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  14. Financial Position and Results of Operation for Year 2003

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14.1 Auditor and Significant Accounting Policies

  14.1.1 Auditor

  PTTEP has appointed Office of the Auditor General, auditor approved by
  the office of Securities and Exchange Commission (SEC), the external
  auditor of the Company and subsidiaries

14.1.2 Summary Auditors’ Report in the past 3 years

  The auditor expressed clean opinion in the Auditors’ Report in the
  past 3 years and expressed the additional opinion are as follows:

1)  Assets, liabilities and expenses of the joint venture have not been
    audited by the Company’s auditor however they have been audited by
    the joint ventures’ auditors.

    2) In the year 2001, the Company has changed its accounting policy
    for its investment in Taninthayi Pipeline Company LLC, a related
    company, from the cost method to the equity method in the financial
    statements of the Company and applied the proportionate
    consolidation method for the consolidated financial statements. The
    Company also changed from the equity method to the proportionate
    consolidation method in the consolidated financial statements for
    Moattama Gas Transportation Company because the Company has joint
    control over both companies, in the form of joint ventures. The
    effect of this change affected to restatement of the audited
    financial statement for the year 2000, and the auditor expressed an
    opinion to the restated financial statements for the year 2000.

    3) The Group recorded a provision of decommissioning costs for the
    year 2003. A provision is recognized, and provided at the onset of
    production of the project, for the estimate of the eventual costs
    that relate to the removal of the production facilities. These costs
    were included as part of the oil and gas properties and were
    amortized based on proved reserves on a unit of production basis.
    The effect of this change affected to restatement of the comparative
    financial statement for the year 2002, and the auditor expressed an
    opinion to the restated financial statements for the year 2002.

14.1.3 Significant Accounting Policies

1) Basis for Preparation of Financial Statements

  The consolidated and the Company financial statements have been
  prepared in accordance with Generally Accepted Accounting Principles
  in Thailand under the Accounting Act B.E. 2543, being those Accounting
  Standards in Thailand issued by the Institute of Certified Accountants
  and Auditors of Thailand and approved under law by the Board of
  Supervision of Auditing Practice appointed by the Minister of Commerce
  under the Auditor Act B.E. 2505, and the financial reporting
  requirements of the Securities and Exchange Commission.

  The Company presents financial statements in compliance with
  notification of Department of Commercial Registration dated September
  14, 2001 under the third paragraph of section 11 of Accounting Act
  B.E. 2543.

  Since 1998, the Group has applied International Accounting Standard 12
  “Income Taxes”.

  The consolidated and the Company financial statements are use of
  estimates and assumptions that affect the assets, liabilities,
  revenues and expenses reported in the financial statements. While the
  Group uses its best estimates and judgments, actual results could
  differ from these estimates as future confirming events occur.

  The consolidated and the Company financial statements have been
  prepared under the historical cost convention except as disclosed in
  the accounting policies below.

2) Subsidiary Undertakings

  Subsidiary undertakings, which are those entities in which the parent
  company in the Group has an interest of more than one half of the
  voting rights and has power to exercise control over subsidiaries’
  financial policies and operations. Subsidiaries are consolidated from
  the date on which control is transferred to the parent company and are
  no longer consolidated from the date that control ceases. All
  intercompany transactions, balances and unrealized gains on
  transactions between the Group are eliminated; unrealized losses are
  also eliminated unless cost cannot be recovered. Where necessary,
  accounting policies for subsidiaries have been changed to ensure
  consistency with the policies adopted by the Group.

  3) Associated Undertakings

  Investments in associated undertakings are accounted for by the equity
  method of accounting. These are undertakings over which the Group
  generally has between 20% and 50% of the voting rights, and over which
  the Group has significant influence, but which it does not control.
  Unrealised gains on transactions between the Group and its associated
  undertakings are eliminated to the extent of the Group’s interest in
  the associated undertakings; unrealised losses are also eliminated
  unless the transaction provides evidence of an impairment of the asset
  transferred. The Group’s investment in associated undertakings
  includes excess on acquisition. Equity accounting is discontinued when
  the carrying amount of the investment in an associated undertaking
  reaches zero, unless the Group has incurred obligations or guaranteed
  obligations in respect of the associated undertaking.

  4) Joint Ventures

  The Group’s interest in jointly controlled entities are accounted for
  by proportionate consolidation. Under this method the Group includes
  its share of the joint ventures’ individual income and expenses,
  assets and liabilities in the relevant components of the financial
  statements.

  The Group’s interest in jointly controlled assets are accounted for by
  proportionate consolidation. Under this method the Group includes its
  share of the assets, liabilities and expenses based on Joint Operating
  Agreement in the relevant components of the financial statements.

5) Related Parties

Enterprises and individuals that directly, or indirectly, through one or
more intermediaries, control, are controlled by, or are under common
control with, the Company, including holding companies, subsidiaries and
follow subsidiaries are related parties of the Company. Associates and
individuals owning, directly or indirectly, an interest in the voting
power of the Company that gives them significant influence over the
enterprise, key management personnel, including directors and officers
of the Company.

In considering each possible related party relationship, attention is
directed to the substance of the relationship, and not merely the legal
form.

6) Foreign Currency Transactions

  Foreign currency transactions are translated into Baht at the exchange
  rates ruling on the transaction dates. Monetary assets and liabilities
  denominated in foreign currency remaining at the year-end date are
  translated into Baht at the average buying and selling rates,
  respectively, as determined by the Bank of Thailand. Such gains or
  losses are recognized as revenues or expenses in the period in which
  they occur.

  The monetary assets and liabilities of subsidiary companies are
  translated into Baht using average buying and selling rates determined
  by the Bank of Thailand at year-end, whereas the income statement is
  translated using the exchange rates ruling on the transaction dates.
  Gains or losses from such translation are recognized as revenues or
  expenses in the period in which they occur.

  The assets and liabilities of overseas jointly controlled entities are
  translated into Baht using average buying and selling rates determined
  by the Bank of Thailand at year-end, whereas the income statement is
  translated using average exchange rates during the period. Differences
  from such translation have been shown under the caption of “Currency
  Translation Differences” in shareholders’ equity.

  7) Cash and Cash Equivalents

  Cash and cash equivalents comprise cash on hand and at banks, and
  other short-term highly liquid investments with maturities within 3
  months.

8)  Trade Accounts Receivable

  Trade accounts receivable are carried at anticipated realizable value.
  An estimate is made for doubtful receivables based on a review of all
  outstanding amounts at the year end. Bad debts are written off during
  the year in which they are identified.

9) Inventories

  Inventories are valued at the lower of weighted average cost or net
  realizable value. Cost is determined by the weighted average method.
  Net realizable value is the estimated selling price in the ordinary
  course of business, less the costs of completion and selling expenses.

10) Materials and Supplies

  Materials and supplies are valued on the average cost basis.
  Allowances have been provided for obsolete and unserviceable items.

11) Borrowing Costs

Interest costs on borrowings to finance the construction of property,
plant and equipment are capitalized, during the period of time that is
required to complete and prepare the asset for its intended use. All
other borrowing costs are expensed.

  12) Property, Plant and Equipment

  General properties

  Property, plant and equipment are presented at cost, after deducting
  accumulated depreciation and provision for impairment of assets.

  Depreciation of general properties is determined on the straight-line
  method at rates ranging from 5% to 20% per annum.

Oil and Gas Property

  The Company follows the Successful Efforts Method in accounting for
  its oil and gas exploration and production activities as follows:

  Cost of Properties

  Cost of properties comprising total acquisition costs of concession
  right or the portion of costs applicable of properties, drilling,
  development, equipment and operating costs of support equipment as
  well as the decommissioning costs. If

  exploratory wells establish proved reserves, and are included in the
  plan to develop in the near future, exploratory drilling costs (both
  tangible and intangible) are initially capitalized otherwise the
  related costs are charged as expenses.

  Exploratory costs, comprising geological and geophysical costs as well
  as area reservation fees during the exploration stage, are charged to
  expenses as incurred.

  Development costs, irrespective of whether relating to development
  wells or unsuccessful development wells, are capitalized.

  Depreciation, depletion and amortization

Capitalized of acquisition costs of concession right are depleted and
amortized on the unit of production method, which is based on estimated
proved recoverable reserves. Depreciation, depletion and amortization of
exploratory wells, development equipment and operating costs of support
equipment as well as the decommissioning costs, except unsuccessful
projects are calculated on the unit of production method, which is based
on estimated proved recoverable reserves and proved development
reserves. Changes in reserve estimates are recognized prospectively.

Proved recoverable reserves and proved development reserves are
calculated by the Group’s own engineers and information from the joint
ventures.

Depreciation of transportation pipeline of Yadana and Yetagun project is
calculated on the straight-line method with an estimated useful life of
30 years.

Where the carrying amount of an asset is greater than its estimate
recoverable amount, it is written down immediately to its recoverable
amount.

Gain and losses on disposal are determined by reference to their
currying amount and are taken into account in operating profit.

Expenditure for addition, renewal and betterment which result in a
substantial increase in an asset’s current replacement value, are
capitalized. Repair and maintenance costs are recognized as expenses
when incurred.

  13) Intangible Assets

  Expenditures on acquired licenses for computer software are
  capitalized and amortized using the straight-line method over the
  lives of contract, maximum of 10 years. The carrying amount is
  reviewed annually and adjusted for impairment where it is considered
  necessary.

  14) Deferred Income Taxes

  Deferred income tax is provided in full, using the balance sheet
  method, on temporary differences arising between the tax bases of
  assets and liabilities and their carrying amounts in the financial
  statements. The principal temporary differences arise from
  depreciation on property, plant and equipment, amortization of
  decommissioning costs, tax losses carried forward and, on the
  difference between the fair values of the net assets acquired and
  their tax base.

  Tax rates enacted or substantively 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
    temporary differences can be utilized.

  Deferred income tax is provided on temporary differences arising on
  investments in subsidiaries, associates and joint ventures, except
  where the timing of the reversal of the temporary difference can be
  controlled and it is probable that the temporary difference will not
  reverse in the foreseeable future.

  15) Borrowings

Borrowings are recognised initially at the proceeds received.
Transaction costs incurred are recognized as deferred assets and
amortized through the income statement over the period of the
borrowings.

  16) Provision for Decommissioning Cost

  The Group recorded provision for decommissioning cost whenever it is
  probable that there is an obligation as a result of the past event and
  reliable amount of obligation.

  The Group recognizes provision for decommissioning costs, which are
  provided at the onset of production of the project, for the estimate
  of the eventual costs that relate to the removal of the production
  facilities. These costs were included as part of the oil and gas
  properties and were amortized based on proved reserves on a unit of
  production basis. The estimates of decommissioning costs have been
  determined based on reviews and estimates by the Group’s own engineers
  and managerial judgment.

  17) Reserve for Expansion

  The Group sets aside a reserve for expansion for the purpose of
  investing in new exploration-phase projects, which are generally
  susceptible to high risk, and for the purpose of finding additional
  petroleum reserves. The reserve for expansion is set aside at the rate
  of 35% of the net profit on tax basis after tax from exploration and
  production activities.

18) Income Recognition

  Sales are recognized upon delivery of products and customer
  acceptance.

  Interest income is recognized on the basis of percentage of period,
  taking into account the effective yield on the asset.

  Revenues other than the above mentioned are recognized on an accrual
  basis.

19) 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. 2532 and the
    Revenue Code

-   Income tax in the Union of Myanmar

-   Deferred income taxes.

  20) Provident Fund

  The Company established a provident fund under the name of "Employee
  of PTTEP Registered Provident Fund".

  The provident fund is funded by payments from employees and by the
  Company which are held in a separate trustee-administered fund. The
  Company contributes to the fund at a rate of 15 % of its employees’
  salaries which are charged to the income statement in the period to
  which the contributions relate.

21) Earnings per Share

  Basic earnings per share is calculated by dividing the net profit
  attributable to shareholders by the weighted average number of outside
  ordinary shares in issue during the year.

For the diluted earnings per share the weighted average number of
outside ordinary shares in issue is adjusted to assume conversion of all
dilutive potential ordinary shares. The Company has one category of
dilutive potential ordinary shares: share options.

22) Deferred Income under Take-or-Pay Agreements

    The Group has certain obligations in respect of the supply of gas
    under gas purchase agreements with its customer. Under these
    agreements customer is required to pay for certain minimum
    quantities of gas in a given year. Should customer be unable to take
    the minimum contracted quantities in a given year, certain volumes
    of gas that the customer has paid for but has not taken in that year
    can take for free of charge in subsequent years subject to certain
    conditions in the agreements. The Group recognizes its obligations
    under Take-or-Pay agreements on an accrual basis based on its best
    estimate of volumes taken in the year. Received in advance under
    these agreements are recognized as deferred income. The deferred
    income, when subsequently taken, is recognized in the income
    statement.

    The Group made prepayment for royalty related to cash received in
    advance under Take or Payment agreement to government of Myanmar.
    Prepayment will be amortized when the deferred income is recognized.

  14.1.4 Bonds issuing Liabilities

  1) The Company issued 2,500,000 unsecured unsubordinated bonds with a
  face value of Baht 1,000 each, totaling Baht 2,500 million. The bonds
  bear interest at a rate of 4.625% per annum, payable every six months
  on March 27 and September 27 of each year, and have a maturity period
  of 15 years, to be redeemed on March 27, 2018.

  2) PTTEPI issued 200,000 unsubordinated bonds with a face value of USD
  1,000 each, totaling USD 200 million, guaranteed by the Company. The
  bonds bear interest at a rate of 7.625% per annum, payable every six
  months on April 1 and October 1 of each year, and have a maturity
  period of 10 years, to be redeemed on October 1, 2006.

  3) The Company issued 230 unsecured unsubordinated bonds with a face
  value of Yen 100 million each, totaling Yen 23 billion. The bonds bear
  interest at a rate of 3.35% per annum and have a redemption period of
  10 years, to be redeemed on September 19, 2007. On the date of the
  bond issuance, the Company entered into a swap agreement with a
  foreign bank to swap Yen for USD 193.28 million. Under this agreement,
  interest is charged at the rate of 7.86% per annum, payable every six
  months on March 19 and September 19 of each year.

2.  Summary PTTEP and its subsidiaries Financial Statements

[]

[]

Change in Accounting Policy

The Group recorded a provision of decommissioning costs for the year
2003. A provision is recognized, and are provided at the onset of
production of the project, for the estimate of the eventual costs that
relate to the removal of the production facilities. These costs were
included as part of the oil and gas properties and were amortized based
on proved reserves on a unit of production basis. The Company restated
the financial statements for the year 2002, presented herein for
comparative purposes, as though the provisions were originally in
compliance with this new accounting policy. The Group has not restated
the financial statement for the period prior to the year 2002 due to
limitation on evaluation of the proper past obligations

[]

[]

[]

[]

[]

3.  Summary significant financial ratio table

  --------------- ---------------------------------- --------- -------- -------- --------
                                                               2001     2002     2003

  Liquidity Ratio                                                                 

                  Current Ratio                      (times)   1.38     2.01     2.94

                  Quick Ratio                        (times)   1.28     1.88     2.76

                  Cash flow from Operations to       (times)   1.67     1.28     1.65
                  current liabilities                                            

                  Account Receivable Turnover        (times)   8.63     8.75     9.62

                  Collection Period                  (days)    41.72    41.14    37.43

  Profitability                                                                   
  Ratio                                                                          

                  Profit Margin                      (%)       37.20    37.94    32.50

                  Return on Equity ( ROE )           (%)       40.80    34.65    28.59

  Efficiency                                                                      
  Ratio                                                                          

                  Return on Assets (ROA)             (%)       15.38    14.87    13.59

                  Return on Fixed Assets             (%)       33.32    35.71    34.00

                  Assets Turnover                    (times)   0.41     0.39     0.42

  Financial                                                                       
  Policy Ratio                                                                   

                  Debt to Equity                     (times)   1.50     1.19     1.03

                  Times Interest Earned              (times)   15.33    16.21    18.11

                  Times Burden Covered               (times)   0.60     0.46     0.51

                  Dividend Ratio                     (%)       35.91    36.51    36.61

  Data Per Share                                                                  

                  Book value per share               (Baht)    47.72    58.98    70.01

                  Net Profit per share               (Baht)    16.71    18.49    18.44

                  Dividend per share                 (Baht)    6.00     6.75     6.75

  Growth Rate                                                                     

                  Total Assets                       (%)       21.49    8.57     9.70

                  Total Liabilities                  (%)       11.83    (1.46)   2.10

                  Sales                              (%)       27.88    7.52     15.04

                  Net Profit                         (%)       109.46   10.64    (0.21)
  --------------- ---------------------------------- --------- -------- -------- --------

14.4 Management’s Discussion and Analysis on Operating Results for Year
2003

14.4.1 PTTEP Performance

  In 2003, PTTEP was successful in implementing its strategic plans,
  notable aspects of which are summarized here:

2.1.1 Several significant investment expansions, both domestic and
overseas, were implemented in line with corporate strategy. The key
investment events in 2003 are detailed below:

-   PTTEP was awarded concession blocks from the 18^(th) Petroleum
    Concession Bidding Round; namely, PTTEP is now the exclusive
    concessionaire and operator for concession block G9/43 and a joint
    venture partner in concession blocks G4/43 and L22/43.

-   PTTEP increased its participation interest from 14.1667% to 19.3178%
    in the Yetagun Project.

-   PTTEP became a joint venture partner, with a 35% participation
    interest, in partnership with Petrovietnam Investment & Development
    Company (PIDC) in onshore petroleum blocks 433a & 416b, with high
    potential petroleum reserves, in the south east of Algeria.

-   PTTEP was awarded the concessionaire and the operatorship for the
    whole of offshore concession blocks M7&M9 in Myanmar.

-   PTTEP and joint venture partners (the sellers) signed a Heads of
    Agreement (HOA) with PTT Public Company (PTT) (the buyer) in
    November 2003 for Arthit Project. Furthermore, the Gas Sales
    Agreement (GSA) was signed in January 2004. These events clearly
    confirm the gas market for Arthit Project development as well as
    securing long term gas reserves supply for the Nation’s future.

-   PTTEP and its subsidiary executed a share purchase agreement to buy
    all issued shares of capital for Thai Shell Exploration and
    Production, Co., Ltd. or Thai Shell. Thai Shell holds a 75% stake in
    the onshore S1 concession (currently producing crude oil at
    approximately 19,000 barrels per day, 50 million cubic feet per day
    of natural gas, and 300 tons per day of liquefied petroleum gas
    (LPG)), and a 100% stake in offshore concession B6/27 (currently
    production is temporarily suspended), as well as the operatorship
    rights for these two blocks. The acquisition cost was approximately
    USD 205 million, and PTTEP expected to complete this transaction in
    January 2004, using its working capital to fund the acquisition.
    Moreover, the agreement signing included the transfer of concession
    rights for onshore petroleum block L22/43 from Thai Shell Co., Ltd..
    By purchasing Thai Shell, PTTEP not only extends its capability as
    an operator of the largest onshore oil field of Thailand, but also
    immediately locks in sales revenue from this field. PTTEP’s oil
    production and oil reserves will also increase impressively. In
    addition, the skilled and experienced staff from Thai Shell will
    strengthen PTTEP capability to compete in the petroleum exploration
    and production business. From this acquisition, PTTEP has forecasted
    a boost in its sales volume to 129,000 barrel per day in 2004 versus
    107,000 barrel per day in 2003.

  2.1.2 On 3 October 2003, the PTTEP Board of Directors at the meeting
  no. 10/2546/214 appointed Mr. Maroot Mrigadat, Senior Vice President
  of Business Development Division, as the Company’s new President,
  succeeding
  Dr. Chitrapongse Kwangsukstith, who will become Senior Executive Vice
  President, Gas Business Group at PTT Public Company Limited, effective
  October 6, 2003. PTTEP policy and direction, however, are expected to
  remain the same.

  PTTEP had a sales volume target in 2003 of 107,796 BPD (excluding
  petroleum sales from Medco). The actual sales volume turned out to be
  107,299 BPD, a 5% increase from the previous year but slightly lower
  than its target. The reason for higher sales volume this year versus
  last year resulted from sales volume increases in the Pailin and
  Yetagun projects, and the reasons for being lower than targeted was
  because of the reduction in the Production Sharing Contract (PSC) in
  the Yadana project and the lower sales volume of Bongkot project,
  owing to quality concerns in the first half of the year. However, a
  recovery soon followed in the second half of the year after a
  successful collaborative resolution with PTT.

  2.1.3 The 2003 performance yielded a Return on Capital Employed (ROCE)
  of 21.53% which was higher than the target of 19-20%. Regarding the
  long term Debt-to-Equity ratio, the PTTEP ratio was at 0.5 time, lower
  than the targeted limit of 1.0 time.

2.1.4 For projects in which PTTEP is the Operator, the Company aims to become an Operator, proud of its Operational Excellence, along with a keen awareness of Health, Safety and Environment (HSE) issues. Of note, PTTEP was awarded International Environment Management System certification or ISO 14001 for its operational areas, which are the PTTEP1 Project, PTTEP Office Building, the Bongkot field and the Songkhla Logistics Base. 

Concurrently, Organization and Human Resource Development initiatives have also progressed; PTTEP has focused on adopting international best practices and world class-competitiveness in order to support its future growth. In this matter, we have applied Good Corporate Governance and developed an Internal Control System, including Risk Management, to ensure for implementation of our plan. The company had also incorporated Learning Organization and Knowledge Management approaches to guarantee continued organizational development.

  14.4.2 Results of operations

  On March 27, 2003, PTTEP issued and sold 2,500,000 units of unsecured
  and unsubordinated debentures of Baht 1,000 each, totaling Baht 2,500
  million. The debentures carry an interest rate of 4.625% per annum,
  which are payable every six months on March 27 and September 27 of
  each year. The debentures have a tenor of 15 years, and will be
  redeemed on March 27, 2018. DBS Thai Danu Bank Public Company Limited
  is the registrar of the debentures. The debentures issuance provides a
  long term financing for PTTEP at a low cost.

  On April 24, 2003, PTTEP 2003 General Shareholders’ Meeting approved
  the issuance and the offering of 2 million units of warrants to
  purchase the Company’s common shares for management and employees of
  the Company for the year 2003 (Exercise Ratio : 1 unit of warrant per
  1 unit of common share) at the exercise price of Baht 117.

  On May 9, 2003, PTTEP paid dividends to its shareholders at Baht 6.75
  per share, in compliance with the resolution of the 2003 PTTEP General
  Shareholders’ Meeting on April 24, 2003.

  On November 10, 2003, PTTEP repaid the USD 50 million loan, with the
  interest of USD 13.60 million, to Union Oil Company of California and
  Moeco Thailand Co., Ltd. The loan, which carried an interest rate of
  Libor + 0.75% per annum, was executed in 1998.

  In the first quarter of 2003, PTTEP and subsidiaries commenced
  recording a provision for decommissioning costs. A provision is
  recognized, and is provided at the onset of production of the project,
  for the best estimate of the eventual costs that relate to the removal
  of the production facilities. These costs were included as part of the
  asset decommissioning costs and were amortized based on proved
  reserves on a unit of production basis. The estimates of
  decommissioning costs have been determined based on reviews and
  estimates by the Group’s own engineers and managerial judgment. The
  effect of this change is reflected in the prior year’s beginning
  balance of retained earnings and restatement of the previous year’s
  financial statements. PTTEP and subsidiaries recorded this adjustment
  by decreasing the year 2002’s beginning balance of retained earnings
  by Baht 468 million and decreasing the year 2002’s net profit by Baht
  35 million. Total adjustment decreased the year 2003’s beginning
  balance of retained earnings by Baht 503 million.

  For the full-year 2003 results, PTTEP and subsidiaries’ net profit was
  Baht 12,028 million or Baht 18.44 per share, decreasing of Baht 26
  million, when compared with the last year’s net profit of Baht 12,054
  million or Baht 18.49 per share. PTTEP and subsidiaries had a ratio of
  return on shareholders’ equity for this year at 28.59%.

  The total revenues of PTTEP and subsidiaries in 2003 amounted to Baht
  37,014 million, increasing Baht 5,240 million or 16%, when compared
  with Baht 31,774 million in 2002. This increase was mainly due to an
  increase in sales of Baht 4,451 million or 15%, resulting from the
  average petroleum price in 2003 increasing to USD 20.62 per BOE when
  compared with USD 18.59 per BOE in 2002, and the higher sales volumes
  in 2003 at 107,299 BOED compared with 101,736 BOED in 2002. Increased
  sales volumes derived mainly from the higher sales volumes of natural
  gas from the Pailin and Yetagun projects and the higher sales volume
  of condensate from the Pailin project, while the decreased sales
  volume was caused mainly by the sales volumes of natural gas in the
  Bongkot project, and the decrease in portion of production sharing in
  the Yadana project.

  Revenue from pipeline transportation, which was proportionately
  recorded from gas pipeline transportation that MGTC and TPC rendered
  to Myanma Oil and Gas Enterprise (MOGE), increased Baht 444 million.
  Such increase derived from the increase in the gas pipeline
  transportation price and the increase in TPC’s gas pipeline
  transportation relevant to the increased MOGE gas sales volume.

  PTTEP and subsidiaries realized their share of net profits from
  associated companies in 2003 at Baht 750 million, consisting of
  operation results from Medco Energi through New Links of Baht 480
  million, and from Thai Oil Power Co., Ltd., of Baht 270 million.

  PTTEP and subsidiaries had a foreign exchange gain in 2003 as a result
  of the stronger Baht.

  PTTEP and subsidiaries incurred expenses in 2003 of Baht 15,613
  million, an increase of Baht 2,704 million or 21%, when compared with
  Baht 12,909 million in 2002. This increase was mainly due to (1) the
  higher exploration expenses from the write-off of dry wells, including
  the costs carried for PetroVietnam in the Block 9-2 and Block 16-1
  projects, and the geological and geophysical studies in the Block 44,
  (2) the higher depreciation related to an increase in production
  volumes and completed oil and gas properties and, (3) the higher
  royalties related to an increase in sales revenue.

  PTTEP and subsidiaries had an increased income tax expenses in 2003 of
  Baht 2,566 million. The increase was mainly due to (1) an increased
  earnings before income taxes and, (2) a decreased utilization of tax
  losses carry forward and payment of Myanmar income tax since May 2003
  in Yetagun project & TPC because of the end of the tax holiday period.

14.4.3 Financial position

  As of December 31, 2003, PTTEP and subsidiaries had total assets
  amounting to Baht 92,576 million, which was Baht 8,183 million higher
  than the end of 2002. This increase was mainly due to (1) an increase
  in cash and cash equivalents and short-term investments of Baht 5,153
  million resulting from a higher net cash flow from operations and
  issuance of debentures, (2) an increase in oil and gas properties and
  gas pipelines of Baht 3,133 million resulting from an additional
  investment of 5.1511% participation interest in the Yetagun project
  and an investment in the TPC’s gas pipeline and (3) a decrease in
  other non-current assets, Baht 745 million, mainly from the write-off
  of the costs carried for PetroVietnam in the Block 9-2 and Block 16-1
  projects to exploration expenses relevant to the write-off of dry
  wells during the period.

  On September 12, 2003, PTTEP International Limited (PTTEPI) and PTTEP
  Offshore Investment Company Limited (PTTEPO), which have a 14.1667%
  participation interest in the Yetagun Project and the TPC’s Gas
  Pipeline respectively, and the other joint venture partners exercised
  their right to purchase all the shares owned by Premier Petroleum
  Myanmar Limited (PPML) in the Yetagun Project and the TPC’s Gas
  Pipeline. Consequently, PTTEPI and PTTEPO acquired an additional
  5.1511% participation interest, resulting in an increased stake from
  14.1667% to 19.3178%. PTTEPI and PTTEPO acquired the above
  participation interest with the excess of the cost of an acquisition
  over the fair value of net assets in proportion to the interest held
  by the Company. Such difference amounted to Baht 1,277 million (Net
  book value was Baht 1,855 million).

  PTTEP received dividends from New Links and Thai Oil Power Co. ,Ltd.,
  in 2003 amounting to Baht 625 million and Baht 58 million,
  respectively. These dividends are recorded in the investment accounted
  for under equity method.

  Most of the current assets of PTTEP and subsidiaries as of December
  31, 2003 were in cash and cash equivalents, short-term investments,
  parent company receivables, and accounts receivables. A large
  proportion of the non-current assets were (1) assets used in
  joint-venture exploration and production, presented under the title of
  property, plant, and equipment, and (2) investments in associated
  companies, New Links and Thai Oil Power Co., Ltd., presented under the
  title of investment accounted for under equity method.

  PTTEP and subsidiaries had total liabilities of Baht 46,902 million,
  which was Baht 964 million higher than the end of 2002. This was
  mainly due to the net effect of (1) the issuance of unsecured and
  unsubordinated debentures of Baht 2,500 million and, (2) repayment of
  the USD 50 million loan in November 2003 with the interest of USD
  13.60 million.

  Regarding the 2 million units of warrants issued by PTTEP on August 1,
  2002, there were allocated to PTTEP directors, managements and
  employees, the warrants are exercisable on the last working day of
  every three months starting from the first exercise date on July 31,
  2003 at the exercised price of Baht 111 per share. As of December 31,
  2003, the total number of shares exercised was 398,000 shares and the
  outstanding number of warrants was 1,602,000 units.

  On November 12, 2003, PTTEP registered a change in paid-up capital to
  Baht 3,261,990,000 for the issued and paid-up of 652,398,000 ordinary
  shares.

  In 2003, PTTEP and subsidiaries had a net cash flow from operations
  which amounted to Baht 16,179 million. Most of this was cash received
  from operating activities. PTTEP and subsidiaries had a net cash flow
  used in investment activities which amounted to Baht 9,142 million.
  Most of this consisted of investment in additional capitalized assets
  used in exploration and production activities in the Pailin and
  Bongkot projects, including the 5.1511% additional investment in the
  Yetagun project and the TPC’s gas pipeline. PTTEP and subsidiaries had
  a net cash flow used in financing activities which amounted to Baht
  4,018 million from (1) the dividend payment amounting to Baht 4,400
  million, (2) repayment of the USD 50 million loan in November 2003,
  (3) cash received from the issuance of unsecured and unsubordinated
  debenture amounting to Baht 2,500 million and, (4) cash received from
  the issuance of ordinary shares for the exercised warrants, as noted
  above. As of December 31, 2003, PTTEP and subsidiaries had cash and
  cash equivalents of Baht 19,063 million, an increase of Baht 2,757
  million from the end of 2002.

  Regarding protection against potential risks which may affect its
  projects, PTTEP purchased insurance coverage by considering all types
  of perils and appropriate sums-insured related to each project. For
  2003, the premiums on these policies remained high relative to those
  of the year 2002. However, the Company continued to purchase
  sufficient insurance coverage as it has done in the past.

As of December 31, 2003, PTTEP’s credit ratings were as follows;

  • Baa1 for its Long-term foreign currency rating by Moody’s Investors

  Service

• BBB for its Long-term foreign currency rating, and BBB+ for its

Long-term local currency rating by Standard and Poor’s Ratings

Services

• BBB+ by Japan Credit Rating Agency, Limited

• AA+ by TRIS Rating Company Limited

4.  Impacts on Operational Results

  In 2003, the Thai government and Ministry of Energy (MOEN) supported a
  clear vision for the country’s energy strategy by issuing positive
  policies to strongly support effective energy exploration and
  production in various resource arenas. These policies have helped the
  deployment of an effective framework for Thailand’s energy development
  direction. For instance, current policies are improving governmental
  mechanisms to motivate private parties to increase investment in
  petroleum exploration and production development projects in Thailand
  and overlapping areas, while also expediting successful cooperation
  among ASEAN countries to institute energy grid networks that will
  upgrade regional gas pipeline transportation and electricity supply
  networks. Such efforts highlight Thailand in the role of a regional
  leader in addition to promoting Thailand as a regional energy hub in
  South East Asia. Moreover, the government has promoted PTTEP’s role as
  a national strategic arm in securing petroleum reserves for the
  country, especially in relation to international cooperation required
  with other countries and their overseas investments.

  All the significant events above are noteworthy indicators of thriving
  commercial energy development projects drawn from various resources in
  Thailand. Additionally, PTTEP expects to be awarded 2 domestic
  exploration concessions, onshore blocks L53/43 and L54/43, next to the
  PTTEP1 project, with both blocks reputed to have excellent potential
  for oil reserve development.

  PTTEP has planned to start producing natural gas from the Arthit field
  by mid 2006 at a rate of 330 million cubic feet per day to serve the
  increasing demand for natural gas. The company has already initiated
  preparations for project development to meet the scheduled plan. For
  this project, PTTEP has again targeted operational excellence in all
  its activities, including project management, technical support,
  organization development, manpower allocation, capital mobilization
  and cost reduction.

  Other factors, which may affect the company performance both in short
  and long term including fluctuation of oil price, revision of gas
  sales agreement, foreign exchange, are also elaborated in the section
  of Risk Factors to be disclosed in Report 56-1 and 2003 Corporate
  Annual report.