of completion. Interest income is recognized on a timeproportion basis, taking into account the effective yield on the asset. Revenues other than those mentioned aboveare recognized on an accrual basis.

4.21 Deferred Income under Agreements (Take-or-Pay)

Under Gas Sales Agreement, the Group has obligations to supply minimum quantities of gas to customer. Ifin any contract year, customer has not taken the minimum quantities of gas according to the Gas SalesAgreement, customer shall pay for quantities of gas not taken (Take-or-Pay). Should the customer be unable totake the minimum contracted quantities in a given year, the volume of gas that the customer has paid for but hasnot taken in that year (Make-up) can be taken free of charge in subsequent years. Payments received in advanceunder these agreements are recognized as deferred income. This deferred income is recognized in the incomestatement when the gas is subsequently taken. (For details, please refer to Note 23)

The Group made prepayments for royalty related to cash received in advance under Take-or-Pay Agreementto the government of Myanmar. The prepayment will be expensed when the gas is subsequently taken by thecustomers. (For details, please refer to Note 18)

4.22 Income Taxes

The Group’s expenditures and revenues for tax purposes comprise:

• Current period tax which is calculated in accordance with the Petroleum Income Tax Act B.E. 2514and Amendment B.E. 2532 and the Revenue Code

• Income tax in the Union of Myanmar

• Income tax in the Socialist Republic of Vietnam

• Corporate income tax in Australia

• Petroleum Resource Rent Tax in Australia

• Corporate income tax in the Sultanate of Oman

• Deferred income taxes, which are calculated as disclosed in Note 17.

4.23 Earnings per Share

Basic earnings per share are calculated by dividing the net income attributable to shareholders by theweighted average number of ordinary shares in issue during the year.

Diluted earnings per share are calculated by dividing the net income attributable to shareholders by theweighted average number of ordinary shares in issue during the year, adjusted with dilutive potential ordinaryshares. The Company assumes that all dilutive potential ordinary shares are converted into ordinary shares in theearning per share calculation.

4.24 Segment Reporting

The segment details are primarily presented by the business operations and secondly by the geographicalareas.

F-77

Business segments provide business activities that are subject to risks and returns different from those ofother business segments. Geographical segments provide business operations within a particular economicenvironment that are subject to risks and return different from those of components operating in other economicenvironments.

5. Major Estimates and Assumptions

In order to prepare the financial statements in conformity with the accounting standards, management isrequired to use estimates and assumptions which impact assets, liabilities, income and expenses. The datarelating to the major assumptions and uncertainties in the estimate which may have an impact on the carryingamount of assets and liabilities presented in the financial statements are as follows:

Estimate for Oil and Gas Reserves

Oil and gas reserves are key elements in the Group’s investment decision-making process which is focusedon generating value. They are also important elements in testing for impairment. Changes in proved oil and gasreserves will also affect the standardized measure of discounted cash flows and the unit-of-productiondepreciation.

Proved reserves are the estimated quantities of petroleum that geological and engineering data demonstratewith reasonable certainty to be recoverable in future years from known reservoirs under existing economic andoperating conditions including government’s rules and regulations. The proved reserves have to be examined andassessed annually by the Group’s geologists and reservoir engineers.

Exploration Costs

Capitalized exploration drilling costs more than 12 months old are expensed unless (1) proved reserved arebooked or (2) they have found commercially producible quantities of reserves and they are subject to furtherexploration or appraisal activity. In making decisions about whether to continue capitalizing exploration drillingcosts for a period longer than 12 months, it is necessary to make judgments about the satisfaction of eachcondition in the present event. If there is a change in one of these judgments in a subsequent period, the relatedcapitalized exploration drilling costs would be expensed in that period.

Impairment of Assets

Value in use of assets under consideration for impairment is assessed by the estimate for the discountedfuture cash flows. The expected future cash flows is based on management’s estimates in relation to the futureselling price, demand and supply in the market, margin rate and estimated future production volume. Expectedfuture production volumes, which include both proved reserves as well as volumes that are expected to constituteproved reserves in the future, are used for impairment testing because the Group believes this is the mostappropriate indicator of expected future cash flows, used as a measure of value in use. The discounted rate for theimpairment testing reflects the current market assessment of the time value of money and the risk specific to theassets for which the future cash flow estimates have not been adjusted.

Goodwill and Intangible Assets

For recognition and measurement of goodwill and intangible assets as of acquisition date includingsubsequent impairment testing, management uses estimated future cash flow from assets or cash-generating unitand appropriate discount rate for present value of future cash flow calculation.

Income Tax

The Group is subject to income taxes in numerous jurisdictions. Significant judgment is required indetermining the worldwide provision for income taxes due to the fact that there are many transactions and

F-78

calculations for which the ultimate tax determination is uncertain during the ordinary course of business. TheGroup recognizes liabilities for anticipated tax based on estimates of whether additional taxes will be due. Wherethe final tax outcome of these matters is different from the amounts that were initially recorded, such differenceswill affect the income tax and deferred tax provisions in the period in which such determination is made.

Deferred tax assets are recognized to the extent that it is probable that future taxable profits will be availableagainst which the temporary differences can be utilized. The management is required to make an estimate fornumber of the deferred income tax assets that should be recognized by considering the assumption about theprobable future tax benefits in each period. The assumption for the future taxable income may containuncertainty as to whether if there is a change, the recognition of the deferred tax asset will be affected.

Lease

In considering whether a lease agreement is an operating lease or a finance lease, management has exercisedjudgment in assessing terms and conditions of the agreement to ensure whether the risks and rewards of assetsare transferred to the Group or not.

Employee Retirement Plans

The Group’s obligation regarding the retirement benefit plans is calculated by estimating the amount offuture benefits that employees will have earned in return for their services to the Company and subsidiaries in thecurrent and in the future periods. The calculation is performed by an independent actuary using the ProjectedUnit Credit Method and the relevant assumptions which include financial and demographic assumptions asdisclosed in Note 25.

When the benefits under the plans are changed, the portion of the increased benefits relating to the pastservices of employees is recognized in the income statement on a straight-line basis over the average remainingperiod until the benefits become vested. The expense is recognized immediately in the income statement whenthe benefits are paid.

Provisions

The provisions are recognized by the Group and presented in the balance sheet when there is an obligationas a result of a past event and there is the possibility that the company will have to pay its beneficial assets forsuch an obligation when its amount can be reliably calculated.

The Group records a provision for decommissioning costs whenever it is probable that there would be anobligation of a reliable amount as a result of a past event. The Group recognizes provision for decommissioningcosts, which are provided at the onset of completion of the project, for the estimate of the eventual costs thatrelate to the removal of the production facilities. These costs were included as part of the oil and gas propertiesand were amortized based on proved reserves on a unit of production basis. The estimates of decommissioningcosts have been determined based on reviews and estimates by the Group’s engineers and managerial judgment.

The provisions are based on the current situation such as regulations, technologies and prices. The actualresults could differ from these estimates as future confirming events occur.

6. Acquisition

On February 4, 2009, the Group acquired 100% of the ordinary shares of Coogee Resources Limited (CRL)whose name was later changed to PTTEP Australasia Pty Limited. CRL was engaged in the investment anddevelopment of oil and gas exploration and production businesses in Australia. The acquired business contributeda net loss of Baht 5,497 million to the Group for the period from February 4, 2009 to December 31, 2009.

F-79

Details of net assets acquired and goodwill are as follows:

Purchase consideration (cash paid) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,475.05Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,290.23

Goodwill (Note 16) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184.82

The assets and liabilities arising from the acquisition are as follows:

Fair ValueAcquiree’s carrying

amount

Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 361.87 371.05Restricted cash at bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 503.69 503.69Trade accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 324.43 324.43Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 376.76 367.54Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 441.75 441.75Deferred tax assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,435.84 1,326.49Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,813.07 26,513.06Intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,382.68 —Trade accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,485.77) (2,695.95)Borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (12,846.43) (12,957.67)Finance lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8,343.21) (8,439.46)Other assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 325.55 372.37

Net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,290.23 6,127.30

Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184.82

Total purchase consideration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,475.05Less: Cash and cash equivalents in subsidiary acquired . . . . . . . . . . . . . . . . . . . . 361.87

Cash outflow on acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,113.18

On October 22, 2009, the Group purchased 100% shareholders’ equity in OMV Timor Sea Pty Ltd (OMV)whose name was later changed to PTTEP Australasia Timor Sea Pty Limited. OMV was engaged in theinvestment and development of oil and gas exploration and production businesses in Australia. The acquiredbusiness contributed net loss of Baht 46 million to the Group for the period from October 22, 2009 toDecember 31, 2009.

Details of net assets acquired and goodwill are as follows:

Purchase consideration (cash paid) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.84Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.84

Difference between the purchase consideration and fair value of net assets acquired . . . . . . . . . . . . . . . . —

The assets and liabilities arising from the acquisition are as follows:

Fair ValueAcquiree’s carrying

amount

Trade accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.20 11.20Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296.66 305.47Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 951.91 26.44Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27.92 27.92Deferred tax assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43.47 —Trade accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (27.51) (27.51)Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (716.81) (256.87)

Net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.84 86.65

Cash outflow on acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.84

F-80

As at December 31, 2009, the Group was reconsidering the fair value of the net assets. The expected fairvalue of the net assets will be adjusted when the initial accounting transaction is completed.

7. Cash and Cash Equivalents

Cash and cash equivalents as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Cash on hand and at banks . . . . . . . . . . . . . . . . . . . . . . . 12,884.37 10,856.97 7,208.93 5,119.13Cash equivalents

—Fixed deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,852.64 10,699.69 11,128.86 6,789.87—Treasury bills . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,940.76 22,438.03 16,689.62 14,223.47

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48,677.77 43,994.69 35,027.41 26,132.47

The interest rate on saving deposits held at call with banks is 0.07 – 3.75% per annum (2008: 0.75 –2.48% per annum). The interest rate on fixed deposits with banks is 0.30 – 3.97% per annum (2008: 2.04 –3.42% per annum). The interest rate on treasury bills is 0.78 – 1.76% per annum (2008: 3.00-3.59% per annum).

8. Trade Accounts Receivable—Parent Company

Trade accounts receivable—parent company as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Sales of petroleum products . . . . . . . . . . . . . . . . . . . . . . 9,820.09 8,512.00 6,598.80 5,274.22Gas pipeline construction service . . . . . . . . . . . . . . . . . . 1,098.50 1,427.68 1,098.50 1,427.68

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,918.59 9,939.68 7,697.30 6,701.90

9. Trade Accounts Receivable

Trade accounts receivable as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Petro Summit Pty Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,354.17 — — —Myanmar Oil and Gas Enterprise . . . . . . . . . . . . . . . . . . 611.80 922.50 — —Star Petroleum Refining Co., Limited . . . . . . . . . . . . . . 512.47 — 36.62 —Chevron Product Company . . . . . . . . . . . . . . . . . . . . . . 346.02 221.19 0.52 —Chevron U.S.A. INC. . . . . . . . . . . . . . . . . . . . . . . . . . . . 238.84 129.57 — —Petrovietnam Exploration . . . . . . . . . . . . . . . . . . . . . . . . 137.31 143.76 — —Ministry of Oil and Gas (Oman) . . . . . . . . . . . . . . . . . . 102.08 94.57 — —Electricity Generating Authority of Thailand . . . . . . . . 40.38 73.76 10.09 18.44Others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.50 1.59 0.63 0.40

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,345.57 1,586.94 47.86 18.84

F-81

10. Materials and Supplies, Net

Materials and supplies, net as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Materials and supplies—at cost . . . . . . . . . . . . . . . . . . . . . . . . . 8,216.14 6,475.45 3,283.90 2,566.51Provision for obsolescence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (70.57) (60.66) (26.73) (16.82)

Materials and supplies—net . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,145.57 6,414.79 3,257.17 2,549.69

11. Other Accounts Receivable

As of December 31, 2009, other receivables balance of Baht 3,685 million included other receivables fromStuart Petroleum Limited amounting to Baht 1,356 million incurred as the Group entered into a Sale andPurchase Agreement with Auralandia Parties and Stuart Petroleum Limited (an Operator) to invest in the 100%participation interest in Petroleum Permits AC/P33 (Oliver Block) with the purchase price of approximately USD35 million together with obligation for cost of drilling the exploration well. However, as at December 31, 2009,this transaction was conditional on approval by Australian government. Therefore, the Group recognized suchcost as other accounts receivable because this amount will only be repayable by Stuart Petroleum Limited in theevent that this transaction is not approved.

12. Related Party Transactions

Significant transactions with related parties are summarized as follows:

12.1 Revenues and Expenses with Related Parties

Significant transactions with related parties for the years ended December 31, 2009 and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Parent company—PTT Public Company Limited (PTT)Sales revenue (world market reference price) . . . . . . . . . 100,147.28 115,773.87 72,126.70 78,776.48Rental revenue (market price) . . . . . . . . . . . . . . . . . . . . . 21.07 18.66 21.07 18.66Income from gas pipeline construction services . . . . . . . — 1,946.60 — 1,946.60Derivative loss on hedging . . . . . . . . . . . . . . . . . . . . . . . — 99.00 — —Amortization of deferred remuneration underagreement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59.56 45.85 59.56 45.85

Subsidiaries, associate and jointly controlled entitiesInterest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44.56 82.16 1,551.42 866.65Management fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 11.25 10.89Interest expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 4.79 —

F-82

12.2 Long-Term Loans to Related Parties

Long-term loans to related parties as at December 31, 2009 and 2008 comprised:

Loans to Consolidated The Company

2009 2008 2009 2008

SubsidiariesPTTEPI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 29,257.77 11,376.14PTTEPO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 28,355.05 13,657.08PTTEP Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 106.41 71.07

AssociatesEnCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 490.00 1,835.00 490.00 1,835.00ShoreAir . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.74 — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 504.74 1,835.00 58,209.23 26,939.29

Movements of long-term loans to related parties for the year ended December 31, 2009 are as follows:

Consolidated The Company

Balance as at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,835.00 26,939.29Addition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,169.74 60,604.68Repayment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,500.00) (29,176.31)Currency translation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — (158.43)

Balance as at December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 504.74 58,209.23

The Company has loans to subsidiaries with an interest rate of 2.73 – 4.07% per annum (2008: interest rate3.81 – 5.13% per annum). The subsidiaries shall occasionally repay the loans. In addition, the Company providedloans to an associate with an interest rate of 3.25 – 6.75% per annum (2008: interest rate 6.75 – 7.69% perannum).

F-83

13.Investmentsin

Subsidiaries,A

ssociatesan

dJointlyCon

trolledEntities

13.1

Subsidiary

Com

panies,A

ssociatedCom

panies,a

ndJointly

Con

trolledEntities

Com

pany

Registered

Cou

ntry

Typ

eof

business

Paid-in

capital1

Shareholding

by

Percentage

ofinterest

Investment

Dividendfor

theyears

2009

2008

CostMetho

dEqu

ityMetho

d

2009

2008

2009

2008

2009

2008

2009

2008

Subsidiary

Com

panies

PTTEPInternationalL

imited(PTTEPI)

...

Thailand

Petroleum

20,000.00

20,000.00

PTTEP

100%

100%

20,000.00

20,000.00

35,746.46

35,124.01

—1,000.00

PTTEPOffshoreInvestmentC

ompany

Lim

ited(PTTEPO

)..................

Cayman

Islands

Petroleum

0.17

0.17

PTTEP

PTTEPI

75%

25%

75%

25%

0.13

0.04

0.13

0.04

15,790.36

5,273.35

19,648.62

6,538.56

——

PTTEPSo

uthw

estV

ietnam

Com

pany

Lim

ited(PTTEPSV

)................

Cayman

Islands

Petroleum

2.03

2.03

PTTEPO

100%

100%

2.03

2.03

(247.76)

(237.89)

——

PTTEPKim

LongVietnam

Com

pany

Lim

ited(PTTEPKV)................

Cayman

Islands

Petroleum

2.03

2.03

PTTEPO

100%

100%

2.03

2.03

(427.83)

(415.77)

——

PTTEPHoang-LongCom

pany

Lim

ited

(PTTEPHL).......................Cayman

Islands

Petroleum

2.12

2.12

PTTEPO

100%

100%

2.12

2.12

(6,765.96)

(6,743.22)

——

PTTEPHoan-VuCom

pany

Lim

ited

(PTTEPHV).......................Cayman

Islands

Petroleum

2.16

2.16

PTTEPO

100%

100%

2.16

2.16

(1,167.98)

(1,979.31)

——

PTTEPOman

Com

pany

Lim

ited

(PTTEPOM)......................

Cayman

Islands

Petroleum

2.16

2.16

PTTEPO

100%

100%

2.16

2.16

(836.54)

1,682.98

——

PTTEPAlgeriaCom

pany

Lim

ited

(PTTEPAG).......................Cayman

Islands

Petroleum

2.10

2.10

PTTEPO

100%

100%

2.10

2.10

(2,439.42)

(2,220.96)

——

PTTEP(Thailand)Lim

ited(PTTEPT

).....

Thailand

Petroleum

100.00

100.00

PTTEPI

100%

51%

100.00

51.00

28.88

(10.73)

——

PTTEPOM

—49%

—49.00

—(10.31)

——

PTTEPServices

Lim

ited(PTTEP

Services)..........................

Thailand

Services

1.00

1.00

PTTEP

25%

25%

0.25

0.25

2.72

32.98

35.99

—PT

TEPI

75%

—1.59

—1.28

——

—PT

TEPT

—75%

—0.75

—98.93

107.96

—PT

TEPSiam

Lim

ited(PTTEPS

).........

Thailand

Petroleum

100.00

100.00

PTTEP

51%

49%

3,872.76

3,719.03

6,253.83

5,948.49

1,911.01

3,454.52

PTTEPO

49%

51%

3,713.33

3,864.89

6,080.88

6,188.55

1,988.99

3,595.48

PTTEPIran

Com

pany

Lim

ited

(PTTEPIR)

.......................Cayman

Islands

Petroleum

1.91

1.91

PTTEPOM

100%

100%

1.91

1.91

(2,123.48)

(447.65)

——

PTTEPMeranginCom

pany

Lim

ited

(PTTEPM

)........................

Cayman

Islands

Petroleum

2.05

2.05

PTTEPO

100%

100%

2.05

2.05

(468.45)

(463.52)

——

PTTEPBahrain

Com

pany

Lim

ited

(PTTEPBH).......................Cayman

Islands

Petroleum

1.90

1.90

PTTEPOM

100%

100%

1.90

1.90

(375.86)

(30.30)

——

PTTEPHolding

Com

pany

Lim

ited

(PTTEPH

).........................Cayman

Islands

Petroleum

1.88

1.88

PTTEPO

100%

100%

1.88

1.88

(9,326.88)

(437.25)

——

PTTEPIndonesiaCom

pany

Lim

ited

(PTTEPID

).......................Cayman

Islands

Petroleum

1.88

1.88

PTTEPH

100%

100%

1.88

1.88

(449.61)

(185.32)

——

PTTEPBengara

ICom

pany

Lim

ited

(PTTEPB

).........................Cayman

Islands

Petroleum

1.88

1.88

PTTEPID

100%

100%

1.88

1.88

(286.88)

(181.54)

——

PTTEPThaiP

rojectsLim

ited

(PTTEPTP)

.......................

Thailand

Petroleum

1.00

1.00

PTTEPT

100%

100%

1.00

1.00

(16.35)

(4.63)

——

PTTEPAndam

anLim

ited(PTTEPA).....

Thailand

Petroleum

0.25

0.25

PTTEPS

100%

100%

0.25

0.25

0.10

0.15

——

PTTEPEgypt

Com

pany

Lim

ited

(PTTEPEG).......................Cayman

Islands

Petroleum

1.69

1.69

PTTEPH

100%

100%

1.69

1.69

(720.86)

(71.74)

——

PTTEPRom

manaCom

pany

Lim

ited

(PTTEPR

).........................Cayman

Islands

Petroleum

1.69

1.69

PTTEPEG

100%

100%

1.69

1.69

(53.64)

(17.37)

——

F-84

Com

pany

Registered

Cou

ntry

Typ

eof

business

Paid-in

capital1

Shareholding

byPercentageof

interest

Investment

Dividendfor

theyears

2009

2008

CostMetho

dEqu

ityMetho

d

2009

2008

2009

2008

2009

2008

2009

2008

Subsidiary

Com

panies

PTTEPSidi

Abd

ElR

ahman

Com

pany

Lim

ited

(PTTEPSA

ER)...............Cayman

Islands

Petroleum

1.69

1.69

PTTEPEG

100%

100%

1.69

1.69

(664.51)

(52.34)

——

PTTEPAustraliaPtyLim

ited

(PTTEPAU).................

Australia

Petroleum

1.53

1.53

PTTEPH

100%

100%

1.53

1.53

(1,499.27)

(170.58)

——

PTTEPAustraliaOffshorePty

Lim

ited(PTTEPAO)..........

Australia

Petroleum

1.53

1.53

PTTEPAU

100%

100%

1.53

1.53

(1,492.24)

(168.36)

——

PTTEPBangladeshLim

ited(PTTEP

BD)........................

Cayman

Islands

Petroleum

1.67

1.67

PTTEPH

100%

100%

1.67

1.67

(337.91)

(3.64)

——

PTTEPMyanm

arLim

ited

(PTTEPMYA)1

..............

Cayman

Islands

Petroleum

1.59

1.59

PTTEPH

100%

100%

1.59

1.59

1.45

1.56

——

PTTEPNew

Zealand

Lim

ited

(PTTEPNZ).................Cayman

Islands

Petroleum

1.70

1.70

PTTEPH

100%

100%

1.70

1.70

(476.78)

1.70

——

PTTEPSemaiIILim

ited

(PTTEPSM

).................Cayman

Islands

Petroleum

1.74

1.74

PTTEPID

100%

100%

1.74

1.74

(160.28)

(1.58)

——

PTTEPAustraliaPerthPtyLim

ited

(PTTEPAP)*

................

Australia

Petroleum

1.20

1.20

PTTEPH

100%

100%

1.20

1.20

(5,833.44)

1.13

——

Andam

anTransportationLim

ited

(ATL)1......................

Cayman

Islands

Petroleum

1.74

—PT

TEPO

100%

—1.74

—1.48

——

—PT

TEPWestA

fricaCom

pany

Lim

ited(PTTEPWA)1

.........Cayman

Islands

Petroleum

1.77

—PT

TEPH

100%

—1.77

—1.48

——

—AssociatedCom

panies

EnergyCom

plex

Com

pany

Lim

ited

(EnC

o)......................

Thailand

Com

merce

1,800.00

800.00

PTTEP

50%

50%

900.00

400.00

803.76

337.42

——

PTTICTSo

lutio

nsCom

pany

Lim

ited(PTTICT)............

Thailand

Services

150.00

150.00

PTTEP

20%

20%

30.00

30.00

40.03

46.92

——

PTTEPAP’sAssociates2

.........

Australia

Services

33.77

—PT

TEPAAO

50%

—16.88

—78.52

——

—JointlyCon

trolledEntities

Carigali—

PTTEPI

Operatin

gCom

pany

SdnBhd.(CPO

C).....

Malaysia

Petroleum

3.68

2.21

PTTEPI

50%

50%

1.84

1.11

1.70

1.01

——

MoattamaGas

Transportation

Com

pany

(MGTC)............

Bermuda

Gas

pipelin

etransportatio

n0.76

0.76

PTTEPO

25.5%

25.5%

0.19

0.19

1,521.84

2,068.10

3,479.45

2,988.62

TaninthayiP

ipelineCom

pany

LLC

(TPC

)......................

Cayman

Islands

Gas

pipelin

etransportatio

n2.62

2.62

PTTEPO

19.3178%

19.3178%

445.33

445.33

1,347.68

1,637.89

1,982.92

1,767.88

OrangeEnergyLim

ited(O

range)

...

Thailand

Petroleum

100.00

100.00

PTTEPO

53.9496%

53.9496%

13,567.69

13,567.69

7,854.78

9,108.25

1,435.68

1,585.84

B8/32

PartnersLim

ited(B8/32

Partners)....................

Thailand

Petroleum

110.00

110.00

PTTEPO

25.0009%

25.0009%

4,523.69

4,523.69

2,778.88

2,940.19

332.14

988.96

Relationship:

The

Com

pany

directly

orindirectly

holdstheshares

insubsidiaries,associates,andjointly

controlledentities.Su

bsidiaries’managem

entteamsarefrom

theCom

pany.

1AsatDecem

ber31,2009,PT

TEPMYA,A

TL,P

TTEPWAhave

sharereceivables.

2PT

TEPAP’sAssociatesareSh

oreA

irPtyLtd

andTroughton

Island

PtyLtd

F-85

* Details of PTTEP AP’s subsidiaries which were audited by another auditor are as follows:

CompanyRegisteredcountry

Percentageof interest

PTTEP Australia Browse Basin Pty Limited (PTTEP AB) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia Pty Limited (PTTEP AA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia Timor Sea Pty Limited (PTTEP AT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Finance) Pty Ltd (PTTEP AAF) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Petroleum) Pty Ltd (PTTEP AAP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Tullian) Pty Ltd (PTTEP AAT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Operations) Pty Ltd (PTTEP AAO) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Ashmore Cartier) Pty Ltd (PTTEP AAA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%PTTEP Australasia (Staff) Pty Ltd (PTTEP AAS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Australia 100%

13.2 Investments in Subsidiaries, Associates, and Jointly Controlled Entities

Changes of investments which are accounted for using the equity method for the consolidated financialstatements and using cost method for the Company’s financial statements comprised:

Consolidated The Company

2009 2008 2009 2008

Net book value as at the beginning of the year . . . . . . . . . . . . . . . . . 384.34 396.74 24,149.40 24,149.40Share of net loss from investment after income taxes . . . . . . . . . . . . (17.86) (12.40) — —Increase in investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 552.14 — 653.74 —Currency translation differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.69 — — —

Net book value as at the end of the year . . . . . . . . . . . . . . . . . . . . . . 922.31 384.34 24,803.14 24,149.40

13.3 Investments in Subsidiaries

Investments in subsidiaries accounted for using the equity method for the consolidated financial statementsand using cost method for the Company’s financial statements comprised:

Consolidated The Company

2009 2008 2009 2008

PTTEP International Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 20,000.00 20,000.00PTTEP Offshore Investment Company Limited . . . . . . . . . . . . . . . . — — 0.13 0.13PTTEP Services Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 0.25 0.25PTTEP Siam Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 3,872.76 3,719.02

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 23,873.14 23,719.40

13.4 Investments in Associates

Investments in associates accounted for using the equity method for the consolidated financial statementsand using cost method for the Company’s financial statements comprised:

Consolidated The Company

2009 2008 2009 2008

Energy Complex Company Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . 803.76 337.42 900.00 400.00PTT ICT Solutions Company Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . 40.03 46.92 30.00 30.00PTTEP AP group’s associates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78.52 — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922.31 384.34 930.00 430.00

F-86

Assets, liabilities, income and gains (losses) from associates as at December 31, 2009 and 2008 are asfollows:

EnCo ICTPTTEP AP group’s

Associates

2009 2008 2009 2008 2009 2008

Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,943.98 2,602.63 176.36 167.96 92.85 —Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,140.22 2,265.21 136.33 121.40 14.33 —Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.60 0.17 170.70 189.44 74.99 —Gains (Losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (33.65) (27.48) (6.90) 14.63 22.69 —

13.5 Investments in Jointly Controlled Entities

Investments in jointly controlled entities are recorded in the Company’s financial statements using the costmethod. The Company presents its share of the assets, liabilities, incomes and expenses of jointly controlledentities, together with similar items, under similar headings in the proportionate consolidated financialstatements.

Transactions of jointly controlled entities are included in the Company’s financial statements as follows:

CPOC MGTC TPC Orange B8/32 Partners

2009 2008 2009 2008 2009 2008 2009 2008 2009 2008

Balance Sheets:Current assets . . . . . . . . . . . . 622.09 1,307.57 682.82 971.69 358.24 541.96 3,401.07 4,180.81 995.71 941.59Non-current assets . . . . . . . . . — — 2,830.51 3,122.45 1,585.43 1,736.40 5,905.25 6,919.41 2,176.58 2,664.95Current liabilities . . . . . . . . . . (620.39) (1,306.56) (19.73) (25.26) (23.31) (37.41) (2,107.12) (3,482.72) (474.79) (960.09)Non-current liabilities . . . . . . — — (1,745.83) (1,801.09) (562.23) (600.10) (1,995.46) (2,302.57) (735.76) (871.72)

Net assets . . . . . . . . . . . . . . . 1.70 1.01 1,747.77 2,267.79 1,358.13 1,640.85 5,203.74 5,314.93 1,961.74 1,774.73

MGTC TPC Orange B8/32 Partners

2009 2008 2009 2008 2009 2008 2009 2008

Statements of income :Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,501.66 4,955.81 2,926.94 2,934.85 8,367.69 11,048.31 2,795.65 4,032.03Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (273.03) (282.53) (190.28) (206.48) (5,788.18) (6,795.26) (1,934.18) (2,503.98)

Income before income taxes . . . . . . . . . . . . . . . . . 4,228.63 4,673.28 2,736.66 2,728.37 2,579.51 4,253.05 861.47 1,528.05Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,247.01) (1,376.78) (825.95) (830.70) (1,255.02) (2,121.53) (342.33) (723.00)

Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,981.62 3,296.50 1,910.71 1,897.67 1,324.49 2,131.52 519.14 805.05

F-87

14. Property, Plant and Equipment, Net

Consolidated

Oil and Gas Properties Pipeline Others Total

ProvedPropertiesand RelatedProducingProperties

UnprovedProperties

SupportEquipmentand Facilities

DecommissioningCosts

Historical costBalance as at January 1, 2008 . . . . . . . . . . . 200,346.09 15,982.39 3,053.73 12,760.07 6,837.63 2,567.74 241,547.65Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52,102.69 6,606.79 270.78 4,938.92 6.38 164.82 64,090.38Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,066.20) (12,394.55) (16.95) — — (72.62) (16,550.32)Currency translation differences** . . . . . . . — — — — 238.47 — 238.47

Balance as at December 31, 2008 . . . . . . . . 248,382.58 10,194.63 3,307.56 17,698.99 7,082.48 2,659.94 289,326.18Acquisition of subsidiaries (Note 6) . . . . . . 18,152.71* — 92.79 1,573.11 — — 19,818.61Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,017.82 2,082.11 263.14 3,956.41 13.52 487.45 57,820.45Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,013.62) (3,843.83) (8.73) — — (57.03) (7,923.21)Reclassification . . . . . . . . . . . . . . . . . . . . . . 7,064.68 (7,064.68) — — — — —Currency translation differences** . . . . . . . — — — — (319.47) — (319.47)

Balance as at December 31, 2009 . . . . . . . . 320,604.17 1,368.23 3,654.76 23,228.51 6,776.53 3,090.36 358,722.56

Accumulated depreciationBalance as at January 1, 2008 . . . . . . . . . . . (88,111.82) — (1,987.24) (4,759.99) (2,137.91) (1,156.27) (98,153.23)Depreciation for the year . . . . . . . . . . . . . . (21,521.73) — (169.08) (1,084.40) (229.93) (268.53) (23,273.67)Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . (1.04) — 17.01 (0.01) — 61.30 77.26Currency translation differences** . . . . . . . — — — — (92.38) — (92.38)

Balance as at December 31, 2008 . . . . . . . . (109,634.59) — (2,139.31) (5,844.40) (2,460.22) (1,363.50) (121,442.02)Acquisition of subsidiaries (Note 6) . . . . . . — — (46.90) (6.73) — — (53.63)Depreciation for the year . . . . . . . . . . . . . . (26,951.55) — (236.21) (2,442.29) (230.48) (262.57) (30,123.10)Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.23 — 9.30 (0.49) — 50.00 59.04Currency translation differences** . . . . . . . — — — — 104.18 — 104.18

Balance as at December 31, 2009 . . . . . . . . (136,585.91) — (2,413.12) (8,293.91) (2,586.52) (1,576.07) (151,455.53)

Provision for impairment lossesBalance as at January 1, 2008 . . . . . . . . . . . (389.54) — — — — — (389.54)Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . (78.50) (90.03) — — .— — (168.53)

Balance as at December 31, 2008 . . . . . . . . (468.04) (90.03) — — — — (558.07)Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3.66) — — — — — (3.66)

Balance as at December 31, 2009 . . . . . . . . (471.70) (90,03) — — — — (561.73)

Net book value as at December 31,2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,279.95 10,104.60 1,168.25 11,854.59 4,622.26 1,296.44 167,326.09

Net book value as at December 31,2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183,546.56 1,278.20 1,241.64 14,934.60 4,190.01 1,514.29 206,705.30

Depreciation included in the income statement for the year ended December 31, 2008 Baht 23,273.67 MillionDepreciation included in the income statement for the year ended December 31, 2009 Baht 30,123.10 Million

* The partial increase of the Oil and Gas Properties for a total of Baht 11,385.56 million during the period is from finance lease. (Fordetails, please refer to Note 21)

** Differences from foreign exchange as a result of the account translation.

F-88

The Company

Oil and Gas Properties Others Total

ProvedPropertiesand RelatedProducingProperties

UnprovedProperties

SupportEquipmentand Facilities

DecommissioningCosts

Historical costBalance as at January 1, 2008 . . . . . . . . . . . . . 105,427.95 1,338.25 1,379.51 8,051.03 1,696.72 117,893.46Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,973.80 — 144.41 2,995.38 143.14 24,256.73Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (49.74) (1,338.25) (3.94) — (50.64) (1,442.57)

Balance as at December 31, 2008 . . . . . . . . . . 126,352.01 — 1,519.98 11,046.41 1,789.22 140,707.62Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,054.29 — 15.60 737.17 459.39 21,266.45Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (11.73) — (3.70) — (56.09) (71.52)

Balance as at December 31, 2009 . . . . . . . . . . 146,394.57 — 1,531.88 11,783.58 2,192.52 161,902.55

Accumulated depreciationBalance as at January 1, 2008 . . . . . . . . . . . . . (42,465.55) — (971.13) (2,463.68) (1,029.84) (46,930.20)Depreciation for the year . . . . . . . . . . . . . . . . (11,921.61) — (53.27) (638.74) (228.42) (12,842.04)Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.09 — 4.18 — 46.42 50.69

Balance as at December 31, 2008 . . . . . . . . . . (54,387.07) — (1,020.22) (3,102.42) (1,211.84) (59,721.55)Depreciation for the year . . . . . . . . . . . . . . . . (16,510.02) — (58.99) (1,115.74) (218.81) (17,903.56)Decrease . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 3.70 — 49.02 52.72

Balance as at December 31, 2009 . . . . . . . . . . (70,897.09) — (1,075.51) (4,218.16) (1,381.63) (77,572.39)

Net book value as at December 31, 2008 . . . . 71,964.94 — 499.76 7,943.99 577.38 80,986.07

Net book value as at December 31, 2009 . . . . 75,497.48 — 456.37 7,565.42 810.89 84,330.16

Depreciation included in the income statement for the year ended December 31, 2008 Baht 12,842.04 MillionDepreciation included in the income statement for the year ended December 31, 2009 Baht 17,903.56 Million

15. Carried Cost under Petroleum Sharing Contract

As at December 31, 2009, the Group presented carried costs under oil and gas properties and othernon-current assets in the balance sheet and presented exploration expenses in the income statement for thefollowing projects:

Project

Carried Cost

Oil and GasProperties

Other Non-CurrentAssets

Exploration Expenses(Cumulative since 2002 –

December 31, 2009)

Vietnam 52/97 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 33.67 —Vietnam B & 48/95 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 35.23 —Vietnam 16-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 922.87 — 1,305.74Vietnam 9-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,185.03 — 811.23Algeria 433a & 416b . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 329.41 — 446.64

F-89

16. Intangible Assets, Net

Consolidated The Company

GoodwillProbableReserves

Other IntangibleAssets Total

Other IntangibleAssets

CostsBalance as at January 1, 2008 . . . . . . . . . . . . . . — — 844.77 844.77 758.27Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 140.35 140.35 72.23

Balance as at December 31, 2008 . . . . . . . . . . . — — 985.12 985.12 830.50Increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 65.78 65.78 50.55Acquisition of subsidiary (Note 6) . . . . . . . . . . 184.82 3,382.68 — 3,567.50 —

Balance as at December 31, 2009 . . . . . . . . . . . 184.82 3,382.68 1,050.90 4,618.40 881.05

Accumulated AmortizationBalance as at January 1, 2008 . . . . . . . . . . . . . . — — (494.18) (494.18) (427.35)Amortization for the year . . . . . . . . . . . . . . . . . — — (72.60) (72.60) (58.59)

Balance as at December 31, 2008 . . . . . . . . . . . — — (566.78) (566.78) (485.94)Amortization for the year . . . . . . . . . . . . . . . . . — — (74.24) (74.24) (64.19)

Balance as at December 31, 2009 . . . . . . . . . . . — — (641.02) (641.02) (550.13)

Net Book Value as at December 31, 2008 . . . . — — 418.34 418.34 344.56

Net Book Value as at December 31, 2009 . . . . 184.82 3,382.68 409.88 3,977.38 330.92

17. Income Taxes and Deferred Income Taxes

17.1 Income Taxes

Income taxes for the years ended December 31, 2009 and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Petroleum income taxCurrent tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,150.19 27,432.24 15,151.47 17,850.45Deferred tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (312.90) 729.59 (478.08) 1,250.37

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,837.29 28,161.83 14,673.39 19,100.82

Income tax under Revenue CodeCurrent tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (200.73) 552.08 80.85 455.44Deferred tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.58 (21.20) 11.20 (1.31)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (200.15) 530.88 92.05 454.13

Income tax in the foreign countriesCurrent tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,652.40 3,851.64 — —Deferred tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111.19 (42.12) — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,763.59 3,809.52 — —

Petroleum Resource Rent Tax in AustraliaCurrent tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (191.06) — — —Deferred tax expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (4,950.43) — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,141.49) — — —

Total income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,259.24 32,502.23 14,765.44 19,554.95

F-90

Income tax rates for the Group are as follows:

Tax Rate (%)

Petroleum income tax on petroleum businesses in Thailand pursuant to Petroleum Income Tax ActB.E. 2514 and 2532 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Income tax under Revenue CodeIncome tax for the Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 – 30Income tax for subsidiaries and jointly controlled entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 – 30

Corporate Income tax in the Union of Myanmar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Corporate Income tax in the Republic of Vietnam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Corporate income tax in Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Petroleum Resource Rent Tax in Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Corporate income tax in the Sultanate of Oman . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

17.2 Deferred Income Taxes

Deferred income taxes as at December 31, 2009 and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Deferred income tax assetsPetroleum income tax . . . . . . . . . . . . . . . . . . . . . . . . . . 172.32 — — —Income tax under Revenue Code . . . . . . . . . . . . . . . . . . 44.20 7.00 — —Corporate income tax in foreign countries . . . . . . . . . . 1,640.74 — — —Petroleum Resource Rent Tax in Australia . . . . . . . . . . 6,685.92 — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,543.18 7.00 — —

Deferred income tax liabilitiesPetroleum income tax . . . . . . . . . . . . . . . . . . . . . . . . . . 13,661.68 13,802.26 11,187.86 11,665.94Income tax under Revenue Code . . . . . . . . . . . . . . . . . . 14.78 (23.00) 14.78 3.58Corporate income tax in foreign countries . . . . . . . . . . 1,316.53 1,452.96 — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,992.99 15,232.22 11,202.64 11,669.52

Deferred income tax - net . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,449.81 15,225.22 11,202.64 11,669.52

Deferred income taxes presented by categories are as follows:

Consolidated The Company

2009 2008 2009 2008

Amortization of decommissioning costs and currencytranslation difference from decommissioning costs . . . . . 3,463.81 2,326.51 1,430.71 1,099.21

Provision for employee benefits . . . . . . . . . . . . . . . . . . . . . . 588.52 377.01 552.39 365.48Provision for impairment loss . . . . . . . . . . . . . . . . . . . . . . . . 235.85 234.02 — —Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (18,337.64) (18,181.10) (13,170.96) (13,130.63)Petroleum Resource Rent Tax in Australia . . . . . . . . . . . . . . 4,680.14 — — —Loss carried forward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,362.55 — — —Unrealized foreign exchange in Australia . . . . . . . . . . . . . . . (415.44) — — —Revaluation in value of oil and gas properties according toAustralian law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,375.40) — — —

Others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (652.20) 18.34 (14.78) (3.58)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,449.81) (15,225.22) (11,202.64) (11,669.52)

F-91

Apart from the corporate income tax, there is Petroleum Resource Rent Tax in Australia (PRRT) with thetax rate of 40% calculated under the particular method. The Group recorded current tax and deferred tax arisingfrom PRRT in the current period by applying the same accounting policies regarding the valuation and disclosureas for the corporate income tax. The Group also recognized deferred tax from Augmentation which is the taxbenefit that the Australian Commonwealth Government allows the tax payer to be able to deduct moreexpenditure from the taxable income with the percentage based on investment, resulting in the decrease of thecorporate income tax for the year ended December 31, 2009 for a total of Baht 619 million.

18. Prepaid Expenses

As at December 31, 2009, the major prepaid expenses totaling of Baht 191.63 million are the prepaymentsthat PTTEPI made for the royalties of Yadana and Yetagun projects to the government of the Union of Myanmar.These prepayments will be amortized when the deferred income discussed in Note 23 is recognized.

19. Other Non-current Assets

Other non-current assets as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Costs carried for PetroVietnam in projects:—Vietnam B & 48/95 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35.23 36.90 — ——Vietnam 52/97 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33.67 35.26 — —

Other deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29.72 24.68 24.74 24.13Others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.16 2.58 0.12 0.27

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100.78 99.42 24.86 24.40

20. Short-term Borrowings and Bonds

Short-term borrowings and bonds as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Current LiabilitiesShort-term borrowings

—Bills of exchange . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 999.20 2,985.96 999.20 2,985.96—Other borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 935.76 — — —

Total short-term borrowings . . . . . . . . . . . . . . . . . . . . 1,934.96 2,985.96 999.20 2,985.96

Current portion of bondsCurrent portion of bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,500.00 — 9,500.00 —Less: Deferred issuance expense of bonds . . . . . . . . . . . . . (1.26) — (1.26) —

Current portion of bonds - net . . . . . . . . . . . . . . . . . . . . . . . 9,498.74 — 9,498.74 —

Total current liabilities . . . . . . . . . . . . . . . . . . . . 11,433.70 2,985.96 10,497.94 2,985.96

Non-current LiabilitiesBonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49,000.00 18,500.00 49,000.00 18,500.00Less: Deferred issuance expense of bonds . . . . . . . . . . . . . (48.80) (11.95) (48.80) (11.95)

Total non-current liabilities . . . . . . . . . . . . . . . . . 48,951.20 18,488.05 48,951.20 18,488.05

F-92

Bills of Exchange

The Company launched the “PTTEP Short-term Financing Program” which involved the company’sinaugural issuance of Bills of Exchange (B/Es). The B/Es are to be issued monthly on a revolving basis toinstitutional and high net-worth investors, with a total revolving credit of up to Baht 30,000 million. As atDecember 31, 2009 the outstanding face value of B/Es was Baht 1,000 million with the weighted averagediscounted rate of 1.16%.

Other Borrowings

Other borrowings are secured loans valued in USD with floating loan interest rate at LIBOR+2% perannum.

Bonds

Unsecured and unsubordinated bonds as at December 31, 2009 and 2008 comprised:

Interest rates(% per annum) Maturity dates

Consolidated and theCompany

2009 2008

Maturity date within 1 year—Bonds Baht 3,500 million . . . . . . . . 4.88 February 12, 2010 3,500.00 3,500.00—Bonds Baht 6,000 million1 . . . . . . . 6MFDR + 0.99 June 15, 2010 6,000.00 6,000.00

Maturity date between 1-3 years—Bonds Baht 3,500 million . . . . . . . . 3.91 June 15, 2012 3,500.00 3,500.00—Bonds Baht 18,300 million . . . . . . . 3.25 May 29, 2012 18,300.00 —

Maturity date between 3-5 years—Bonds Baht 5,000 million . . . . . . . . Year 1-2 : 3.00 May 29, 2013 5,000.00 —

Year 3-4 : 4.00 or6-M THB FIX + 1.252

—Bonds Baht 11,700 million . . . . . . . 4.00 May 29, 2014 11,700.00 —Maturity date over 5 years

—Bonds Baht 2,500 million3 . . . . . . . 3.30 March 27, 2018 2,500.00 2,500.00—Bonds Baht 3,000 million NC54 . . . 5.13 June 15, 2022 3,000.00 3,000.00—Bonds Baht 5,000 million . . . . . . . . 4.80 May 29, 2019 5,000.00 —

Total par value of bonds . . . . . . . . . . . . . . . 58,500.00 18,500.00Less: Deferred issuance expense ofbonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . (50.06) (11.95)

Total carrying value . . . . . . . . . . . . . . . . . . . 58,449.94 18,488.05

1 On September 4, 2007, the Company entered into Interest Rate Swap Contract (IRS) for bonds amounting to Baht 6,000 million with afinancial institution to change the interest rate from fixed rate at 3.60% per annum to the floating rate at 6-month Fixed Deposit Rate plus0.99% (6MFDR + 0.99%).

2 Minimum and maximum repayments are 3.25% and 6.00% per annum respectively.3 On September 27, 2005, the Company had a Cross Currency Swap transaction with a bank to swap Baht for USD 60.82 million. Under

this agreement, interest was charged at the rate of 3.85% per annum. On May 2, 2007, the Company swapped the USD with the samebank for Baht 2,500 million. Under this agreement, interest rate was reduced to 3.30% per annum until the expiry date.

4 NC5 (Non Call 5 years): the Company can redeem such bonds in the 5th year or in 2012.

21. Finance Lease Liabilities

Finance lease liabilities are liabilities from using the Floating Production Storage and Offloading (FPSO) ofPTTEP Australasia project. The Group recorded the capital expenditure at the lower of the fair value of the

F-93

leased property or the present value of the minimum lease payments and recorded the liabilities at the leaseobligation value, net of finance charges. The costs of finance lease are approximately USD 425.30 million. TheCompany will make the initial payment for the lease when FPSO is completed and ready for its intended use forpetroleum production from Montara field and will continue for 5 years. However, because of the delays resultingfrom the Montara Incident (as set out in Note 31), the first FPSO lease payment is expected to be in August 2010.The interest rate implicit in the lease is 10.56% per annum. The Group recognized the assets from finance leasesas “Oil and Gas Properties” under the caption “Property, Plant and Equipment” in the balance sheets. Financelease liabilities as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Minimum future payment for finance leasesMaturity date within 1 year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,211.79 — — —Maturity date between 1 – 5 years . . . . . . . . . . . . . . . . . . . . . . . . 13,329.68 — — —

Less: Future finance cost of the finance leases . . . . . . . . . . . . . . . . . . . (3,155.91) — — —

Present value of the finance lease liabilities . . . . . . . . . . . . . . . . . . . . . 11,385.56 — — —

Finance Lease Liabilities—Current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 828.84 — — ——Long-term portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,556.72 — — —

11,385.56 — — —

22. Short-term Provision

Short-term provision as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Provision for decommissioning cost that will be due within 1 year(Note 26) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 661.20 — — —

Provision for Montara Incident (Note 31) . . . . . . . . . . . . . . . . . . . . . . . . 212.22 — — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 873.42 — — —

23. Deferred Income

Deferred income comes from MGTC and TPC receiving advance payments for pipeline transportation fromMOGE and PTTEPI receiving advance payments from PTT for natural gas that PTT did not receive in2000 – 2001 in accordance with the volumes stipulated in the gas sales contract of the Yadana and Yetagunprojects. The deferred income will be recognized by PTTEPI, MGTC and TPC when PTT receives gas in futureyears. Deferred income as at December 31, 2009 and 2008 comprised:

2009 2008

Deferred income for the year 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,343.58 2,307.92Deferred income for the year 2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265.16 226.51

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,608.74 2,534.43

24. Remuneration under Agreement

During the year, the Company paid the deferred remuneration under the Gas Sales Agreement of the Arthitproject to PTT Public Company Limited amounting to USD 24 million. As at December 31, 2009, the Companyis liable to PTT Public Company Limited for a total of USD 8 million recorded under accrued expenses.

F-94

25. Provision for Employee Benefits

The reconciliation details for the present value of the defined benefit plans are as follows:

Consolidated The Company

Present value of the defined benefit plans as at January 1, 2008 . . . . . . . . . . . . . . . . . 1,315.78 1,265.76Current service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123.07 109.06Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73.64 70.88

Present value of the defined benefit plans as at December 31, 2008 . . . . . . . . . . . . . . 1,512.49 1,445.70Current service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129.92 114.65Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.12 80.47

Present value of the defined benefit plan as at December 31, 2009 . . . . . . . . . . . . . . . 1,726.53 1,640.82

The reconciliation details for the liabilities recognized in the balance sheets as at December 31, 2009 and2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Present value of the defined benefit plans . . . . . . . . . . . . . . . . . . . . . . 1,726.53 1,512.49 1,640.82 1,445.70Unrecognized transitional liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . (561.85) (749.14) (536.04) (714.73)

Net liabilities recorded in the balance sheets . . . . . . . . . . . . . . . . . . . 1,164.68 763.35 1,104.78 730.97

Expenses recorded in the income statement for the years ended December 31, 2009 and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Current service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129.92 123.07 114.65 109.06Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.12 73.64 80.47 70.88Transitional liabilities recognized during the year . . . . . . . . . . . . . . . . . . . . . 187.28 187.28 178.69 178.69

Expenses recorded in the income statement . . . . . . . . . . . . . . . . . . . . . . . . . . 401.32 383.99 373.81 358.63

Major Actuarial Assumptions

The Group’s financial assumptions

% per annum

Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.6Inflation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.0Credit interest rate on provident funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.5

The Group’s demographic assumptions

• Mortality assumption: The mortality rate is from Thailand Mortality Ordinary 1997 (TMO97) issuedby the Office of the Insurance Commission. The TMO97 contains the results of the most recentmortality investigation of policyholders in life insurance companies in Thailand. It is reasonable toassume that these rates would be reflective of the mortality experience of the working population inThailand.

• Turnover rate assumption:

Age-related scale % per annum

Prior to age 30 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.5Age 30-39 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5Age 39 thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.0

F-95

The turnover rate above reflects the rate at which employees voluntarily resign from service. It does notinclude death, disability, and early retirement. The calculation for the employee benefits shall then be based onsuch assumptions.

26. Provision for Decommissioning Costs

Provision for decommissioning costs remaining as at December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Provision for decommissioning costs . . . . . . . . . . . . . . . . . . . . . 23,482.30 16,309.66 10,426.55 10,142.13Less Current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (661.20) — — —

Non-current portion of provision for decommissioning costs . . 22,821.10 16,309.66 10,426.55 10,142.13

Subject to future oil prices and the Company’s reserve estimates, current portion of provision fordecommissioning cost amounting to Baht 661.20 million is for Challis field of PTTEP Australasia project whichis expected to remain in production until 2010.

Movements of provisions for decommissioning costs during the year 2009 and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Balance at the beginning of the year . . . . . . . . . . . . . . . . . . . . . . 16,309.66 10,990.90 10,142.13 6,903.10Currency translation differences . . . . . . . . . . . . . . . . . . . . . . . . . 109.55 379.84 (452.75) 243.65Additional provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,063.09 4,938.92 737.17 2,995.38

Balance at the end of the year . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,482.30 16,309.66 10,426.55 10,142.13

27. Share Capital

The Company’s registered capital consists of 3,322 million ordinary shares at Baht 1 per share, or a total ofBaht 3,322 million. On November 10, 2009, the Company registered the change in its issued and fully paid-upcapital to 3,312.56 million ordinary shares at Baht 1 per share, or a total of Baht 3,312.56 million. The details ofthe change in the issued and fully paid-up ordinary shares are as follows:

Unit: Million Shares

Ordinary shares issued and fully paid-upBalance as at January 1, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,297.42Share capital issued and paid-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.66

Balance as at December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,307.08Share capital issued and paid-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.48

Balance as at December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,312.56

F-96

The Company reserves 62 million ordinary shares for employees to purchase in accordance with warrants inthe Employee Stock Ownership Plan or ESOP for 5 continuous years. As at December 31, 2009, the employeeshad exercised the warrants to purchase 52.56 million shares and there were 9.44 million reserved sharesoutstanding. The details are as follows:

Date of warrantsissued

Exercised price(Baht per share)

Exercised rightwarrant per

ordinary share

The number ofallotted shares(million shares)

The number ofreserved shares(million shares)

August 1, 2002* . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.2 1:5 9.78 0.22August 1, 2003* . . . . . . . . . . . . . . . . . . . . . . . . . . . 23.4 1:5 9.72 0.28August 1, 2004* . . . . . . . . . . . . . . . . . . . . . . . . . . . 36.6 1:5 13.61 0.39August 1, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55.6 1:5 12.33 1.67August 1, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91.2 1:5 7.12 6.88

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52.56 9.44

* As at December 31, 2009, the warrants issued on August 1, 2002, 2003 and 2004 had expired. The remaining warrants which cannot beexercised are 0.04, 0.06 and 0.08 million shares respectively.

28. Gain (Loss) on Foreign Currency Translation

Gain (loss) on foreign currency translation for the years ended December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Realized gain (loss) on foreign currency translation . . . . . . . . . . (1,161.36) 495.11 (636.99) 15.00Unrealized gain (loss) on foreign currency translation . . . . . . . . 653.14 (377.12) 458.36 (192.50)

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (508.22) 117.99 (178.63) (177.50)

29. Other Revenues

Other revenues for the years ended December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Income from gas pipeline construction service . . . . . . . . . . . . . . — 1,946.60 — 1,946.60Gain on settlement of derivative financial instrument . . . . . . . . 301.93 — — —Rental revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68.55 61.17 21.49 20.56Others . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 281.36 187.35 82.43 154.54

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 651.84 2,195.12 103.92 2,121.70

30. Petroleum Royalties and Remuneration

Petroleum royalties and remuneration for the years ended December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Petroleum royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,644.32 16,186.42 8,949.90 9,973.54Special remuneration benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . 421.25 1,141.74 — —

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,065.57 17,328.16 8,949.90 9,973.54

F-97

31. Montara Incident in Australia

On August 21, 2009, Montara field’s H1 development well in Timor Sea of the PTTEP Australasia projectexperienced an uncontrolled leakage of oil and gas. The Group immediately implemented its emergency responseprocedure to control the leakage and deal with the leak. On November 1, 2009, during the operation of theleakage control, there was fire at the contractor’s West Atlas drilling rig and at the PTTEP owned wellheadplatform. The leakage and fire was under control and ceased on November 3, 2009. Subsequently on January2010, Montara development H1 well was completely closed out.

With reference to the aforementioned incident, the Group has estimated the overall expenditures. In the thirdquarter of 2009, the Group recorded the expenses, prior to the fire incident, of Baht 5,174 million. And in thefourth quarter of 2009, the Group estimated an additional of Baht 5,253 million in order to reflect long termmonitoring and the fire in November 2009. The latter expenses already included the damaged wellhead platformwrite-off of Baht 3,325 million. Regarding that the incident was covered by insurance and the Group received anagreement from the insurers to make a payment on account (the interim payment) of Baht 1,341 million, theGroup thus recorded the payment in the financial statement in the fourth quarter of 2009, which offset the totalincident expenditures. The net expenditure is deductible in tax calculation.

The current estimation of the total amount to be recovered under the insurance policies is approximatelyUSD 270 million or approximately Baht 9,000 million (including the interim payment of Baht 1,341 million inthe fourth quarter of 2009). However, the actual amount ultimately recoverable under the insurance policies isdependent upon costs actually incurred and the terms and conditions of the policies. The Group is now in theprocess of claiming from the insurers the remaining recoverable amounts.

Summary expenses from Montara Incident for the year ended December 31, 2009 are as follow:

Loss from oil and gas incident and fire incident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,102*Loss from damaged wellhead platform write off . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,325Less Interim payment from the insurer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,341)

Total expenses from Montara Incident . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,086

* As of December 31, 2009, expenses of Baht 212.22 million apart from total incident cost were classified as short-term provision underthe caption of current liabilities.

32. Management’s remuneration

Management’s remuneration for the years ended December 31, 2009 and 2008 comprised:

Consolidated The Company

2009 2008 2009 2008

Director’s remuneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38.38 45.34 38.38 45.34Senior management’s remuneration * . . . . . . . . . . . . . . . . . . . . . . . . . . . 117.70 114.09 117.70 114.09

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156.08 159.43 156.08 159.43

* Exclusive of the remuneration for senior management seconded to PTT.

The Company provided the warrants to purchase ordinary shares (as set out in Note 27) for seniormanagement. As at December 31, 2009, the remaining warrants were 0.14 million shares.

F-98

33. Expenses by Nature

Significant expenses by nature of the Group which comprise the expenses based on its percentage of interestin each project as at December 31, 2009 and 2008, are as follows:

Consolidated The Company

2009 2008 2009 2008

Salary, wages and employees’ benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,017.61 2,407.21 888.18 909.53Repair and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,566.62 881.56 900.79 712.06Exploration well write-off . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,671.14 6,306.83 11.54 49.14Geological and geophysical . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,706.13 1,966.56 180.08 277.60

34. Earnings per Share

Basic earnings per share for the years ended December 31, 2009 and 2008 are calculated as follows:

Consolidated The Company

2009 2008 2009 2008

Net income attributable to shareholders (Million Baht) . . . . . . . 22,153.60 41,674.84 25,052.10 34,361.97Weighted average number of outside ordinary shares in issueduring the year (Million Shares) . . . . . . . . . . . . . . . . . . . . . . . 3,309.08 3,301.73 3,309.08 3,301.73

Basic earnings per share (Baht) . . . . . . . . . . . . . . . . . . . . . . . . . . 6.69 12.62 7.57 10.41

A diluted earnings per share is calculated based on the weighted average number of outside ordinary sharesin issue during the year adjusted with dilutive potential ordinary shares assuming that all dilutive potentialordinary shares are converted into ordinary shares. The Company has dilutive potential ordinary shares as a resultfrom the warrants provided to employees in which the number of dilutive potential ordinary shares is calculatedbased on face value of the warrants (calculated from the weighted average price of the ordinary outstandingshares during the year). This calculation serves to determine the unpurchased shares to be added to the outsideordinary shares to compute the dilution; no adjustment is made to the net income.

Diluted earnings per share for the years ended December 31, 2009 and 2008 are calculated as follows:

Consolidated The Company

2009 2008 2009 2008

Net income attributable to shareholders (Million Baht) . . . . . . . 22,153.60 41,674.84 25,052.10 34,361.97Net income used to determine diluted earnings per share(Million Baht) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,153.60 41,674.84 25,052.10 34,361.97

Weighted average number of outside ordinary shares in issueduring the year (Million Shares) . . . . . . . . . . . . . . . . . . . . . . . 3,309.08 3,301.73 3,309.08 3,301.73

Adjustments for share options (Million Shares) . . . . . . . . . . . . . 2.63 5.65 2.63 5.65

Weighted average number of outside ordinary shares fordiluted earnings per share (Million Shares) . . . . . . . . . . . . . . 3,311.71 3,307.38 3,311.71 3,307.38

Diluted earnings per share (Baht) . . . . . . . . . . . . . . . . . . . . . . . . 6.69 12.60 7.56 10.39

F-99

35.Segm

entInform

ation

Con

solid

ated

fina

ncialstatementsfortheyear

endedDecem

ber31,2009

Exp

loration

andprod

uction

Pipeline

Others

Inter-

compa

nyElim

ination

Group

’stotal

business

Primaryrepo

rting—

business

segm

ents

Tha

iland

Other

South

EastAsia

Australia

MiddleEast

andOthers

SouthEast

Asia

Revenues—

Third

parties

.........................................

9,140.18

3,634.88

2,048.22

576.97

3,762.60

——

19,162.85

—Related

parties........................................

88,619.61

9,755.72

—1,771.95

3,662.42

—(3,662.42)

100,147.28

Other

revenues—Third

parties.....................................

178.06

—303.92

0.28

3.56

341.76

(189.46)

638.12

TotalRevenues.................................................

97,937.85

13,390.60

2,352.14

2,349.20

7,428.58

341.76

(3,851.88)

119,948.25

Operatin

gexpenses

..............................................

8,527.82

4,375.89

2,042.20

528.79

176.90

12.93

(3,738.27)

11,926.26

Adm

inistrativeexpenses

..........................................

2,048.55

739.00

267.59

471.33

46.64

89.21

(35.11)

3,627.21

Exploratio

nexpenses

—Amortizationof

dryholeandproject..........................

58.18

83.13

2,163.85

3,365.98

——

—5,671.14

—Geologicaland

geophysical.................................

404.50

425.13

152.00

724.50

——

—1,706.13

Depreciation,depletionandam

ortization.............................

25,770.34

1,835.57

615.79

1,070.91

242.59

40.71

—29,575.91

Royaltiesandremuneration

.......................................

12,541.96

1,523.62

——

——

—14,065.58

Lossfrom

theMontara

Incident

....................................

——

5,760.83

——

——

5,760.83

Lossfrom

damagewellheadplatform

................................

——

3,325.04

——

——

3,325.04

Foreignexchange

(gain)

loss

......................................

(1,029.69)

(60.67)

965.85

(0.45)

—0.40

—(124.56)

Shareof

(gain)

loss

from

associates

.................................

——

(22.69

)—

—40.55

—17.86

TotalExpenses

.................................................

48,321.66

8,921.67

15,270.46

6,161.06

466.13

183.80

(3,773.38)

75,551.40

Segm

entresult..................................................

49,616.19

4,468.93

(12,918.32

)(3,811.86)

6,962.45

157.96

(78.50)

44,396.85

Depreciation—

general...........................................

(280.09)

Adm

inistrativeexpenses—general..................................

(1,434.71)

Operatin

gprofit.................................................

42,682.05

Other

income,net...............................................

13.72

Financecosts—

Interestincome

....................................

376.27

—Interestexpenses

andotherfinancecosts................

(1,870.33)

Losson

foreignexchange

.........................................

(632.79)

Managem

ent’sremuneration.......................................

(156.08)

Incomebefore

tax...............................................

40,412.84

Tax—Project...................................................

(20,941.36)

(1,305.51)

4,957.40

(56.28)

(2,072.96)

(30.81)

(19,449.52)

—Group

........................

...........................

1,190.28

NetIncome(Loss)...............................................

28,674.83

3,163.42

(7,960.92)

(3,868.14)

4,889.49

127.15

22,153.60

Assets

Segm

entassets

.................................................

160,578.61

28,491.46

48,183.92

9,833.72

4,668.86

2,351.24

—254,107.81

Investmentsunderequity

method...................................

——

78.52

——

843.79

—922.31

Unallo

catedassets

...............................................

45,680.49

Con

solid

ated

totalassets..........................................

300,710.61

Liabilities

Segm

entliabilities...............................................

65,815.04

4,587.20

24,344.90

2,362.62

1,651.97

524.18

—99,285.91

Unallo

catedliabilities............................................

58,423.93

Con

solid

ated

totalliabilities.......................................

157,709.84

CapitalE

xpenditures.............................................

36,300.39

3,066.92

37,813.47

3,526.49

(305.95)

551.55

80,952.87

F-100

Con

solid

ated

fina

ncialstatementsfortheyear

endedDecem

ber31,2008

Exp

loration

andprod

uction

Pipeline

Others

Inter-

compa

nyElim

ination

Group

’stotal

business

Tha

iland

Other

South

EastAsia

Australia

MiddleEast

andOthers

SouthEast

Asia

Revenues—

Third

parties..............

............................

13,316.04

3,045.42

—485.33

4,131.14

——

20,977.93

—Related

parties

........................................

102,006.72

10,276.78

—3,490.38

3,753.71

—(3,753.71)

115,773.88

Other

revenues—Third

parties......................................

108.02

——

——

262.68

(169.89)

200.81

—Related

parties

....................................

——

——

—1,946.60

—1,946.60

TotalRevenues......................

............................

115,430.78

13,322.20

—3,975.71

7,884.85

2,209.28

(3,923.60)

138,899.22

Operatin

gexpenses

..................

............................

7,331.63

4,492.79

—540.36

211.74

1,844.20

(3,892.19)

10,528.53

Adm

inistrativeexpenses

...........................................

2,088.22

625.30

66.02

345.54

38.05

138.08

(96.47)

3,204.74

Exploratio

nexpenses

—Amortizationof

dryholeandproject...........................

334.84

5,549.91

—422.08

——

—6,306.83

—Geologicaland

geophysical..................................

683.13

530.16

270.90

482.37

——

—1,966.56

Depreciation,depletionandam

ortization

.............................

20,615.28

1,293.43

0.36

809.30

242.04

38.51

—22,998.92

Royaltiesandremuneration

........................................

15,684.69

1,643.47

——

——

—17,328.16

Derivativeloss

onhedging.........................................

904.49

——

——

——

904.49

Foreignexchange

(gain)

loss

.......................................

469.56

(48.30)

(1.88)

11.48

—(3.61)

—427.25

Shareof

loss

from

associates

.......................................

——

——

—12.40

—12.40

TotalExpenses......................

............................

48,111.84

14,086.76

335.40

2,611.13

491.83

2,029.58

(3,988.66)

63,677.88

Segm

entresult......................

............................

67,318.94

(764.56)

(335.40)

1,364.58

7,393.02

179.70

65.06

75,221.34

Depreciation—

general................

............................

(286.80)

Adm

inistrativeexpenses—general...................................

(1,292.40)

Operatin

gprofit

....................

.............................

73,642.14

Other

income,net................................................

47.70

Financecosts—

Interestincome.....................................

942.23

—Interestexpenses

andotherfinancecosts.................

(840.82)

Gainon

foreignexchange

.........................................

545.25

Director’sremuneration...........................................

(159.43)

Incomebefore

tax....................

............................

74,177.07

Tax—Project...................................................

(29,347.12)

(1,605.62)

——

(2,207.48)

(70.36)

(33,230.58)

—Group

....................................................

728.35

NetIncome(Loss)

..................

.............................

37,971.82

(2,370.18)

(335.40)

1,364.58

5,185.54

109.34

41,674.84

Assets

Segm

entassets......................

............................

148,049.69

28,086.28

668.04

10,440.73

5,425.10

2,634.65

—195,304.49

Investmentsunderequity

method........

............................

——

——

—384.34

—384.34

Unallo

catedassets

...............................................

42,566.59

Con

solid

ated

totalassets

..............

............................

238,255.42

Liabilities

Segm

entliabilities

..................

.............................

73,610.74

4,936.25

697.70

1,644.11

1,729.25

880.86

—83,498.91

Unallo

catedliabilities.............................................

20,652.68

Con

solid

ated

totalliabilities............

............................

104,151.59

CapitalE

xpenditures

................

.............................

40,807.91

17,497.28

665.39

4,961.71

244.85

292.07

—64,469.21

F-101

The Group is organized into the following business segments:

• Exploration and production: The Group operates in oil and gas exploration and production bothdomestically and overseas, either as an operator or as a joint venture partner with international oil andgas companies. Most domestic projects are located in the Gulf of Thailand. Overseas projects arelocated in Southeast Asia, the Middle East, North Africa, and Australia. As at the balance sheet date,the Group had 18 projects in the production phase and 23 projects in the development and explorationphases.

• Overseas pipelines: The Group has investments with its joint venture partners to operate pipelines totransport natural gas from the exploration and production projects where the Group has workinginterests i.e., the Yadana and Yetagun projects.

• Others: The Group’s other operations consist mainly of investments in projects strategically connectedto the energy business, which does not constitute a separately reportable segment.

Secondary reporting—geographical segments

The Group’s two main business segments are managed on a worldwide basis. They are operated in fourmain geographical areas:

Consolidated financial statements for the year ended December 31, 2009

ThailandOther Southeast

Asia AustraliaMiddle Eastand others Group

Revenues—Third parties . . . . . . . . . . . . . . . 9,140.18 7,397.48 2,048.22 576.97 19,162.85—Related parties . . . . . . . . . . . . . 88,619.61 9,755.72 — 1,771.95 100,147.28

Segment assets . . . . . . . . . . . . . . . . . . . . . . . 162,929.85 33,160.32 48,183.92 9,833.72 254,107.81Investments under equity method . . . . . . . . 843.79 — 78.52 — 922.31Capital expenditures . . . . . . . . . . . . . . . . . . . 36,851.94 2,760.97 37,813.47 3,526.49 80,952.87Consolidated total assets . . . . . . . . . . . . . . . 209,454.13 33,160.32 48,262.44 9,833.72 300,710.61

Consolidated financial statements for the year ended December 31, 2008

ThailandOther Southeast

Asia AustraliaMiddle Eastand others Group

Revenues—Third parties . . . . . . . . . . . . . . . . . 13,316.04 7,176.56 — 485.33 20,977.93—Related parties . . . . . . . . . . . . . . . 102,006.72 10,276.78 — 3,490.38 115,773.88

Segment assets . . . . . . . . . . . . . . . . . . . . . . . . . 150,684.34 33,511.38 668.04 10,440.73 195,304.49Investments under equity method . . . . . . . . . . 384.34 — — — 384.34Capital expenditures . . . . . . . . . . . . . . . . . . . . 41,099.98 17,742.13 665.39 4,961.71 64,469.21Consolidated total assets . . . . . . . . . . . . . . . . . 193,635.27 33,511.38 668.04 10,440.73 238,255.42

36. Disclosure of Financial Instruments

Risk Management

The Group’s business and operations cause it to be exposed to the following key risks:

Market Risk

Market risk is the situation whereby changes in commodities prices, interest rates, and foreign exchangerates may positively or adversely impact the Group’s revenues, cash flows, assets, and liabilities.

Financial derivatives of various kinds are employed for the purpose of managing risk exposure tomovements in prices of commodities, interest rates and foreign exchange rates.

F-102

• Price Risk

The Group’s product prices vary with those of world oil prices, which are subject to factors beyond itscontrol, for instance, market demand and supply, political and economic stability of various countries,OPEC’s production policy, oil reserves, and the change in the global climate in each season. Fluctuations inworld oil prices affect the Group’s revenue and investment planning.

Regarding the aforementioned factors, when the world oil prices change, so do the prices of theGroup’s crude oil and condensate. However, because of built-in natural gas pricing mechanisms found in theGas Sale Agreement (GSA) which cushion natural gas prices from oil price volatility (Natural Hedge), whenthe reference oil prices change, the typical prices of natural gas—the Group’s main product—do change inthe same direction. Most of the Group’s contractual natural gas prices are adjusted every 6 or 12 monthsdepending on the gas price formula of each project and should this price rise or fall, the natural gas pricewill move correspondingly to a certain degree comparing to the prices of crude oil and condensate.

The Group has realized that price has an impact on its revenues and profits; therefore, the riskmitigation plan is annually considered by the Risk Management Committee and the Board of Directors priorto execution. To mitigate existing price risks, the Group employs the use of options contracts, subject toendorsement by the Board of Directors prior to execution.

In 2009, the world oil price was volatile, having climbed up from USD 41 per barrel, at the beginningof the year, to USD 78 per barrel, at the end of the year.

• Interest Rate Risk

The majority of the Group’s debt is subject to fixed interest rates. However, to capture the benefits offalling interest rates in the future, the Group has converted an interest rate swap of Baht 6,000 million indebts to the 6-month fixed deposit Thai Baht rate plus an agreed spread, reflecting the Group’s aim tominimize funding cost whilst managing risk in tandem.

Furthermore, the Group’s short-term commercial papers (Bills of Exchange), featuring tenors ofapproximately one month, are subject to pricing based upon the latest comparable yield on Thai governmenttreasuries.

• Foreign Currency Risk

Although the vast majority of the Group’s domestic and international business (revenues and expenses)are tied to the USD, the Group’s functional currency remains in Thai Baht. Therefore, foreign exchange riskarises when transactions are denominated in a currency other than the functional currency. Foreign exchangegains and losses are presented in Note 28.

The Group is aware of the risks surrounding assets and liabilities denominated in foreign currencies, asa result, the Group has a policy of asset and liability management by which the structure and features oftransactions regarding assets, liabilities and shareholders’ equity are aligned with each other.

Credit Risk

The Group seeks to ensure that sales of products are made to the customers with acceptable credit profiles,with the overwhelming majority of sales being made to PTT Public Company Limited, the PTTEP’s parentcompany. The credit risks are carefully assessed and regularly reviewed.

F-103

Liquidity Risk

Liquidity risk is the risk that arises from the unavailability of viable sources of funding for the Group’sbusiness activities. Future liabilities and interest expenses, excluding the liabilities from finance leases, as atDecember 31, 2009 are as follows:

Maturity Date

2010

2011 20122013

onwards TotalRevolving 3 Months 6 Months 12 Months

Baht bond at fixed interest ratePrincipal . . . . . . . . . . . . . . . . . . . . . . . — 3,500 6,000 — — 21,800 27,200 58,500Interest expenses . . . . . . . . . . . . . . . . . — 408 708 936 1,884 1,546 4,457 9,939

Baht bill of exchange at floatinginterest ratePrincipal . . . . . . . . . . . . . . . . . . . . . . . 1,000 — — — — — — 1,000

Total principal and interest expenses . . . . . 1,000 3,908 6,708 936 1,884 23,346 31,657 69,439

The major assumption for the data presented above is that all the interest expenses are calculated based onthe contractual interest rate. The floating interest rate is stable and the principal stays unchanged until it is repaidat the maturity date.

With the use of the estimation for cash and the need of foreign currencies based on the information at theCentral Risk Management which are regularly provided by various entities, the Group can manage the liquidityrisk. Moreover, the Group has various financing channels in both domestic and international market to reduce theliquidity risk.

The Group operates a Short-Term Financing Program with access to Thailand’s capital market via acommercial paper program, exclusive of Baht 3,090 million in committed credit facilities. Such facilities areavailable subject to advanced notification to banks for a period of at least 3 business days, based upon apre-agreed benchmark rate. Of the total, Baht 3,000 million is subject to annual review, while Baht 90 million isprovided on a revolving basis.

Outstanding principal amounts and undrawn facilities are summarized below:

Credit Limit Undrawn Amounts

Short-Term Commercial Papers* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,000 29,000Committed Bank Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,090 3,090

* Short-term commercial papers mainly comprise Bills of Exchange (B/Es).

The Group’s Receivables Purchase Financing Facility has been launched for the purpose of convertingcredit terms to immediate cash to ensure flexible working capital.

The company’s long-term debt ratings as assigned by prominent credit rating agencies are as follows:

2009 2008

Foreign Currency Domestic Currency Foreign Currency Domestic Currency

Rating AgencyMoody’s . . . . . . . . . . . . . . . . . . . . A3 A2 A3 A2Standard and Poor’s . . . . . . . . . . . BBB+ BBB+ BBB+ BBB+Japan Credit Rating . . . . . . . . . . . . A- A+ A- A+TRIS Rating . . . . . . . . . . . . . . . . . — AAA — AAA

F-104

Fair Value of Financial Instruments

Since the majority of the financial assets are short-term and the loans carry interest at rates close to currentmarket rates, the management believe that the fair value of the Company’s financial assets does not materiallydiffer from its carrying value.

The Group calculated the fair value of long-term liabilities using the discounted cash flow based on adiscounted rate of borrowing with similar terms, while the cross currency interest and principal swaps were basedon the quoted market rate. A comparison of the carrying value and fair value of these instruments is as follows:

As at December 31, 2009

Carrying amount Fair value

Baht 2,500 million of unsecured and unsubordinated bonds . . . . . . . . . . . . . . . . . . . 2,500.00 2,438.39Baht 3,500 million of unsecured and unsubordinated bonds . . . . . . . . . . . . . . . . . . . 3,500.00 3,580.39Baht 12,500 million of unsecured and unsubordinated bonds

—Tranche 1, Baht 6,000 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,000.00 6,065.40—Tranche 2, Baht 3,500 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,500.00 3,589.13—Tranche 3, Baht 3,000 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,000.00 3,018.60

Baht 40,000 million of unsecured and unsubordinated bonds—Tranche 1, Baht 18,300 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,300.00 18,514.85—Tranche 2, Baht 5,000 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,000.00 5,006.78—Tranche 3, Baht 11,700 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,700.00 11,789.68—Tranche 4, Baht 5,000 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,000.00 4,825.60

Interest rate swap for Baht 2,500 million bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 243.66Interest rate swap for Baht 6,000 million bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 56.97

37. Dividends

On March 31, 2009, the annual general meeting of the shareholders approved payment of a dividend for theyear 2008 of Baht 5.42 per share. The Company made an interim dividend payment for the first half-yearoperations of 2008 at the rate of Baht 2.86 per share on August 29, 2008 and for the second half-year operationsof 2008 at the rate of Baht 2.56 per share on April 10, 2009.

The Company has estimated the dividend to its shareholders for the year 2009 as Baht 2.68 per share. TheCompany made an interim dividend payment for the first half-year operations of 2009 at the rate of Baht 1.48 pershare on August 28, 2009 and still has to pay the dividend for the second half-year operations of 2009 at the rateof Baht 1.20 per share. This dividend will be paid upon approval by the annual general meeting of theshareholders.

38. Commitment and Contingent Liabilities

• Commitment for the operating leases—the Group as a lessee

The future minimum lease payments for the non-cancellable operating leases as at December 31, 2009and 2008 are as follows:

Consolidated The Company

2009 2008 2009 2008

Within 1 year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,288.64 2,575.98 3,574.71 2,163.51Between 1 – 5 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,050.46 8,125.68 3,616.65 7,663.51Over 5 years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,434.34 23.44 10.95 22.02

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,773.44 10,725.10 7,202.31 9,849.04

F-105

• Commitment from loan agreements

As at December 31, 2009, the Company had an unsubordinated loan agreement with the EnergyComplex Company Limited (EnCo), with the loan limit of Baht 1,250 million. The agreement shall continuefor 13 years and 6 months effective from April 2, 2009. The total of loans provided by the Company as atDecember 31, 2009 was Baht 490 million.

• Obligation under Gas Sale Agreement

According to Gas Sales Agreement of MTJDA Block B-17 and B-17-01, if the sellers fail to deliver thequantity of natural gas notified by the buyer on the date agreed upon, the buyer has the right to take thedeficient quantity of natural gas (Shortfall) at a price equal to 75% of the current price applicable at the timethe Shortfall occurred. PTT, the buyer, has nominated quantities of natural gas since late December 2009.However, PTTEPI and joint venture partner, the seller, cannot deliver the natural gas nominated by PTTsince the gas production start-up is expected to occur in the first quarter of 2010. Therefore, PTTEPI andjoint venture partner have an obligation for price reduction on such Shortfall. Currently, PTTEPI and itsjoint venture partner are in process of negotiating with the buyer.

• Contingent liabilities

As at December 31, 2009, the Company had contingent liabilities in the form of letters of guaranteeamounting to Baht 1,072.66 million in the Company’s financial statements and Baht 2,328.63 million in theconsolidated financial statements.

The construction contract for the Montara FPSO contains an interest penalty clause if the contract iscancelled before completion. The penalty amount is approximately Baht 3,590 million.

With reference to the accident in Montara, the Group cancelled a partial construction contract whichmay lead to an obligation to pay the additional costs of approximately Baht 956 million. However, it isbeing negotiated with the contractual party.

39. Significant Events during the period

On January 14, 2009, PTTEPM holding a 40% participation interest in the Indonesia Merangin-1 projectentered into the Farmout Agreement with joint partners to withdraw all its participation in such project.Subsequently, the withdrawal process was officially approved by Indonesian Government authorities(BPMIGAS) on June 24, 2009.

On February 25, 2009, the contract to swap a 20% participation interest of PTTEPI in the ProductionSharing Contract (PSC) in blocks M3 and M4 with CNOOC Myanmar Limited’s A4 and C1 has expired beforereceiving an approval from the Myanmar Government, as a result, the contract consequently became invalid andPTTEPI then maintained its holding of 100% participation interest in blocks M3 and M4.

On March 14, 2009, PTTEPBD decided to withdraw its 30% participation interest in Bangladesh 17 & 18projects in Bangladesh due to an ending of an exploration period under the Production Sharing Contract.

On March 27, 2009, the Board of Directors of the Company approved for the share capital increase to EnCobased on proportionate consolidation with the amount limited to Baht 500 million.

On July 24, 2009, the Thai Government approved PTTEPT to become a partner of the G4/48 project withthe participation interest of 5%.

On July 27, 2009, the Thai Government approved PTTEPS to transfer 40% of its participation interest inB6/27 project (The former name: Nang Nuan project) to Nippon Oil Exploration Limited (NOEX). Currently,PTTEPS has 60% participation interest in the aforementioned project.

F-106

On September 22, 2009, the Council of Ministers approved PTTEPT to transfer 4% of the participationinterest in Arthit project (Block G9/48) to Mitsui Oil Exploration Co., Ltd. On November 18, 2009, the Ministerof Energy approved for the addition to the petroleum concession. PTTEPT then had 80% participation interest insuch project.

On December 25, 2009, the Board of Directors of PTT Exploration and Production Public CompanyLimited passed the resolution to approve the ownership on the PTTEP head office building, at 555 PTTEP OfficeBuilding Vibhavadi-Rangsit Road, Chatuchak, Bangkok 10900, to PTT Public Company Limited in accordancewith contract condition. PTTEP is in process to comply with the Board of Directors’ resolution.

40. Reclassification

The financial statements for the period 2008 were reclassified for the comparison purpose to conform withthe changes in the presentation of the financial statements for the fiscal period in which the income statement forthe year ended 2009 presents management’s remuneration and finance costs and to align with the requirement ofminimum line items in the financial statements B.E. 2552 announced by the Department of BusinessDevelopment which was effective on or after January 1, 2009.

41. Events after the Balance Sheet Date

On January 14, 2010, the Group established PTTEP Southwest Vietnam Pipeline Company Limited with aregistered capital of USD 50,000, consisting of 50,000 ordinary shares at USD 1 each, and with 100%shareholding by PTTEPH.

On January 17, 2010, the Company signed the Petroleum Contract in block Hassi Bir Rekaiz in Algeria. Thejoint venture partners consist of PTTEP (the operator), CNOOC International Limited (CNOOC) and Sonatrachwith the participation interests of 24.50%, 24.50%, and 51.00% respectively. However, the Contract will beeffective upon announcement in the Gazette of Algeria. PTTEP AG and CNOOC joined the Algeria 2009 BidRound with the portion of 50:50 and have been selected as the successful bidder of the block Hassi Bir Rekaiz inDecember 2009.

The Board of Directors of the Company authorized for the issue of these financial statements onFebruary 17, 2010.

F-107

STATOIL CANADA PARTNERSHIP

AUDITED FINANCIAL STATEMENTS

DECEMBER 31, 2010

F-108

INDEPENDENT AUDITORS’ REPORT

To the Managing Partner of Statoil Canada Partnership

We have audited the accompanying financial statements of Statoil Canada Partnership (the “Partnership”), which comprise the statement of financial position as at 31 December 2010 and the statements of loss and comprehensive loss, cash flows and changes in partners’ equity for the year then ended, and a summary of significant accounting policies and other explanatory information.

Management's responsibility for the financial statements

Management of Statoil Canada Ltd. is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as at 31 December 2010 and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards.

Comparative Information

Without modifying our opinion, we draw attention to Note 2 to the financial statements which describes that the Partnership adopted International Financial Reporting Standards on January 1, 2009 with a transition date of January 1, 2009. We were not engaged to report on the restated comparative information, and as such, it is unaudited.

Calgary, Canada 11 March 2011 Chartered Accountants

F-109

Statoil Canada PartnershipStatement of Financial Position

At December 31 At December 31 At January 1(thousands of Canadian dollars) Notes 2010 2009 2009

(unaudited) (unaudited)

ASSETS

Property, plant and equipment 5 1,623,213$ 1,243,575$ 457,092$Exploration and evaluation assets 6 2,016,012 1,978,584 2,130,799

Total non-current assets 3,639,225 3,222,159 2,587,891

Inventories 7 11,582 - -Trade and other receivables 8 2,348 5,277 2,075Receivables from related companies 13 2,323 166 568Prepaid expenses 1,219 236 362Cash and cash equivalents 9 112,631 329 8,617

Total current assets 130,103 6,008 11,622

TOTAL ASSETS 3,769,328$ 3,228,167$ 2,599,513$

PARTNERS' EQUITY AND LIABILITIES

Partnership units 10 4,064,894$ 1,950,045$ 1,950,045$Deficit (404,001) (225,922) (133,197)

Total equity 3,660,893 1,724,123 1,816,848

Asset retirement obligations 12 16,499 10,183 5,924Total non-current liabilities 16,499 10,183 5,924

Trade and other payables 11 54,555 76,105 103,752Payables to related companies 13 37,381 1,417,756 672,989

Total current liabilities 91,936 1,493,861 776,741

Total liabilities 108,435 1,504,044 782,665

TOTAL PARTNERS' EQUITY AND LIABILITIES 3,769,328$ 3,228,167$ 2,599,513$

See the accompanying notes to these financial statements.

On behalf of the Managing Partner:

F-110

Statoil Canada PartnershipStatement of Loss and Comprehensive LossFor the year ended December 31

(thousands of Canadian dollars) Notes 2010 2009(unaudited)

Revenues and other incomeRevenue from crude oil sales 5,223$ -$Other sales 412 341Gain on sale of assets 5 18,908 -

Total revenues and other income 24,543 341

Operating expensesPurchases (3,383) (32)Operating expenses (41,618) (9,748)Selling, general and administrative expenses (26,674) (375)Depreciation and amortization 5 (2,907) (2,167)Exploration expenses (101,320) (75,389)

Total operating expenses (175,902) (87,711)

Net operating loss (151,359) (87,370)

Financial ItemsNet foreign exchange gains 1,577 5,318Interest income and other financial items 20 18Interest and other finance expenses (28,317) (10,691)

Net financial items (26,720) (5,355)

Total loss and comprehensive loss (178,079)$ (92,725)$

See the accompanying notes to these financial statements.

F-111

Statoil Canada PartnershipStatement of Cash FlowsFor the year ended December 31

(thousands of Canadian dollars) Notes 2010 2009(unaudited)

OPERATING ACTIVITIESNet loss (178,079)$ (92,725)$

Adjustments to reconcile net loss to net cash flowsprovided by operating activities:

Depreciation and amortization 2,907 2,167Exploration expenditures written off 6 2,351 -Gain on sale of assets and other items 5 (18,908) -Accretion 12 528 376Capitalized interest 5 (15,558) (14,070)

Changes in non-cash operating working capital: 14 (1,413,718) 714,446

Cash flows (used in) provided by operating activities (1,620,477) 610,194

INVESTING ACTIVITIESAdditions to property, plant and equipment (382,491) (604,558)Exploration expenditures capitalized 6 (39,779) (13,924)

Cash flows used in investing activities (422,270) (618,482)

FINANCING ACTIVITIESProceeds from issuance of partnership units 10 2,155,049 -

Cash flows provided by financing activities 2,155,049 -

Net increase (decrease) in cash and cash equivalents 112,302 (8,288)

Cash and cash equivalents, beginning of year 9 329 8,617

Cash and cash equivalents, end of year 9 112,631$ 329$

See the accompanying notes to these financial statements.

F-112

Statoil Canada PartnershipStatement of Changes in Partners' EquityFor the year ended December 31

(thousands of Canadian dollars) Notes

Number ofunits issued

PartnershipUnits Deficit

Balance at January 1, 2009 (unaudited) 1,000,000 1,950,045$ (133,197)$

Net loss for the year (unaudited) - - (92,725)

Balance at December 31, 2009 1,000,000 1,950,045 (225,922)

Net loss for the year - - (178,079)

Issuance of partnership units 10 580,835 2,155,049 -

Cancellation of partnership units 10 (10,835) (40,200) -

Balance at December 31, 2010 1,570,000 4,064,894$ (404,001)$

See the accompanying notes to these financial statements.

F-113

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

1 ORGANIZATION

Statoil Canada Partnership (“the Partnership”) was created on February 4, 2005 in Alberta, Canada, as ageneral partnership between North American Oil Sands Corporation (“NAOSC”) and ParamountResources under the name 68-475 Alberta Oil Sands Partnership. The Partnership name was changed toNorth American Oil Sands Partnership on October 23, 2006, to StatoilHydro Canada Partnership on December 31, 2007, and to Statoil Canada Partnership on November 1, 2009. In June 2007, Statoil ASA(“Statoil”) became the ultimate parent company of the Partnership through the acquisition of all of theshares of NAOSC.

Statoil is listed on the Oslo Stock Exchange (Norway) and the New York Stock Exchange (USA).

Statoil Canada Ltd. and Statoil Canada Holdings Corp. are the partners of the Partnership, with StatoilCanada Ltd. holding a 99.8892% partnership interest (the “Managing Partner”) and Statoil CanadaHoldings Corp. holding a 0.1108% partnership interest. The Partnership’s address of registered office is:2100, 635 8th Ave SW, Calgary, Alberta, Canada. The financial statements of the Partnership for the yearended December 31, 2010 were authorized for issue by an officer of the Managing Partner on March 11,2011.

The Partnership’s business principally consists of the exploration and production of crude oil with a focuson developing the Partnership’s oil sands interests in Alberta, Canada. The Partnership has notgenerated substantial revenues and has not generated any cash flows from operations to fund itsacquisition, exploration and development activities. Accordingly, the Partnership relies upon the fundingfrom the partners to finance its oil and gas properties acquisitions, exploration and development.

2 SIGNIFICANT ACCOUNTING POLICIES

Statement of compliance

The financial statements of the Partnership have been prepared in accordance with InternationalFinancial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”)and interpretations issued by the International Financial Reporting Interpretations Committee.

These financial statements are the Partnership’s first IFRS financial statements for the purposes of IFRS1, First Time Adoption of International Financial Reporting Standards (“IFRS 1”). However, thePartnership has been reporting under IFRS to its Managing Partner since Statoil’s 2007 acquisition of the Partnership. Accordingly, there are no adjustments to reconcile the Partnership’s opening IFRS balancesheet to a previous application of accounting principles.

IFRS 1 provides for certain mandatory exceptions and optional exemptions for first time adopters of IFRS.The Partnership has elected to take an optional exemption allowing a first time adopter to record thedeemed cost of certain property, plant and equipment and exploration and evaluation assets at the dateof transition to IFRS at the transaction-based estimated fair value of property, plant and equipment and expected oil and gas reserves.

Basis of preparation

The financial statements are prepared on the historical cost basis with some exceptions, as detailed inthe accounting policies set out below. These policies have been applied consistently to all periodspresented in these financial statements. The financial statements’ functional and presentation currency isCanadian dollars and all values are rounded to the nearest thousand (thousands of Canadian dollars)except when otherwise indicated.

F-114

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Standards issued but not yet effective

Standards issued but not yet effective up to the date of issuance of the Partnership’s financial statementsare listed below. This listing is of standards and interpretations issued, which the Partnership reasonablyexpects to be applicable at a future date. The Partnership intends to adopt these standards when theybecome effective.

IAS 24 Related Party Disclosures (Amendment)The amended standard is effective for annual periods beginning on or after January 1, 2011. It clarifiedthe definition of a related party to simplify the identification of such relationships and to eliminateinconsistencies in its application. The Partnership does not expect any impact on its financial position orperformance.

IFRS 9 Financial Instruments: Classification and MeasurementThis standard covers the classification and measurement of financial assets and will be effective fromJanuary 1, 2013. IFRS 9 also entails amendments to various other IFRSs effective from the same date.The Partnership has not yet determined its adoption date for this standard and is still evaluating thepotential impact of this standard.

Revenue recognition

Revenues associated with sale and transportation of crude oil, natural gas, petroleum and chemicalproducts and other merchandise are recognized when title and risk pass to the customer, which isnormally at the point of delivery of the goods based on the contractual terms of the agreements.

Revenue is presented net of customs, excise taxes and royalties paid in-kind on petroleum products.

Oil and gas exploration and development expenditure

The Partnership uses the "successful efforts" method of accounting for oil and gas exploration costs.Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells(including the exploratory wells to delineate the resource play) are capitalized as exploration andevaluation assets until the wells are complete and the results have been evaluated. If, followingevaluation, the exploration drilling costs have not found sufficient quantities of proved reserves to justifycommercial production of bitumen, the previously capitalized costs are evaluated for de-recognition ortested for impairment. Geological and geophysical costs and other exploration expenditures areexpensed as incurred.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest thatthe carrying amount of the asset may exceed its recoverable amount, and at least once a year. Impairment and reversals of impairment of exploration and evaluation assets are charged toexploration expenses in the statement of loss.

Capitalized exploration and evaluation expenditures, including expenditures to acquire mineral interests inoil and gas properties, related to wells that find sufficient quantities of proved reserves to justifycommercial production of bitumen, are transferred from exploration and evaluation assets to property,plant and equipment at the time of sanctioning of the development project.

Property, plant and equipment

Property, plant and equipment is stated at cost, less accumulated depreciation and accumulatedimpairment losses. The initial cost of an asset comprises its purchase price or construction cost, anycosts directly attributable to bringing the asset into operation, the initial estimate of an asset retirementobligation, if any, and, for qualifying assets, borrowing costs.

F-115

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts ofassets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it isprobable that future economic benefits associated with the item will flow to the Partnership, theexpenditure is capitalized. Inspection and overhaul costs associated with major maintenance programsare capitalized and amortized over the period to the next inspection. All other maintenance costs areexpensed as incurred.

Exploration and evaluation assets that are transferred to property, plant and equipment, developmentexpenditure on the construction, installation or completion of infrastructure facilities such as the centralprocessing facility, pipelines and the drilling of development wells, and field-dedicated transport systemsfor oil and gas are capitalized as producing oil and gas properties within property, plant and equipmentand are depreciated using the unit of production method based on proved developed reserves expectedto be recovered from the area during the concession or contract period. Capitalized acquisition costs ofproved properties are depreciated using the unit of production method based on total proved reserves.Depreciation of other assets and transport systems used by several fields is calculated on the basis oftheir estimated useful lives, normally using the straight-line method. Each part of an item of property,plant and equipment with a cost that is significant in relation to the total cost of the item is depreciatedseparately.

The useful lives of the assets are estimated as follows:

Machinery and equipment 3 to 7 years straight-lineProduction plants Unit of productionBuildings 40 years straight-line

The estimated useful lives of property, plant and equipment are reviewed on an annual basis andchanges in useful lives are accounted for prospectively. An item of property, plant and equipment isderecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on de-recognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in otherincome or operating expenses, respectively, in the period the item is derecognized.

Exploration and evaluation assets

Exploration and evaluation assets are stated at cost, less accumulated impairment losses. Expensesrelated to the drilling of exploration wells to delineate the resource play are initially capitalized asexploration and evaluation assets pending determination of whether potentially economic oil and gasreserves have been discovered by the drilling effort. Exploration wells that discover potentially economicquantities of oil and gas remain capitalized as exploration and evaluation assets during the evaluationphase of the find.

Exploration and evaluation assets are not amortized. Such assets are subject to impairment testing whenfacts and circumstances suggest that the carrying amount of an asset may exceed its recoverableamount (or at least on an annual basis), and are reclassified to property, plant and equipment when thedecision to develop a particular area is made.

Financial assets

Financial assets are initially recognized at fair value when the Partnership becomes a party to thecontractual provisions of the asset. For additional information on fair value methods, refer to the"Measurement of fair values" section below. The subsequent measurement of the financial assetsdepends on which category they have been classified into at inception.

F-116

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

At initial recognition the Partnership classifies its financial assets into the following three main categories;financial instruments at fair value through profit or loss; loans and receivables; and available-for-sale(“AFS”) financial assets. The first main category, financial instruments at fair value through profit or loss,further consists of two sub-categories; financial assets held for trading and financial assets that on initialrecognition are designated as fair value through profit and loss. The latter may also be referred to as the"fair value option".

Financial assets classified in the loans and receivables category are carried at amortized cost using theeffective interest method. Gains and losses are recognized in the statement of loss when the loans andreceivables are derecognized or impaired, as well as through the amortization process. Trade and otherreceivables are carried at the original invoice amount, less a provision for doubtful receivables, which ismade when there is objective evidence that the Partnership will be unable to recover the balances in full.

Current financial investments are initially recognized in the financial instruments category at fair valuethrough profit or loss, either as held for trading or through the Partnership’s application of the fair valueoption. Following from that classification the current financial investments are carried in the statement offinancial position at fair value with changes in their fair values recognized in the statement of loss.

Financial assets are presented as current if they contractually will expire or otherwise are expected to berecovered within 12 months after the statement of financial position date, or if they are derivative financialinstruments held for the purpose of being traded. Other financial assets expected to be recovered morethan 12 months after the statement of financial position date and for which there is no plan of realizationare classified as non-current.

Financial assets are derecognized when the contractual rights to the cash flows expire or substantially allrisks and rewards related to the ownership of the financial asset are transferred to a third party.

Financial assets and financial liabilities are shown separately in the statement of financial position unlessthe Partnership has both a legal right and a demonstrable intention to net settle certain balances payableto and receivable from the same counterparty, in which case they are shown net in the statement offinancial position.

Borrowing costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets,which are assets that necessarily take a substantial period of time to get ready for their intended use orsale, are added to the cost of those assets, until such time as the assets are substantially ready for theirintended use or sale. Where funds are borrowed specifically to finance a project, the amount capitalizedrepresents the actual borrowing costs incurred.

Where the funds used to finance a project form part of general borrowings, the amount capitalized iscalculated using a weighted average of rates applicable to relevant general borrowings of the Partnershipduring the period. All other borrowing costs are recognized in the statement of loss in the period in whichthey are incurred.

Foreign currency translation

In preparing the financial statements, transactions in foreign currencies (those other than functionalcurrency) are translated at the foreign exchange rate at the date of the transaction. Monetary assets andliabilities denominated in foreign currencies are translated to the functional currency at the foreignexchange rate at the statement of financial position date. Foreign exchange differences arising ontranslation are recognized in the statement of loss as net foreign exchange gains or losses. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated usingthe exchange rate at the date of the transactions.

F-117

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Research and Development

The Managing Partner engages in research and development activities to develop or improve processesand techniques to extract oil from oil sands deposits. Research involves planned investigation with thegoal of attaining new knowledge. Development involves translating that knowledge into a new technologyor process. Research and Development costs are charged by the Managing Partner. Research costs areexpensed as incurred.

Development costs which are expected to generate probable future economic benefits are capitalized asintangible assets if, and only if, all of the following have been demonstrated: the technical feasibility ofcompleting the intangible asset so that it will be available for use or sale; the intention to complete theintangible asset and use or sell it; the ability to use or sell the intangible asset; how the intangible assetwill generate probable future economic benefits; the availability of adequate technical, financial and otherresources to complete the development and to use or sell the intangible asset, and the ability to reliablymeasure the expenditure attributable to the intangible asset during its development. All other researchand development expenditure is expensed as incurred.

Inventories

Inventories are stated at the lower of cost and net realizable value. Crude oil inventories are accountedfor on a weighted average basis. Cost is determined by the first-in first-out method for materials andsupplies. Net realizable value represents the estimated selling price for inventories less all estimatedcosts of completion and costs necessary to make the sale.

Impairment of exploration and evaluation assets and property, plant and equipment

The Partnership assesses assets or groups of assets for impairment whenever events or changes incircumstances indicate that the carrying value of an asset may not be recoverable. Individual assets aregrouped based on levels with separately identifiable and largely independent cash inflows. For capitalizedexploration expenditure, the cash-generating units are individual wells.

In assessing whether a write-down of the carrying amount of a potentially impaired asset is required, theasset's carrying amount is compared to the recoverable amount. Frequently the recoverable amount of anasset proves to be the Partnership’s estimated value in use, which is determined using a discounted cashflow model. The estimated future cash flows applied are based on reasonable and supportableassumptions and represent the Partnership’s best estimates of the range of economic conditions that willexist over the remaining useful life of the cashflow generating assets, set down in Statoil’s most recentlyapproved long-term plans. The Partnership’s long-term plans are approved by Statoil’s corporatemanagement and updated at least annually. The plans cover a 10 to 40 year period and reflect expectedproduction volumes and prices for oil and natural gas in that period. For assets and cash generating unitswith an expected useful life or timeline for production of expected reserves extending beyond 10 years,the related cash flows also include project or asset specific estimates established in line with consistentassumptions and principles.

In performing a value in use-based impairment test, the estimated future cash flows are adjusted for risksspecific to the asset and discounted using a real post-tax discount rate based on Statoil’s post-taxweighted average cost of capital (WACC). The use of post-tax discounted rates in determining value inuse does not result in a materially different determination of the need for, or the amount of, impairmentthat would be required if pre-tax discounted rates had been used.

If assets are determined to be impaired, the carrying amounts of those assets are written down to therecoverable amount which is the higher of fair value less costs to sell and value in use.

F-118

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Impairments are reversed as applicable to the extent that conditions for impairment are no longerpresent.

Impairment losses and reversals of impairment losses are presented as exploration expenses ordepreciation, amortization and net impairment losses respectively, on the basis of their nature as eitherexploration and evaluation assets or development and producing assets (property, plant and equipment).

Financial liabilities

Financial liabilities are initially recognized at fair value when the Partnership becomes a party to thecontractual provisions of the liability. For additional information on fair value methods, refer to the"Measurement of fair values" section below. The subsequent measurement of financial liabilities dependson which category they have been classified into. The category applicable for the Partnership is thefinancial liabilities at fair value through profit or loss.

Trade and other payables are carried at payment or settlement amounts.

Financial liabilities are presented as current if the liability is due to be settled within 12 months after thestatement of financial position date, or if they are derivative financial instruments held for the purpose ofbeing traded. Other financial liabilities which contractually will be settled more than 12 months after thestatement of financial position date are classified as non-current.

Financial liabilities are derecognized when the contractual obligation expires, is discharged or cancelled.Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized eitherin interest income and other financial items or in interest and other finance expenses.

Provisions and contingent assets and liabilities

Provisions are recognized when the Partnership has a present obligation (legal or constructive) as a result of a past event and, it is probable that an outflow of resources embodying economic benefits will berequired to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expectedfuture cash flows at a pre-tax rate that reflects current market assessments of the time value of moneyand, where appropriate, the risks specific to the liability. Where discounting is used, the increase in theprovision due to the passage of time is recognized as other finance expenses.

Contingent liabilities arising from past events and for which it is not probable that an outflow of resourceswill be required to settle the obligation, if any, are not recognized but are disclosed with an indicationof uncertainties relating to amounts and timing involved, unless the possibility of an outflow in settlementis remote.

Possible assets arising from past events that will only be confirmed by future uncertain events and are notwholly within the Partnership’s control (contingent assets), are not recognized, but are disclosed when an inflow of economic benefits is probable. The asset and related income are subsequently recognized in thefinancial statements in the period in which the flow of economic benefits becomes virtually certain.

F-119

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Asset retirement obligations (ARO)

Provisions for ARO costs are recognized when the Partnership has an obligation (legal or constructive) to dismantle and remove a facility or an item of property, plant and equipment and to restore the site onwhich it is located, and when a reliable estimate of that liability can be made. Cost is estimated uponcurrent regulation and technology, considering relevant risks and uncertainties, to arrive at bestestimates. Normally an obligation arises for a new facility, such as an oil and natural gas production ortransportation facility, upon construction or installation. An obligation for ARO may also crystallise duringthe period of operation of a facility through a change in legislation or through a decision to terminateoperations. The provision is classified under asset retirement obligations in the statement of financialposition. The amount recognized is the present value of the estimated future expenditure determinedusing the credit adjusted risk free rate.

When a provision for ARO cost is recognized, a corresponding amount is recognized to increase therelated property, plant and equipment. This is subsequently depreciated as part of the costs of the facilityor item of property, plant and equipment.

Any change in the present value of the estimated expenditure is reflected as an adjustment to theprovision and the corresponding property, plant and equipment.

Measurement of fair values

Quoted prices in active markets represent the best evidence of fair value, and are used by thePartnership in determining the fair values of assets and liabilities to the extent possible.

A financial instrument is regarded as quoted in an active market if the prices quoted are readily andregularly available, normally through an exchange, and the prices quoted by the exchange representactual and regularly occurring market transactions that in all significant aspects are identical to theinstrument being valued. The Partnership considers both the actual volume and the timing of recentmarket transactions in determining whether prices are quoted in a sufficiently active market. Financialinstruments quoted in active markets will typically include commodity based futures, exchange tradedoption contracts, commercial papers, bonds and equity instruments with quoted market prices obtainedfrom the relevant exchanges or clearing houses. The fair values of quoted financial assets, financialliabilities and derivative instruments are determined by reference to bid and ask prices, at the close ofbusiness on the statement of financial position date.

Where there is no active market, fair value is determined using valuation techniques. These include usingrecent arm's-length market transactions; reference to other instruments that are substantially the same;discounted cash flow analysis; and pricing models. In the valuation techniques the Partnership also takesinto consideration the counterparty and its own credit risk. This is either reflected in the discount rateused, or through direct adjustments to the calculated cash flows.

Critical accounting judgements and key sources of estimation uncertainty

Critical judgements in applying accounting policiesThe following are the critical judgements, apart from those involving estimations, that the Partnership hasmade in the process of applying the accounting policies and that have the most significant effect on the amounts recognized in the financial statements:

F-120

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Key sources of estimation uncertaintyThe preparation of financial statements requires that management make estimates and assumptions thataffect reported amounts of assets and liabilities, income and expenses. The estimates and associatedassumptions are based on historical experience and various other factors that are believed to bereasonable under the circumstances, the result of which form the basis of making the judgements aboutcarrying values of assets and liabilities that are not readily apparent from other sources. Actual resultsmay differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoingbasis considering the current and expected future market conditions.

The Partnership is exposed to a number of underlying economic factors such as, natural gas prices, oilprices, diluent prices and foreign exchange rates which affect the overall results. In addition, thePartnership’s results are influenced by the level of production, which in the short term may be influencedby for instance maintenance programmes. In the long-term, the results are impacted by the success ofexploration and field development activities.

The matters described below are considered to be the most important in understanding the key sourcesof estimation uncertainty that are involved in preparing these financial statements and the uncertaintiesthat could most significantly impact the amounts reported on the results of operations, financial positionand cash flows.

Expected oil and gas reserves. Expected oil and gas reserves have been estimated by internal expertson the basis of industry standards and are used for impairment testing purposes and for calculation ofasset retirement obligations. Reserves estimates are based on subjective judgments involving geologicaland engineering assessments of in-place hydrocarbons volumes, the production, historical extractionrecovery and processing yield factors, installed plant operating capacity and operating approval limits.The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Futurechanges in expected oil and gas reserves, for instance as a result of changes in prices, could have a material impact on asset retirement obligations, as well as for the impairment testing of upstream assets,which could have a material effect on operating income as a result of changed impairment charges.

Exploration and leasehold acquisition costs. Judgements as to whether the costs of drillingexploratory wells pending determination of whether the wells have found proved oil and gas reserves,leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gasacreage should remain capitalized or written down due to impairment losses in the period may materiallyaffect the operating income for the period.

Impairment/reversal of impairment. The Partnership has significant investments in property, plant andequipment and intangible assets. Changes in the circumstances or expectations of future performance ofan individual asset may be an indicator that the asset is impaired requiring the book value to be writtendown to its recoverable amount. Impairments are reversed if conditions for impairment are no longerpresent. Evaluating whether an asset is impaired or if an impairment should be reversed requires a highdegree of judgement and may to a large extent depend upon the selection of key assumptions about thefuture.

Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest thatthe carrying amount of the asset may exceed its recoverable amount and at least annually. If, followingevaluation, an exploratory well has not found proved reserves, the previously capitalized costs are testedfor impairment. Subsequent to the initial evaluation phase for a well, it will be considered a trigger forimpairment testing of a well if no development decision is planned for the near future, and there is noconcrete plan for future drilling in the licence. Impairment of unsuccessful wells is reversed, as applicable,to the extent that conditions for impairment are no longer present.

F-121

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Estimating recoverable amounts involves complexity in estimating relevant future cash flows, based onassumptions about the future, and discounted to their present value. Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors such as futuremarket prices, refinery margins, currency exchange rates, future output, discount rates and political andcountry risk among others, in order to establish relevant future cash flows. Impairment testing frequentlyalso requires judgement to be applied in regards to applicable probabilities and probability distributions aswell as levels of sensitivity inherent in the establishment of recoverable amount estimates, and consequently in ensuring that the recoverable amount estimate’s robustness where relevant is factoredsufficiently into the impairment evaluations and reflected in the impairment or reversal of impairmentrecorded in the financial statements. Long-term assumptions for major economic factors are made at theStatoil group level, and there is a high degree of reasoned judgement involved in establishing theseassumptions, in determining other relevant factors such as forward price curves, in estimating productionoutputs, and in determining the ultimate termination value of an asset.

Asset retirement obligations. The Partnership has obligations to dismantle and remove a facility or an item of property, plant and equipment and to restore the site on which it is located, and when a reliableestimate of that liability can be made. Legal obligations associated with the retirement of non-currentassets are recognized at their fair value at the time the obligations are incurred. Upon initial recognition ofthe liability, that cost is capitalized as part of the related non-current asset and allocated to expense overthe useful life of the asset.

It is difficult to estimate the costs of these decommissioning and removal activities, which are based oncurrent regulations and technology, considering relevant risks and uncertainties. Most of the removalactivities are many years into the future and the removal technology and costs are constantly changing.The estimates include assumptions of both the time required and the costs that can vary considerablydepending on the assumed removal complexity. As a result, the initial recognition of the liability and thecapital cost associated with decommissioning and removal obligations, and the subsequent adjustment ofthese statement of financial position items, involve the application of significant judgement.

Income tax

The Partnership is not a taxable entity for federal and provincial tax purposes and as a result no recognition is given to income taxes for financial reporting purposes.

Earnings per share

The Partnership is not a publicly listed entity and as a result no calculation has been made for earningsper share.

3 FINANCIAL RISK MANAGEMENT OBJECTIVES AND POLICIES

General information relevant to risks

The Partnership’s business activities naturally expose it to financial risk. The Partnership’s approach torisk management includes identifying, evaluating, and managing risk in all activities. Additionally,mitigating measures are identified and followed up on to manage risk to acceptable levels.

The Managing Partner is responsible for defining, developing, and reviewing risk policies applied withinthe Partnership. Statoil’s risk management processes are applied consistently throughout the Partnershipas mandated by Statoil’s Corporate Risk Committee.

F-122

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

Financial risks

The Partnership's activities are exposed to financial risks as defined by IFRS 7:• Market risk (including commodity price risk, interest rate risk, currency risk)• Liquidity risk; and• Credit risk

Market risk

The Partnership operates in the crude oil and refined products markets and is exposed to market risksincluding fluctuations in hydrocarbon prices, foreign currency rates, interest rates and electricity pricesthat can affect the revenues and costs of operating, investing and financing activities.

The risks are managed primarily on a short-term basis with a focus on achieving the highest risk adjustedreturns within predefined mandates for risk tolerance, set by Statoil.

Commodity price risk

Commodity price risk represents the Partnership’s and Statoil’s most important short-term market risk,comprised primarily of the prices of purchased diluents, natural gas and electricity and the prices ofdiluted bitumen sold. Commodity price risk is monitored every day against established mandates asdefined by Statoil’s governing policies.

Currency risk

The Partnership has transactional currency exposure arising from sales and purchases in other than therespective functional currency. The Partnership does not actively manage this risk given limited non-functional currency activity however the risk is monitored periodically to assess the need for specificmitigation.

Liquidity risk

Liquidity risk is the risk that the Partnership will not be able to meet obligations associated with financialliabilities when due. The purpose of liquidity and current liability management is to make certain that thePartnership has sufficient funds available at all times to cover its financial obligations.

To secure financial flexibility and sufficiency of longer-term financing needs, inter-company loans are inplace to ensure sufficient liquidity based upon annual cash forecasts as well as short-term cash forecaststhat are updated weekly.

Credit risk

Credit risk is the risk that the Partnership’s customers or counterparties will cause the Partnershipfinancial loss by failing to honour their obligations.

Counterparty risk is closely managed by the Managing Partner’s credit risk group. Credit mandates defineacceptable credit risk thresholds and are endorsed by management and regularly reviewed with regard tochanges in market conditions. Prior to entering into transactions with new counterparties, credit policyrequires all counterparties to be formally identified, approved, and assigned internal credit ratings andexposure limits. All counterparties are re-assessed at a minimum annually and monitored continuously.

F-123

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

4 CAPITAL MANAGEMENT

The Partnership’s capital management policy is driven by Statoil’s group policy which is to maximisevalue creation over time, while maintaining a strong financial position. The ultimate parent company,Statoil ASA, incurs debt and then extends loans or equity to fully owned subsidiaries, including thePartnership, to fund capital requirements within the group.

The Partnership manages its capital through the Capital Value Process (CVP) which is the decisionprocess for investment projects (including cessation projects). The CVP is a structured and holisticapproach to project identification, development and execution. The CVP starts with a businessopportunity, prepared in a business case. The business case (including capital budgeting and forecastingfor a project and defined phases for a project) is risk mitigated through various approvals by theManaging Partner and Statoil’s internal decision process.

5 PROPERTY, PLANT AND EQUIPMENT

(thousands of dollars)

Machinery,equipment

andtransportation

equipment

Productionplants oiland gas,

incl.pipelines

Buildingsand land

Assets underdevelopment Total

Cost at December 31, 2009 1,295 83,596 27,608 1,133,518 1,246,017

Additions 4,134 11,809 5,119 385,978 407,040

Disposals (108) - (21,308) (3,088) (24,504)

Cost at December 31, 2010 5,321 95,405 11,419 1,516,408 1,628,553

Accumulated depreciation atDecember 31, 2009 (173) (2,269) - - (2,442)

Disposals 9 - - - 9

Depreciation and amortization (818) (2,089) - - (2,907)Accumulated depreciation atDecember 31, 2010 (982) (4,358) - - (5,340)Carrying amount at December 31,2010 4,339 91,047 11,419 1,516,408 1,623,213

F-124

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

(thousands of dollars)

Machinery,equipment

andtransportation

equipment

Productionplants oiland gas,

incl.pipelines

Buildingsand land

Assets underdevelopment Total

Cost at December 31, 2008 275 257 21,305 435,530 457,367

Additions 1,020 83,339 6,303 531,849 622,511Transfers from exploration andevaluation assets - - - 166,139 166,139

Cost at December 31, 2009 1,295 83,596 27,608 1,133,518 1,246,017

Accumulated depreciation atDecember 31, 2008 (18) (257) - - (275)

Depreciation and amortization (155) (2,012) - - (2,167)Accumulated depreciation atDecember 31, 2009 (173) (2,269) - - (2,442)Carrying amount at December 31,2009 1,122 81,327 27,608 1,133,518 1,243,575

Borrowing costsBorrowing costs relating to assets under development, that have been capitalized during the periodamount to $15,558 (2009 - $14,070), at a weighted average interest cost of 1.45% (2009 – 1.89%)

Gain on disposal of landIn 2010 the Partnership transferred land to the Managing Partner in exchange for the cancellation ofpartnership units. The transfer was recorded at $40,200, being the estimated fair value of the land. Thetransfer resulted in a $18,892 gain (note 10).

6 EXPLORATION AND EVALUATION ASSETS

The exploration and evaluation asset balance consists of the acquisition costs of the oil sands assets thathave not yet reached the development phase.

(thousands of dollars) 2010 2009Cost at beginning of the year 1,978,584 2,130,799Additions 39,779 13,924Transfers to property, plant and equipment - (166,139)Expensed exploration expenditures previously capitalized (2,351) -

Cost at end of the year 2,016,012 1,978,584

F-125

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

7 INVENTORIES

As at December 31

(thousands of dollars) 2010 2009Crude oil 2,485 -Petroleum products 6,879 - Materials and spare parts 2,218 -

Inventories 11,582 -

The cost of inventories recognized as an expense during the year was $3,383 (2009 – $32).

8 TRADE AND OTHER RECEIVABLES

As at December 31

(thousands of dollars) 2010 2009Trade receivables 435 2,749Accrued receivables 1,238 -Other 675 2,528

Trade and other receivables 2,348 5,277

The average credit period on sales of goods is 30 days. No interest is charged on past due receivables.

As at December 31 the analysis of trade receivables that were past due but not impaired is as follows:

(thousands of dollars) Total

Neither pastdue nor

impaired < 30 days30 – 60

days60 – 90

days90 – plus

days2010 435 188 - - - 2472009 2,749 2,577 - - - 172

In determining the recoverability of a trade or other receivable, the Partnership performs a risk analysisconsidering the type and age of the outstanding receivable and the creditworthiness of the counterparties.An allowance on the trade receivables disclosed above that are past due at the end of the reportingperiod has not been made because there has not been a significant change in credit quality and theamounts are still considered recoverable. The Partnership does not hold any collateral or other creditenhancements over these balances nor does it have a legal right of offset against any amounts owed bythe Partnership to the counterparties.

F-126

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

9 CASH AND CASH EQUIVALENTS

As at December 31

(thousands of dollars) 2010 2009

Cash at banks and on hand 112,631 329

Cash at banks earns interest at prime less 2 – 4% based on daily cash balances. The Partnership onlydeposits cash surpluses with major banks of high quality credit standing.

10 TRANSACTIONS IMPACTING PARTNERS’ EQUITY

The Partnership is authorized to issue an unlimited number of partnership units. Each unit represents an equal, undivided partnership interest in the Partnership and entitles the holder to participate equally indistributable cash and net income. Each unit is transferable, subject to the requirements referred to in thePartnership Agreement.

On November 22, 2010, a Partnership unit sale agreement was signed among Statoil Canada Ltd., StatoilCanada Holdings Corp. and PTTEP Netherland Holding Limited (“PTTEP”) that effective January 1, 2011,PTTEP would purchase a 40% interest in the Partnership.

On December 17, 2010, the Partnership sold land to Statoil Canada Ltd. for $40,200. Statoil Canada Ltd.paid for the purchase through the cancellation of 10,835 partnership units.

On December 17, 2010, the Partnership paid off the debt owing to Statoil Canada Ltd. as required in thePartnership unit sale agreement as described above. The debt was paid off through the issuance of580,835 partnership units for $2,155,049.

11 TRADE AND OTHER PAYABLES

As at December 31

(thousands of dollars) 2010 2009

Trade payables 3,345 3,734Accrued expenses 51,210 72,371

Trade and other payables 54,555 76,105

Trade and other payables are non-interest bearing and are normally settled on an average of 30 – 90days.

F-127

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

12 ASSET RETIREMENT OBLIGATIONS

(thousands of dollars) 2010 2009Asset retirement obligations as at January 1 10,183 5,924Liabilities incurred/revision in estimates 5,788 3,883Accretion 528 376

Asset retirement obligations at December 31 16,499 10,183

The amount recognized is the estimated future expenditure relating to dismantle and remove a facility oran item of property, plant and equipment and to restore the site on which it is located. The provision is thediscounted present value of the estimated costs, using existing technology at current prices. The AROobligation has been created based on the Partnership’s internal estimates using a credit-adjusted risk freerate of 5.17% (2009 – 5.4%) and 2% inflation rate (2009 – 2%). The majority of expenditures related toasset retirement obligations are currently expected to be paid in 2050. Only a minor portion ofexpenditures are expected to be paid in the next five years. The timing depends primarily on when theproduction ceases at the various facilities. For further discussion of methods applied and estimatesrequired, see note 2 significant accounting policies.

Obligations related to environmental remediation and cleanup related to oil and gas producing assets areincluded in the estimated asset retirement obligations.

13 RELATED PARTY DISCLOSURES

The Partnership has no employees or management. Statoil and Statoil Canada provide all employeesand management to the Partnership. Amounts charged to the Partnership for these services arecalculated based on time incurred and at rates that are based on fair values.

All other costs incurred by the Partnership, whether charged to expense or capitalized, comprise costsdirectly incurred by Statoil or Statoil Canada on the Partnership’s behalf, and are recorded as amountsdue to related companies in these financial statements.

During the year, the Partnership incurred research and development expenses amounting to $18,463(2009 – Nil) of which $18,112 was incurred by the Managing Partner on behalf of the Partnership andrecorded as part of selling, general and administrative expenses and the remaining amount is recordedas part of operating expenses.

As at and for the year ended December 31, 2010

(thousands of dollars)Providing

servicesPurchaseservices

Accountspayable

Accountsreceivable

Statoil Canada Ltd. (Managing Partner) 2,990 126,114 36,335 2,312Statoil ASA (ultimate parent) - 7,984 1,031 -

Leismer Aerodrome Ltd. (affiliate) 119 15 15 11

Total 3,109 134,113 37,381 2,323

F-128

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

As at and for the year ended December 31, 2009

(thousands of dollars)Providing

servicesPurchaseservices

Accountspayable

Accountsreceivable

Statoil Canada Ltd. (Managing Partner) 4,933 69,563 1,417,054 37Statoil ASA (ultimate parent) 714 6,837 657 53Leismer Aerodrome Ltd. (affiliate) 552 238 5 76

Statoil (UK) Ltd. (affiliate) 66 40 40 -

Total 6,265 76,678 1,417,756 166

The receivables from and payables to related companies are unsecured and bear no fixed repaymentterms. No expense has been recognized in the current or prior years for bad or doubtful debts in respectof the amounts owed by related parties. Certain amounts included in payables during the year bearinterest at prime and are accrued monthly.

14 CHANGES IN NON-CASH WORKING CAPITAL

For the year ended December 31

(thousands of dollars) 2010 2009Inventory (11,582) -

Trade and other receivables 2,929 (3,202)Receivables from related parties (2,157) 402

Prepaids (983) 126Trade and other payables (21,550) (27,647)

Payables to related companies (1,380,375) 744,767

Changes in non-cash working capital (1,413,718) 714,446

15 OTHER COMMITMENTS AND CONTINGENCIES

Take or pay contracts

During the normal course of business, the Partnership has entered into contractual, take or pay contractsfor the purchase of services from various third parties. The remaining commitment to be paid in 2011 is$8,186.

The Managing Partner has entered into a long-term take or pay agreement for pipeline transportation ofcrude oil. The primary term of the contract is 120 months and will continue to an optional second term at the end of the primary term for a period of 60 months. The agreement ensures the right to transport theproduction of crude from the partnership operations through the pipeline, while also imposing anobligation to pay for booked capacity.

F-129

Statoil Canada PartnershipNotes to the Financial StatementsFor the year ended December 31, 2010(Information as at December 31, 2009 and January 1, 2009 and for the year ended December 31, 2009 isunaudited)

The following are the minimum commitments at December 31, 2010:

(thousands of dollars)Transport

commitments

2011 1,446

2012 9,9792013 19,329

2014 19,5232015 19,718

Thereafter 122,519192,514

16 FINANCIAL INSTRUMENTS

Fair values

The fair values of the financial assets and liabilities are included at the amount at which the instrumentscould be exchanged in a current transaction between willing parties, other than in a forced or liquidationsale.

The fair values of cash and cash equivalents, trade and other receivables, receivables from relatedcompanies, trade and other payables and payables to related companies approximate their carryingamounts largely due to the short-term maturities of these instruments.

17 SUBSEQUENT EVENT

On January 21, 2011, the partners signed a Partnership Unit Sale Agreement with a subsidiary of PTTEPExploration and Production Public Company Limited (“PTTEP”), resulting in PTTEP acquiring Partnershipunits from Statoil Canada Holdings Corp. and from Statoil Canada Ltd for aggregate proceeds of $2.28billion. Following the acquisition, PTTEP owns a 40% Partnership Interest and Statoil Canada Ltd. ownsa 60% Partnership interest. The effective date of the agreement is January 1, 2011.

F-130

UNAUDITED PRO FORMA COMBINED

FINANCIAL INFORMATION OF PTTEP AS OF AND FOR THE

YEAR ENDED DECEMBER 31, 2010

F-131

PTT Exploration and Production Public Company Limited and SubsidiariesUnaudited Pro Forma Condensed Combined Balance Sheet

As of December 31, 2010

HistoricalPTTEP

HistoricalSCP 40%(Note 4)

Pro Forma adjustments

Pro FormaPTTEP

40% SCPAcquisition Notes issue

Thai GAAP Thai GAAP Thai GAAP Note Thai GAAP Note Thai GAAPASSETS

Cash and cash equivalents .................................. 59,515 1,371 (58,829) 3 (a) 21,146 3 (f) 23,203

Accounts receivable ............................................ 11,728 57 — — 11,785

Inventories ........................................................... 594 141 — — 735

Materials and supplies, net ................................. 7,954 — — — 7,954

Other current assets............................................. 5,285 15 — — 5,300

Total current assets ........................................... 85,076 1,584 (58,829) 21,146 48,977Non-current assets

Investments.......................................................... 1,468 — — — 1,468

Property, plant and equipment, net..................... 226,333 14,934 27,596 3 (b) — 268,863

Intangible assets, net ........................................... 3,939 29,366 5,327 3 (b) — 38,632

Goodwill .............................................................. — — 9,146 2, 3 (a) — 9,146

Deferred income tax assets................................. 13,824 — — — 13,824

Other non-current assets .....................................

Prepaid expenses ................................................. 152 — — — 152

Deposit for the purchase of partnership units.... 10,312 — (10,312) 3 (a) — —

Deferred remuneration under agreement............ 920 — — — 920

Other non-current assets ..................................... 196 — — — 196

Total non-current assets ................................... 257,144 44,300 31,757 — 333,201Total assets .............................................................. 342,220 45,884 (27,072) 21,146 382,178Current Liabilities

Accounts payable ................................................ 1,959 1,120 — — 3,079

Current portion of long-term debt ..................... — — — — —

Short-term loans.................................................. 7,945 — — — 7,945

Working capital to co-venturers ......................... 1,014 — — — 1,014

Accrued expenses................................................ 18,274 — — — 18,274

Accrued interests payable ................................... 552 — — — 552

Income tax payable ............................................. 22,448 — — 3 (b) — 22,448

Short-term provision ........................................... 3,933 — — — 3,933

Other current liabilities ....................................... 2,072 — — — 2,072

Total current liabilities ..................................... 58,197 1,120 — — 59,317Non-current Liabilities

Bonds................................................................... 69,893 — — 21,146 3 (f) 91,039

Finance lease liabilities ..................................... — — — — —

Deferred income tax liabilities ........................... 15,780 — 17,491 — 33,271

Other non-current liabilities................................ 26,056 201 — — 26,257

Total non-current liabilities ............................. 111,729 201 17,491 21,146 150,567Total Liabilities ....................................................... 169,926 1,321 17,491 21,146 209,884Stockholders’ EquityShare Capital ............................................................ 17,500 — — — 17,500

Partnership units....................................................... — 49,481 (49,481) — —

Currency translation differences.............................. (2,953) — — — (2,953)

Retained earnings/ (Deficit)..................................... 157,747 (4,918) 4,918 — 157,747

Total stockholders’ equity ..................................... 172,294 44,563 (44,563) — 172,294Total liabilities and stockholders’ equity ............ 342,220 45,884 (27,072) 21,146 382,178

F-132

PTT Exploration and Production Public Company Limited and SubsidiariesUnaudited Pro Forma Condensed Combined Statement of Operations

For the year ended December 31, 2010

HistoricalPTTEP

HistoricalSCP 40%

Note 4

Pro Forma Adjustments

Pro FormaPTTEP

40% SCPAcquisition Notes issue

Thai GAAP Thai GAAP Thai GAAP Note Thai GAAP Note Thai GAAPNet revenueRevenues

Sales..................................................................... 138,474 69 — — 138,543

Revenue from pipeline transportation ................ 3,504 — — — 3,504

Other revenues .................................................... 5,594 249 — — 5,843

Total revenues .................................................... 147,572 318 — — 147,890Expenses

Operating expenses ............................................. 14,588 548 — — 15,136

Exploration expenses .......................................... 2,752 1,233 — — 3,985

Administrative expenses ..................................... 5,972 325 — — 6,297

Petroleum royalties and remuneration................ 16,773 — — — 16,773

Depreciation, depletion and amortization .......... 36,825 35 540 3 (c) — 37,440

Other expenses .................................................... 2,127 — — — 2,127

Total expenses .................................................... 79,037 2,141 540 — 81,718Operating income ................................................... 68,535 (1,823) (540) — 66,172

Loss from the investments in associates ............ (45) — — — (45)

Income before finance costs and income taxes ...... 68,490 (1,823) (540) — 66,127

Finance costs ....................................................... 2,540 345 — 1,213 3 (g) 4,098

Income before income taxes.................................... 65,950 (2,168) (540) (1,213) 62,029

Income taxes ....................................................... 24,211 — (151) 3 (c) (340) 3 (g) 23,720

Net income .............................................................. 41,739 (2,168) (389) (873) 38,309Earnings per share

Basic earnings per share ..................................... 12.59 11.56

Diluted earnings per share .................................. 12.59 11.56

F-133

1. BASIS OF PRESENTATION

The unaudited pro forma combined financial information has been prepared in connection with the acquisition of 40% participationinterest in the Partnership from Statoil Canada Ltd. and Statoil Canada Holdings Corp. legally named Statoil Canada Partnership (“SCP”) byPTT Exploration and Production Public Company Limited (“PTTEP”) through its subsidiary PTTEP Canada Limited. In addition, the proforma combined financial statements include the issuance and sale of Baht 21,207 5.692% Senior Notes due 2021 by PTTEP through itssubsidiary PTTEP Canada International Finance Limited. Together these two events will be referred to as the “Transactions” for the purposesof this unaudited pro forma financial information.

The unaudited pro forma combined financial information has been prepared for illustrative purposes only and gives effect to theTransactions by PTTEP pursuant to the assumptions described in Note 3 to the pro forma combined financial information. The unaudited proforma combined balance sheet as at December 31, 2010 gives effect to the Transactions by PTTEP as if they had occurred on December 31,2010. The unaudited pro forma combined statement of operations for the year ended December 31, 2010 gives effect to the Transactions asif they were completed on January 1, 2010.

The pro forma combined financial information is not necessarily indicative of the operating results or financial condition that wouldhave been achieved if the Transactions had been completed on the dates or for the periods presented, nor do they purport to project the resultsof operations or financial position of the consolidated entities for any future period or as of any future date. The pro forma combined financialinformation does not reflect any efficiencies relating to operating synergies that may be incurred as a result of the Transactions.

The pro forma adjustments and allocations of the purchase price for SCP are based in part on preliminary estimates of the fair valueof assets acquired and liabilities to be assumed. The acquisition price for the participation interests in SCP was Baht 68,997 million. Of thetotal, Baht 10,312 million was paid on November 22, 2010, with the balance being paid on January 22, 2011. The transaction costs associatedwith this acquisition were Baht 143 million.

In preparing the unaudited pro forma combined balance sheet and the unaudited pro forma combined statement of operations, thefollowing historical information was used:

(a) the audited consolidated balance sheet of PTTEP as at December 31, 2010, and the audited consolidated statement of operationsfor the year ended December 31, 2010 in accordance with Thai GAAP;

(b) the audited statement of financial position of SCP as at December 31, 2010, and the audited statement of loss andcomprehensive loss for the year ended December 31, 2010 in accordance with IFRS.

The pro forma combined financial information includes information from the financial statements of SCP as indicated above which areprepared according to IFRS. Adjustments for any GAAP differences, accounting policy conformation and other presentational matters in SCP’sfinancial statements are set out in Note 4.

The unaudited pro forma combined balance sheet and the unaudited pro forma combined statement of operations should be read inconjunction with the above listed financial statements and their accompanying notes.

2. ACQUISITION OF SCP

On November 22, 2010, PTTEP announced a proposal to acquire 40% of the outstanding Partnership units of SCP (the ‘‘Offer’’) forcash of Baht 68,997 million.

The acquisition will be accounted for as a business combination with PTTEP as the acquirer of a 40% interest in SCP. PTTEP hasobtained joint control and as such has proportionately consolidated the results of SCP.

The allocation of the purchase price is based upon management’s preliminary estimates and certain assumptions with respect to the fairvalue increment associated with the assets to be acquired and the liabilities to be assumed. The actual fair values of the assets and liabilitieswill be determined as of the date of acquisition and may differ materially from the preliminary amounts disclosed below in the assumed proforma purchase price allocation because of changes in fair values of the assets and liabilities for the final purchase price allocation.

Million ThaiBaht

Purchase price ............................................................................................................................................................. 68,997Transaction costs ......................................................................................................................................................... 143Purchase consideration ............................................................................................................................................. 69,140Fair value of assets/ (liabilities) acquiredCash and cash equivalents .......................................................................................................................................... 1,371Accounts receivable- related companies .................................................................................................................... 28Trade accounts receivable ........................................................................................................................................... 29Inventories ................................................................................................................................................................... 141Prepaid expense ........................................................................................................................................................... 15Accounts payable- related companies ........................................................................................................................ (455)Trade accounts payable ............................................................................................................................................... (665)Working capital ......................................................................................................................................................... 464Property, plant and equipment ................................................................................................................................ 42,530Intangible .................................................................................................................................................................... 34,692Liabilities assumedFuture Income taxes ................................................................................................................................................. (17,491)Asset retirement obligation ...................................................................................................................................... (201)Goodwill ...................................................................................................................................................................... 9,146Purchase price allocated ........................................................................................................................................... 69,140

F-134

3. EFFECT OF TRANSACTIONS ON THE PRO FORMA COMBINED FINANCIAL STATEMENTS

The transactions reflected in the pro forma financial information are:

1) Purchase of 40% interest in SCP by PTTEP completed January 2011

2) Adjustments for GAAP differences, accounting policy differences and conformation of financial statement presentation

3) Baht 21,207 million senior notes issuance

1) Purchase of 40% interest in SCP

a) PTTEP paid Baht 68,997 for the purchase of the 40% interest in SCP with a Baht 10,312 million deposit paid onNovember 22, 2010 and transaction costs of Baht 143 million for a total of Baht 58,829 million calculated as follows:

Million ThaiBaht

Purchase Price including transaction costs ......................................................................................... 69,140

Less Deposit (paid Nov 22, 2010) ..................................................................................................... (10,312)

Total Cash to be paid and adjusted .................................................................................................... 58,829

b) The working capital, property, plant and equipment, intangibles, and future income taxes have been adjusted to reflectthe fair value, with the residual being recorded as Goodwill. See Note 2 for fair value allocation.

c) Depletion, depreciation and amortization expense has been adjusted to reflect the application of the appropriateunit-of-production rate for successful efforts allocated to SCP based on the estimated proved petroleum reserves asdetermined by independent reserve engineers after adjustments for transactions described in Note 2.

d) The transactions costs for the PTTEP’s acquisition of 40% interest in SCP total Baht 143 million. This amount shouldbe capitalised under Thai GAAP and as such is adjusted to goodwill.

e) The future income tax provision has been adjusted to reflect the adjustments above.

2) Accounting Policies and differences between IFRS and Thai GAAP for SCP

PTTEP, which maintains its books and records in accordance with Thai GAAP, has compared their accounting policies with theaccounting policies under IFRS that SCP has, to ensure consistent application of certain accounting estimates under Thai GAAP. Basedon this analysis, differences have been identified resulting in several pro forma adjustments. See Note 4 for GAAP differenceadjustments.

3) Senior notes issuance and sale

f) PTTEP has issued 5.692% senior notes for Baht 21,207 million due 2021.

g) The effective interest of Baht 1,213 million is recorded for the year ended December 31, 2010 with a 28% tax effectfor PTTEP’s tax rate in Canada.

4. RECONCILATION OF SCP FINANCIAL STATEMENTS

The following are pro forma adjustments made to accounts for the IFRS to Thai GAAP differences and accounting policy differencesbetween SCP and PTTEP.

• PTTEP’s accounting policy is to classify probable (i.e. unproven) reserves occurring from acquisitions as Intangible Assets.Thus an adjustment has been made to reclassify probable reserves recognised as PP&E by SCP to Intangibles for PTTEP.

• PTTEP recognised Exploration and Evaluation Assets as PP&E. Thus an entry was made to reclassify these amounts to PP&E.

Other adjustments:

Certain SCP audited financial statement line items have been remapped to line up with the PTTEP line items on FinancialStatements. See Note 4 for line reconciliation.

The SCP financial statements for the period ended December 31, 2010 have been prepared in accordance with IFRS andpresented in Canadian dollars (“CAD$”). The following reconciliation is to reflect differences that exist between IFRS and Thai GAAP,conversion from CAD$ to Baht, and line item reclassifications to reflect PTTEP line items.

F-135

PTTEP has proportionally consolidated the Audited Financial Statements of SCP for the 40% interest acquired and have beentranslated from CAD$ to Baht using the Bank of Thailand year end rate of 30.432 Baht to CAD$1.00.

SCP Balance Sheet ReconciliationAs at December 31, 2010(million Thai Baht)

SCP 40% SCP 40%December 31,

2010Line item

reclassificationThai GAAPadjustments

December 31,2010

IFRS Thai GAAPASSETS

Cash and cash equivalents ......................................... 1,371 — 1,371

Accounts receivable- related companies.................... 28 — 28

Trade accounts receivable .......................................... 29 — 29

Inventories................................................................... 141 — 141

Prepaid expense .......................................................... 15 (15) —

Other current assets .................................................... 15 — 15

Total current assets................................................... 1,584 — 1,584Non-current assets

Property, plant and equipment, net ............................ 19,759 (4,825) 14,934

Intangible assets, net .................................................. 24,541 4,825 29,366

Total non-current assets........................................... 44,300 — 44,300Total assets...................................................................... 45,884 — 45,884Current Liabilities

Accounts payable- related companies........................ 455 — 455

Trade accounts payable............................................ 665 — 665Total current liabilities ............................................... 1,120 — 1,120

Non-current LiabilitiesProvision for decommissioning costs ........................ 201 — 201

Asset Retirement Obligation ...................................... 201 (201) —

Total non-current liabilities ..................................... 201 — 201Total Liabilities .............................................................. 1,321 — 1,321

Stockholders’ EquityPartnership units ......................................................... 49,481 — 49,481

Deficit ......................................................................... (4,918) — (4,918)

Total stockholders’ equity........................................ 44,563 — 44,563Total liabilities and stockholders’ equity ............... 45,884 — 45,884

F-136

SCP Income of Operation ReconciliationFor the year ended December 31, 2010(million Thai Baht)

SCP 40% SCP 40%Year ended

December 31,2010

Line itemreclassification

Thai GAAPadjustments

Year endedDecember 31,

2010

IFRS Thai GAAPNet revenueRevenues

Sales ............................................................................ 69 — 69

Revenue from crude oil sales..................................... 64 (64) —

Other sales .................................................................. 5 (5) —

Other revenues............................................................

Gain on foreign exchange .......................................... 19 — 19

Net foreign exchange gains........................................ 19 (19) —

Interest income ........................................................... 0 — 0

Gain on sale of assets................................................. 230 (230) —

Other revenues............................................................ 230 — 230

Total revenues ........................................................... 318 — — 318Expenses

Operating expenses..................................................... 507 41 — 548

Purchases..................................................................... 41 (41) —

Exploration expenses.................................................. 1,233 — 1,233

Selling, general and administrative expenses ............ 325 (325) —

Administrative expenses............................................. — 325 — 325

Depreciation, depletion and amortization .................. 35 — 35

Total expenses............................................................ 2,141 — — 2,141Operating income .......................................................... (1,823) — — (1,823)Loss from the investments in associates ........................ — —

Income before finance costs and income taxes .......... (1,823) — — (1,823)Finance costs............................................................... 345 — 345

Interest and other finance expenses ........................... 345 (345) —

Income before income taxes ......................................... (2,168) — — (2,168)Income taxes ............................................................... — —

Net loss ............................................................................ (2,168) — — (2,168)

F-137

ISSUER

PTTEP Canada International Finance LimitedEnergy Complex Building A 6th Floor & 19th � 36th Floor

555/1 Vibhavadi-Rangsit RoadBangkok 10900

Thailand

GUARANTOR

PTT Exploration and Production Public Company LimitedEnergy Complex Building A 6th Floor & 19th � 36th Floor

555/1 Vibhavadi-Rangsit RoadBangkok 10900

Thailand

TRUSTEE, PAYING AGENT, REGISTRAR AND TRANSFER AGENT

The Bank of New York Mellon101 Barclay Street

New YorkNew York 10286

USA

LEGAL ADVISERS TO THE ISSUER AND THE GUARANTOR

as to United States law

Allen & Overy9th Floor

Three Exchange Square, CentralHong Kong

as to Thai law

Allen & Overy (Thailand) Co., Ltd.22nd Floor, Sindhorn Building 3,

130-132 Wireless Road,Lumpini, Pathumwan,

Bangkok 10330Thailand

as to Canadian law

Stikeman ElliottLevel 12, Chifley Tower

2 Chifley SquareSydney, NSW 2000

Australia

LEGAL ADVISERS TO THE INITIAL PURCHASER

as to United States law

Clifford ChanceJardine House 29th Floor

One Connaught PlaceCentral

Hong Kong

as to Thai law

Clifford Chance (Thailand) LimitedSindhom Building Tower 3

21st Floor, 130-132 Wireless RoadPathumuan

Bangkok 10330Thailand

LEGAL ADVISERS TO THE TRUSTEE

as to United States law

Clifford ChanceJardine House 29th Floor

One Connaught PlaceCentral

Hong Kong

AUDITORS OF THE GUARANTOR

The Office of the Auditor General of ThailandSoi Areesampan, Rama VI Road

Bangkok 10400Thailand